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March 8, 2020

NextEra Appeals Court Decision on Texas ROFR Law

By Tom Kleckner

NextEra Energy subsidiaries last week appealed a federal court ruling that upheld a Texas law giving incumbent transmission companies the right of first refusal to build new power lines.

The companies asked for expedited treatment to prevent “irreparable harm.”

NextEra Energy Capital Holdings and four other NextEra transmission owner/developer entities took their case to the 5th U.S. Circuit Court of Appeals in New Orleans (20-50160) after the U.S. District Court for the Western District of Texas last month refused to overturn Texas Senate Bill 1938. (See District Court Dismisses Texas ROFR Repeal.)

The law essentially allows only incumbent transmission companies to build new power lines in Texas by granting regulatory certificates of convenience and necessity to the owners of the endpoints of a new transmission line.

The NextEra units said the Feb. 26 ruling means NextEra Energy Transmission (NEET) Midwest could lose its “lawfully won right” to build the $115 million Hartburg-Sabine transmission project in MISO’s East Texas footprint. NEET Midwest won the project’s rights in 2018 through a competitive bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

NextEra Texas ROFR — The 5th U.S. Circuit Court of Appeals grounds in New Orleans | *5th U.S. Circuit Court of Appeals*

“Accordingly, without expedited decision on the merits from this court, NextEra will be imminently and irreversibly deprived of its lawfully won right to build and operate a major transmission project,” NextEra said in its appeal.

NextEra’s filing on Friday said the company recently learned that MISO is using its established variance analysis process to study the project and developments around it. The RTO uses the analysis to study projects already approved under its Transmission Expansion Plan that are later disrupted by circumstances that affect the project’s cost, schedule or “the ability of selected developers and transmission owners to complete.”

NextEra said MISO indicated it anticipates a decision reassigning or canceling the project by March 31. MISO would then seek FERC approval of the change, with the commission ruling by June, NextEra said.

MISO told RTO Insider that it continues to plan for the project but wouldn’t say under which developer it will proceed. Should the project revert to the incumbent, it would become Entergy’s responsibility.

Spokesperson Allison Bermudez said in an email that MISO is aware of the recent court action, but confidentiality restrictions limit its ability to talk publicly about the project. Bermudez said MISO will make a further statement once the RTO completes the variance analysis.

NextEra did not respond to a request for comment.

The legislation also affects NEET Southwest’s application with the Public Utility Commission of Texas to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s region of East Texas.

NextEra said SB 1938 violates the U.S. Constitution’s dormant Commerce Clause because it allows only the incumbent Texas owners of the end points to build, own and operate new lines. Should the incumbent decline to build the line, it can assign the right only to another Texas entity, NextEra said.

“In effect, Texas has closed its borders to new out-of-state companies from doing this type of business in the state,” NextEra said.

The company also asserted that the law violates the Constitution’s Contracts Clause “because it abridges the ‘existing contractual relationship’” for the Hartburg-Sabine project. It cited the Department of Justice’s “statement of interest” filed last year in NextEra’s appeal of SB 1938 that said the law placed Texas’ deregulated retail electric market “at risk.” (See DOJ Weighs in on Texas ROFR Lawsuit.)

The NextEra companies on March 2 also filed an injunction with the district court asking that its proposed transmission projects be shielded from the new law while they appeal to the 5th Circuit.

“In opposing the preliminary injunction, Texas identified only an amorphous threat to its sovereignty that might result from an injunction,” NextEra said. “An injunction pending appeal will temporarily prevent the imminent, irreversible loss of a $100 million-plus project for NextEra while the 5th Circuit considers the substantial constitutional issues presented here.”

March 8, 2020

ISO-NE Study to Chart Transition to Future Grid

By Rich Heidorn Jr.

ISO-NE and New England Power Pool stakeholders are collaborating to study market and reliability issues the region will face as it seeks to decarbonize power, transportation and heating over the next three decades.

NEPOOL members discussed the outlines of the study — which was prompted by requests last year from the New England States Committee on Electricity (NESCOE), New England Power Generators Association (NEPGA) and other stakeholders — at the Participants Committee meeting Thursday.

