Page 1071 – RTO Insider

July 24, 2020

CAISO Adopts Co-located Resources Plan

The CAISO Board of Governors unanimously adopted the first of two proposals Wednesday intended to allow co-located and hybrid resources, such as solar panels coupled with battery storage, to connect to the grid more seamlessly.

The proposals, part of the ISO’s hybrid resources initiative, were fast-tracked to speed the addition of storage at existing interconnection points. CAISO needs the new capacity to help head off a projected shortfall next summer caused by the retirement of aging natural gas plants and the inability of solar to meet evening peak demand without storage. (See CAISO Briefs Western EIM on Hybrid Resources.)

In response to the anticipated shortfall, the California Public Utilities Commission required load-serving entities under its jurisdiction to procure 3,300 MW of capacity by 2023. Some LSEs proposed integrating co-located resources into the market as soon as this fall, and CAISO moved quickly to adopt its co-located connection plan by the end of July to allow FERC 90 days to approve Tariff changes before the resources go live.

“There is an urgency around getting [policy to support] these co-located resources … because we start to see these resources coming on and interconnecting late this year,” Mark Rothleder, CAISO’s vice president for market policy and performance, told the board. “We need to get started with some minimum features around the point of interconnection … [and] we will continue to work on additional features that have been requested in future phases.”

The starting point includes new Tariff language governing resources that share a single point of interconnection but have separate resource IDs, allowing CAISO to dispatch them individually.

CAISO Resources Plan — | *174 Power Global*

CAISO executives decided to implement the co-located plan first because it involves more familiar procedures. The hybrid resources plan — allowing solar and storage to be dispatched as a single unit — could prove trickier, they said.

“The co-located model allows for the underlying resources to be modeled in a manner similar to existing resources today but requires the ISO market to manage a constraint at the point of interconnection to ensure that the combination of resources does not receive market instructions beyond the interconnection limit,” Rothleder wrote in his memo to the board.

The board will take up the hybrid resources plan this fall. CAISO needs additional time to develop a proposal that will let it deal with situations in which intermittent resources such as wind and solar are offline because of weather conditions, while the storage component keeps operating, Rothleder said.

“Enabling hybrid resources requires several new features for the resource operator to communicate to the ISO when portions of the generating facility are unavailable because of