ISO-NE Future Grid — ISO-NE CEO Gordon van Welie | © *RTO Insider*

“People are generally very supportive of doing a study,” ISO-NE CEO Gordon van Welie said Friday at a news briefing on the RTO’s 2020 Regional Electricity Outlook, which noted states’ “goals to achieve up to 100% renewable resources” and asked “How do we get there from here?”

“I think the general consensus in the room … is it’s a good thing to go off and study the future power system because that’s going to give us a lot of information to then inform the other discussions that people want to have, which is the market design conversation, and ultimately transmission,” added van Welie, who said electrification will transition the region from a summer- to a winter-peaking electric system.

“There was less clarity around what the scope and objective of the study should be. The discussion yesterday was mostly about process and not scope. And that conversation [about scope] will be coming in due course in the next month or two.”

Work on the study will begin in earnest after the RTO’s NEPOOL Markets Committee Briefs: Feb. 11-13, 2020.)

The PC meeting materials included a graphic depicting the study as four bubbles: the objective (assessing the power system needed to meet state energy and environmental policies); study process (identify the resource mix and operational and reliability needs); a gap analysis (to determine whether the current markets plus ESI provide resources and ISO-NE what they need to continue reliable operations); and a discussion of potential market approaches to address any gaps.

Van Welie said that the study’s time frame will be the subject of future stakeholder discussions, but that he expects it to be longer than the next 10 years, when he said electric demand from decarbonization of transportation and heating is projected to increase only slightly.

“When I look at that and the long-term decarbonization goals in the region, I think there will be a hockey stick [rise in demand]. We’re going to have to accelerate — dramatically accelerate — decarbonization of the other sectors, so there will be a steep growth in electric demand over that period,” he said. “It’s important, if we’re going to study the future, that we study that hockey stick because there’s nothing really interesting to study in the next 10 years. The demand’s pretty flat.”

A Brattle Group study released in September predicted that meeting the states’ goals for reducing greenhouse gas emissions by 80% by 2050 will result in a doubling of electricity demand, even with substantial energy efficiency gains.

“I don’t know that we should lock onto specific numbers and multiples at this time,” van Welie said. More important, he said, is how the system will add renewable capacity: through the markets that have served the region for the last two decades, or through long-term power purchase agreements, which would put investment risk back on consumers.

ISO-NE sought to develop a market-based path for renewables to supplant carbon-emitting resources through the substitution auction in the Competitive Auctions for Sponsored Policy Resources (CASPR) program, which allows resources nearing retirement to trade their capacity supply obligations with new state-sponsored resources that did not clear in the primary auction.

The RTO has held two auctions under CASPR. Vineyard Wind, a planned 800-MW offshore wind farm, took over a 54-MW obligation from a retiring resource in Forward Capacity Auction 13 last year. There were no trades this year in FCA 14.

“As we said when we filed CASPR, it’s intended to work over time,” said Anne George, the RTO’s vice president of external affairs and corporate communications. “We still feel like with only two auctions of experience, we need a little more time to see how CASPR works.”

“I think it’s going to take time for those economic pressures to build up” to persuade incumbent generators to retire, van Welie added. “So, we have been very clear about this: We think carbon pricing is a much better solution … which is why you hear us advocating for it.” (See ISO-NE: States Must Lead on Carbon Pricing.)

At a conference in D.C. last week, speakers expressed some doubts about carbon pricing, saying it won’t solve the climate crisis by itself or persuade states to abandon their own clean energy policies. (See related story, Carbon Pricing Gains Popularity — and Doubts.)

“I think it’s going to take time for people to get comfortable with [carbon pricing]. It may take a long time for us to get comfortable with it,” van Welie acknowledged. “Developers are going to be very cautious about trusting the regulatory system around carbon pricing until they see that it’s stable and has longevity.”

The Regional Greenhouse Gas Initiative, which includes all six New England states, “never produced a material carbon price in terms of driving the clean energy transition,” van Welie said. RGGI’s most recent auction in December cleared at only $5.61/ton.

Van Welie contrasted RGGI with Europe, where carbon emissions were trading last week at about 25 Euros/ton ($28), high enough that Royal Dutch Shell, BP and others are willing to build offshore wind on their own balance sheets without long-term PPAs, he said.

Transmission RFP

On an unrelated issue, van Welie said the RTO was “very pleased” with the response to its first-ever competitive transmission solicitation, which resulted in 36 project proposals by the March 4 deadline. (See ISO-NE Issues First Competitive Tx RFP.)

ISO-NE issued the solicitation in December to prepare the transmission system in the Boston area for the retirement of the Mystic Generating Station in Everett, Mass. The proposals will seek to address transmission facility overloads under peak load conditions, as well as system restoration concerns with the underground cable system. ISO-NE hopes to select the finalists for the work by the end of the year.

“We’ve got a lot of work ahead of us,” said van Welie, adding that the RTO will be releasing more details on the responses shortly.

New Member

In addition to its discussion on the futures study, the PC voted Thursday to admit trade group Advanced Energy Economy as a NEPOOL member. AEE, whose members provide energy efficiency, demand response, energy storage and natural gas, renewable and nuclear generation, was admitted as a Fuels Industry Participant.

Operating, Planning Procedure Revisions Approved

Members also approved revisions to the following operating and planning procedures:

OP-18 (Metering and Telemetering Criteria): adds a requirement to telemeter station frequency; identifies equipment requirements; specifies which requirements apply to existing and new equipment; and revises Section I (Purpose) to reflect current practice.
OP-23, Appendix I (Resource Auditing): clarifies the asset ID entry for certain reactive resources without an RTO-assigned asset ID.
OP-3 (Transmission Outage Scheduling): extends the maximum duration for an “opportunity outage” from 96 hours to 108 hours. An opportunity outage is one that fails to satisfy the minimum advance notice time required for planned short-term transmission outage processing and is submitted for RTO approval as a result of an unexpected opportunity to accomplish work that would otherwise require another outage at a less opportune time.
PP-3 (Reliability Standards for the New England Area Pool Transmission Facilities): replaces the term “governance participant” with the terms “market participant” and/or “transmission owner.”

March 8, 2020

CapX2050 Calls for More Tx, Dispatchability in Midwest

By Amanda Durish Cook

The Upper Midwest needs more transmission, more technology and preservation of some dispatchable generation for the sake of reliability, the CapX2050 study concluded last week.

The 10 Minnesota utilities behind the effort drew three major takeaways from the study:

More transmission infrastructure will be necessary in the Upper Midwest to accommodate resource transition.
Non-dispatchable resources alone can’t meet all energy requirements, so some traditional power plants will still be necessary.
Real-time operational demands will become trickier to manage and will require new procedures.

Building on the CapX2020 transmission effort focused on 2020 reliability needs, the CapX2050 study addresses how the grid can handle widescale reductions in carbon emissions by 2050. (See Minnesota Utilities Reunite for CapX2050 Study.) Like the 2020 effort, the 2050 study concentrated on the transmission system that serves Minnesota, eastern South Dakota and North Dakota, western Wisconsin and the surrounding areas.

The study’s report said grid support in the form of ancillary services will be needed in areas where large, dispatchable generation is retired. New transmission technology and storage resources will be required to deliver ancillary services.

MISO CapX2050 — The Brookings County-to-Hampton project, part of CapX2020 | *CapX2020*

The group said its findings track with conclusions from MISO Renewable Study Shows More Tx, Tech Needed.)

“The variability of the output of non-dispatchable resources, even within a single day, could lead to several thousands of [megawatts] being transferred across the transmission system, with reversals in direction of flow occurring in an equal but opposite magnitude during the same day,” the report warned. “Operating techniques, transmission infrastructure and analysis tools will need to become more sophisticated to more accurately identify and adjust in real-time to deal with these changes.”

The utilities said that simply adding more non-dispatchable resources cannot solve the problem of sometimes deficient energy supply.

“Abrupt changes in weather, including prolonged extreme weather conditions, sudden changes in consumer demand, or disturbances on the transmission system (i.e., outages) will increasingly challenge the ability of the electric grid to provide a continuous supply of energy as more non-dispatchable resources are added,” the report said. It added that maintaining some dispatchable resources and adding energy storage can keep the transmission system reliable.

In what should be déjà vu for MISO planners, the CapX2050 report also called for a “long-term comprehensive regional transmission plan.” The Organization of MISO States has been pressing the RTO for two years to develop a long-term transmission package to accommodate growth of policy-driven generation resources. (See MISO Cracks Door on Long-term Tx Planning.) The report reminded MISO that “transmission expansion has been shown to be cost-effective when considered as part of a larger market.”

At this point, the CapX2050 utilities aren’t calling for any specific transmission projects. CapX2020 culminated in an 800-mile, grid expansion in the Upper Midwest, including four 345-kV transmission lines in Minnesota, North Dakota, South Dakota and Wisconsin and a 230-kV line in northern Minnesota.

Great River Energy spokesperson Jenny Mattson said that while future studies under CapX2050 aren’t being ruled out, none are planned so far.

“Though there is no time frame for additional studies, we’ll continue to evaluate the system in partnership with other utilities and stakeholders, including legislators, regulators, communities and MISO,” Mattson said in an email to RTO Insider.

The utilities also said they’re “ready to engage with public and stakeholders” on planning for new transmission.

March 8, 2020

MISO Foresees ‘Typical’ Spring

By Amanda Durish Cook

CARMEL, Ind. — MISO expects to have enough reserves on hand throughout spring to meet expected demand.

The RTO predicts spring energy usage will peak at 100 GW in May, with about 134 GW of total projected capacity available to meet load. MISO’s spring peak record of 107 GW occurred May 29, 2018.

“The 2020 spring is projected to be a very typical spring,” Senior Manager of Resource Adequacy Coordination Lynn Hecker told the Market Subcommittee on Thursday.

The National Oceanic and Atmospheric Administration forecasts above-normal spring temperatures for areas within MISO South, with the rest of the footprint at normal levels.

As with most of MISO’s preseason assessments, Hecker said high load coupled with high generation outages could have the RTO calling up load-modifying resources and operating reserves.

MISO spring — Spring load and capacity projections | *MISO*

Following its usual practice, MISO is preparing for higher generation outages on peak during spring. Potential reliability risks are most pronounced in April — when outages can historically near 45 GW — even though load is roughly 10 to 16 GW lower than in March or May.

“We are expecting to maybe dip into load-modifying resources in the 90/10 forecast,” Hecker said. That forecast represents a scenario in which there is a 90% chance of actual load being lower than predicted and a 10% chance of load being higher.

In the most likely 50/50 load scenario with a normal capacity supply, MISO won’t have to call on reserves in either March, April or May. However, if load is unusually high, the RTO runs the risk of entering emergency operating procedures.

The spring supply picture gets more dire if high-load scenarios pair with higher-than-expected generation outages, especially in April, a favorite month for scheduled maintenance. MISO said that April contains the only risk of the RTO burning through all of its operating reserves and LMRs and still coming up about half a gigawatt short.

March 6, 2020

NERC OC, PC and CIPC Briefs: March 3-4, 2020

ATLANTA — NERC’s Operating, Planning and Critical Infrastructure Planning committees gathered this week for their last face-to-face meetings before turning their functions over to the new Reliability and Security Technical Committee (RSTC) in June.

PC Discusses Distributed Energy White Paper

In an unusual move, the Planning Committee opened up the floor to discuss at length a draft white paper proposing to incorporate distributed energy resources such as rooftop solar panels and batteries into reliability standard TPL-001. Chair Brian Evans-Mongeon, of Utility Services Inc., said the paper initially went through the standard review process, but because of the wide-ranging implications for system planners, the leadership decided the full committee should provide comments.

“The PC doesn’t necessarily have a lot of times where they discuss topics. A lot of times we get the presentation, we ask a couple of questions and we react,” he said. “We thought that … there ought to be a little more go-around [and] discussion among PC members, observers and staff who are involved in this information.”

Committee members spent most of the discussion debating the extent to which DERs can be accounted for in system planning, a topic of growing concern for NERC. In a meeting of the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group earlier this year, Thomas Bialek of San Diego Gas & Electric warned that planners lack transparency into the energy generated by DERs, which can lead to greater risk from external disruptions. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)

NERC — Robert Reinmuller, Hydro One Networks | © *ERO Insider*

However, opinion was more divided on the wisdom of recommending changes to reliability standards, at least without gathering more information on the behavior of DERs in extreme scenarios.

“I’m really concerned about just putting it, without that detail, to a drafting team and seeing if we get lucky and they come out with something good,” said Carl Turner, engineering services director at Florida Municipal Power Agency. “Because I’ve seen drafting teams go both ways — we’ve had some that were really good, technically, and some that were not, and we got a giant mess of a standard.”

In response, Robert Reinmuller, director of transmission system planning at Hydro One Networks, pointed out that DER penetration is increasing no matter what regulators do, and that NERC may have to move with the times or be left behind.

“We have about 7,000 MW of [DER] behind the meter. … It’s coming, and it’s coming fast,” Reinmuller said. “I’m not certain that we need a standard today or tomorrow, but … we need to move toward that.”

Actions

The PC approved actions on the following reliability guidelines:

BPS perspectives for implementing IEEE 1547-2018;
Fuel assurance and fuel-related reliability risk analysis for the bulk power system; and
Distributed energy resource data collection for transmission planning (authorized posting for comment).

It also approved the following white papers:

Fast Frequency Response Fundamentals;
IRPTF Review of NERC Reliability Standards Applicability; and
Reliability Gaps in Reliability Standard PRC-019-2.

The Operating Committee also approved changes to the “Risks and Mitigations for Losing EMS Functions” reference document that are mainly intended to clarify vague and outdated language.

CIPC Receives GridEx Update

The GridEx Working Group plans to release its report on GridEx V by the end of March, according to Jake Schmitter, senior manager for training and exercises at NERC. Schmitter told the Critical Infrastructure Protection Committee that the group will release two versions of the report — TLP White and TLP Amber — that will both present the results of the exercise’s executive tabletop and the findings from the distributed play report. The Amber report will also include a list of participating organizations, as well as the scenario narrative.

Schmitter presented several highlights from the report, such as a geographical breakdown of participating organizations, an analysis of which participants played more realistic scenarios and the factors that allowed them to do so. He also discussed the future of the working group, which will become part of the Electricity Information Sharing and Analysis Center after the dissolution of the CIPC.

“Our [meetings] are still going to be attached to the RSTC meetings … because a lot of the RSTC members will more than likely be members of the GridEx Working Group,” Schmitter said, adding that the group is currently selecting new members and expects to finalize the roster by the end of May.

— Holden Mann

March 6, 2020

RSTC Tackles Organization Issues in First Meeting

By Holden Mann

ATLANTA — NERC’s new Reliability and Security Technical Committee (RSTC) held its first meeting Wednesday with a focus on introducing the body’s membership and laying the groundwork for beginning operations in June.

NERC’s Board of Trustees approved the creation of the RSTC last year, merging the Planning, Operating and Critical Infrastructure Protection committees, which have more than 120 members combined. (See NERC Board of Trustees Briefs: Feb. 6, 2020.)

NERC RSTC — The new RSTC met for the first time in Atlanta. | © *ERO Insider*

Focusing on Functions

For the initial meeting, RSTC Chair Greg Ford of Georgia System Operations and Vice Chair David Zwergel of MISO left most of the committee’s ostensible business to the three retiring committees, which concluded their final full meetings the same day (though they will meet briefly in June to finish handing over their work to the RSTC). Instead, the gathering featured briefings from the heads of the old committees on their existing structures and their ongoing work, followed by a discussion on how to consolidate their functions in the new organization.

Answering a question posed by numerous participants at previous meetings, Ford and Zwergel confirmed that the retiring committees’ existing subgroups will continue their ongoing projects with their current membership in the short term, reporting to the RSTC. Over the longer term, the leaders shared their initial broad thoughts on how the committee’s project pipeline might work, with projects organized into three main workstreams — technical services and modeling, assessments and analysis, and security. However, they emphasized that final arrangements have not been worked out and that input from members and industry will shape the process going forward.

Members Step Forward

Committee members suggested a number of ideas, such as assigning an RSTC liaison for each subcommittee that would be responsible for communicating between it and the larger body. Another significant concern raised was the logistical challenges of shrinking down the existing structure. Brian Evans-Mongeon of Utility Services Inc., the outgoing CIPC chair and at-large member of the RSTC, suggested that the new committee consider extending its meetings to accommodate the workload — for instance, by adding a two-hour introductory session like the joint sessions currently held by the OC, PC and CIPC.

“Given the fact that we’re trying to fit the agenda of three groups into an eight-hour span, it seems to me that kind of pre-session could [still be] of value,” Evans-Mongeon said.

“A pre-session is always an option,” Ford agreed, adding that the executive committee will also consider holding online informational meetings each quarter prior to the full meeting, similar to NERC’s Member Representatives Committee. NERC Chief Engineer Mark Lauby said that this can also be a solution for those members whose organizations’ travel policies might not permit them to attend longer meetings.

Members of NERC leadership attending the meeting encouraged the new committee to build on the work of its predecessors, while looking for any areas for further streamlining.

“As I attended the meetings yesterday and this morning, it was a little melancholy, to a degree, to listen to the closing statements from the chairs of the OC, PC and CIPC,” board Vice Chair Kenneth DeFontes said. “But at the same time, I come into this room with a great deal of optimism. And as I sat through the meetings, I saw evidence … that suggested to me the concept … should be very successful, because we’re going to be able to accomplish the same work, but hopefully do it more efficiently and more effectively.”

March 6, 2020

MISO Forward Report Stresses Near-term Change

By Amanda Durish Cook

CARMEL, Ind. — A new report from MISO concludes that stakeholders will need to quickly adjust the RTO’s capacity construct and offer new market products to accommodate a resource mix in which renewables represent a majority.

The second annual Forward Report was framed from the perspective of MISO’s rapidly evolving utilities and what they will need from a grid operator in the near future. The report includes five hypothetical utility profiles based on integrated resource plans, interviews with stakeholders and investor presentations. MISO used the profiles to conclude it needs to change its capacity auction and resource accreditation, while developing new market products to incentivize a flexible supply.

“Utilities need MISO to act now to develop transitional and transformational solutions,” CEO John Bear wrote in the report’s introduction. “As customers continue to push for decarbonization goals, utilities are adopting significantly more diverse business models. Supply and demand of availability, flexibility and visibility will vary by utility. MISO’s ecosystem for exchange must accommodate this significantly increased degree of diversity and facilitate members to leverage that value.”

Bear said MISO utilities must “redefine what is needed” to manage risk on the grid.

The first Forward Report in 2019 concluded that market changes are necessary as the RTO footprint experiences demarginalization, decentralization and digitalization. (See New MISO Report Starting Point for Major Grid Change.)

“We have an imperative to act quickly,” MISO Executive Vice President of Market and Grid Strategy Richard Doying told the Resource Adequacy Subcommittee on Wednesday. He added that the Organization of MISO States and state regulators have said their utilities are weighing millions of dollars in investments and are wondering if the MISO market can accommodate their new resource portfolios.

Doying pointed to MISO’s 77-GW interconnection queue, now dominated by nearly 46 GW in solar generation projects.

“Not a lot of traditional resources; they’re new resources with operational characteristics that we aren’t used to,” Doying said of the queue makeup.

MISO predicts that by 2030 its generation mix will contain 32% renewables, 28% natural gas, 27% coal and 9% nuclear. In 2018, MISO’s generation mix was fueled by 47% coal, 27% natural gas, 15% nuclear and 8% renewables. Doying said the 2030 mix isn’t a MISO forecast but based on utilities’ announced plans.

“This is what all of your companies have said they’re doing. … This is not based on a bunch of assumptions,” he told stakeholders.

Sunset on the Planning Horizon

MISO said its footprint will soon contain “very diverse utilities that will rely on each other as neighbors in a shared resource pool in new ways.”

Customized Energy Solutions’ Ted Kuhn asked what role MISO sees itself playing: planner, or facilitator to the rapid change.

Doying said MISO will concentrate more on making sure it gathers more detailed and accurate information to share with its members making investment decisions.

The new report reiterated MISO’s now familiar prediction that its annual loss of load expectation process for estimating reliability needs will eventually be broken down by season to assess risks in all hours of the planning year.

“We count megawatts based on one thing: peak load. … If we only count megawatts based on the requirement we established, does that account for all reliability risks?” Doying asked rhetorically, referring to MISO’s current process of establishing accreditation and reserve margin requirements to serve load on the hottest summer day.

“I think a simple, summer-based loss-of-load expectation study doesn’t account for all risks. … It does a very good job, but it’s incomplete,” Doying said. “Is annual the right time frame to conduct that assessment, or should it be done seasonally?”

Doying said MISO is advancing on developing some sort of “sub-annual component” for its Planning Resource Auction. The RTO last year said a seasonal capacity auction would be beneficial though some stakeholders have pushed back on the idea. (See MISO Gives Tentative Nod to Seasonal Capacity Design.)

Kuhn said he was worried MISO was focusing too much on seasonal or monthly divisions of the planning horizon when an influx of solar generation will require an hourly analysis of risk.

“You can break the horizon down as much as you like; the sun doesn’t shine at night,” Kuhn said.

Doying also said MISO may create new market products that reward flexibility.

“We don’t have a proposal, but we do know that’s been done in other regions,” Doying said. “There are a lot of ramping needs when you get a lot of wind and solar on the system.”

He said MISO will re-evaluate its scarcity and emergency pricing in the coming months. Both items appear on the RTO’s Integrated Roadmap list of market improvements to undertake in 2020. MISO staff have said emergency pricing has generally been inefficiently low.

March 6, 2020

ERCOT Sees Summer Repeat: Record Peak, Tight Reserves

By Tom Kleckner

ERCOT’s first assessment of the summer season foresees a repeat of 2019 — record electric usage and tight reserves — but with additional capacity to help meet demand.

The Texas grid operator’s seasonal assessment of resource adequacy (SARA) projects a peak demand of 76.7 GW, almost 2 GW over the current record of 74.8 GW set last August. However, ERCOT expects to have 82.4 GW of total resource capacity on hand, a 3.5-GW increase over last summer’s available capacity.

ERCOT summer peak — Sign of the times: Wind blades await distribution near Corpus Christi, with offshore rigs docked behind them. | © *RTO Insider*

“We continue to expect the region to have adequate reserves to cover a range of system conditions,” Warren Lasher, ERCOT’s senior director of system planning, said during a media call Thursday.

The grid operator’s reserve margin remains at 10.6%, 2 percentage points higher than last summer’s 8.6% margin. (See ERCOT’s Reserve Margin Climbs to 10.6% in 2020.)

ERCOT said that, as in 2019, conditions could warrant the need to declare an energy emergency, but it noted that it and its market participants are taking steps to ensure system reliability can be maintained during tight conditions.

It has added 513 MW of additional capacity since December alone, including 348 MW of wind capacity. Solar energy accounts for 77 MW of capacity, and an 88-MW gas plant provides the only new addition of fossil generation.

Pointing to the vast amount of renewable energy in ERCOT’s generator interconnection queue (104.6 GW), John Hall, director of regulatory and legislative affairs for the Environmental Defense Fund, said renewable energy plays a critical role in “ensuring Texans have the power they need during the hot summer months ahead.”

“Texas’ competitive electricity market continues to lead the nation in providing clean, affordable and reliable power,” he said in a statement.

ERCOT also on Tuesday released its final SARA report for the spring season (March-May). The grid operator expects sufficient generation to meet a spring peak of 64.2 GW.

It will release the final summer SARA report and a revised Capacity, Demand and Reserves report in early May.

March 6, 2020

SPP Briefs: Week of March 2, 2020

An SPP committee charged with coordinating the RTO’s policy development and recommendations to integrate electric storage resources (ESRs) took its first steps Tuesday with a conference call.

During the call, Chair Holly Carias, of NextEra Energy Resources, reminded the Electric Storage Resource Steering Committee’s (ESRSC) members that they are not to decide policies, but to “ensure the appropriate working groups are assigned the right recommendations.” She said the committee would be responsible for providing guidance, resolving conflicts and monitoring the working groups’ progress.

The committee discussed 17 of the 32 issues in front of it — divided into technical, cost allocation and “other” — before running out of time. The ESRSC will regroup March 13 to finish the task.

The committee’s creation sprang out of a Strategic Planning Committee discussion in January and was spurred on by SPP Planning Approach to Battery Storage.)

SPP’s accelerating energy storage growth | *SPP*

It is composed of the chairs of the Markets and Operations Policy Committee (Carias) and several working groups, including Economic Studies (ITC Holdings’ Alan Myers), Market (American Electric Power’s Richard Ross), Operating Reliability (Evergy’s Allen Klassen), Regional Tariff (Nebraska Public Power District’s Robert Pick), Supply Adequacy (Golden Spread Electric Cooperative’s Natasha Henderson) and Transmission (Midwest Energy’s Nathan McNeil).

The Nebraska Power Review Board’s John Krajewski, chair of the Cost Allocation Working Group, will serve on the ESRSC as a liaison member for the Regional State Committee.

The ESRSC reports to the MOPC but will also report progress to the SPC. The committee has set a tentative timeline of January 2021.

Wanted: Industry Experts to Review Order 1000 Projects

SPP is accepting applications through March 15 for the latest pool of industry experts that might be chosen to serve on an independent panel reviewing the RTO’s competitive transmission construction proposals in 2020.

The Oversight Committee will recommend the pool members, with the Board of Directors voting on their approval later this year.

SPP creates this pool of individuals each year in response to FERC Order 1000. The panel of industry experts will review, rank and score proposals for c ompetitive transmission projects approved for construction.

SPP’s recently approved Transmission Expansion Plan includes two 345-kV projects that will be competitively bid: a $77 million, 60-mile line near Tulsa, Okla.; and a $152 million, 105-mile line and terminal equipment in Kansas and Missouri.

A similar panel in 2016 approved SPP’s only competitive project so far. However, that project was later canceled because of a drop in load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

— Tom Kleckner

March 5, 2020

Senate Dems Seek to Undo PJM, NYISO Rulings

By Rich Heidorn Jr.

WASHINGTON — U.S. Sen. Chris Van Hollen (D-Md.) said Wednesday that he and other Senate Democrats will seek to amend a bipartisan energy bill this week to undo FERC rulings on PJM’s minimum offer price rule (MOPR) and NYISO buyer-side market power mitigation (BSM).

Van Hollen told the American Council on Renewable Energy’s Policy Forum that the American Energy Innovation Act introduced by Sens. Lisa Murkowski (R-Alaska) and Joe Manchin (D-W.Va.), the top members of the Senate Energy and Natural Resources Committee, was an opportunity to reverse FERC’s Dec. 19 order expanding PJM’s MOPR. (See Murkowski, Manchin Offer Bipartisan Energy Bill.)

MOPR — U.S. Sen. Chris Van Hollen (D-Md.) | © *RTO Insider*

Speaking with reporters after his speech, Van Hollen said he, Senate Minority Leader Chuck Schumer (D-N.Y.) and Sen. Cory Booker (D-N.J.) will offer an amendment to reverse both the PJM order extending the MOPR to new state-subsidized resources and FERC’s Feb. 20 order narrowing the resources exempt from NYISO’s BSM rules in southeastern New York. The latter order requires the ISO to subject storage and demand response to a minimum offer floor in its capacity market. (See FERC Narrows NYISO Mitigation Exemptions.)

“We should get 51 votes,” said Van Hollen, who last month joined with colleagues in asking PJM CEO Manu Asthana to delay the next Base Residual Auction to give states time to react to FERC’s “rash decision.” (See PJM’s MOPR Quandary: Should States Stay or Should they Go?)

Murkowski said last week her 550-page bill, which incorporates some 50 bills previously approved by the Senate committee, “is our best chance to modernize our nation’s energy policies” since the 2007 Energy Independence and Security Act.

In addition to reauthorizing the Advanced Research Projects Agency – Energy (ARPA-E) through fiscal year 2025, the bill could provide new markets for coal and natural gas and add initiatives for carbon capture, ocean energy, next generation nuclear power and advanced vehicles. The legislation is being substituted for a geothermal bill previously introduced by Murkowski and Manchin (S.2657) with a Senate floor vote coming as soon as this week.

House Democrats also hope to put their imprint on the bill, Rep. Paul Tonko (D-N.Y.), a member of the Energy and Commerce Committee, told the ACORE forum.

Tonko said the bill is a step in the right direction but that the House of Representatives will seek to make “it even more robust” by seeking to amend it with an extension of the investment tax credit for wind and a standalone storage ITC.

The Senate voted 90-4 Wednesday to begin debate on the bill. Murkowski opened debate with comments on Title II, which includes cyber, grid and mineral security. She cited World Bank estimates that meeting the goals of the Paris Agreement would increase demand for battery storage minerals — lithium, cobalt and nickel — by 1,000%.

She said the bill “will help America become a leader in growing industries like battery and renewable manufacturing, along with the jobs and the economic growth that they represent. I think it also helps put the United States in the driver’s seat to prevent supply disruptions that could quickly derail our efforts to deploy renewables, energy storage, EVs and other technologies.”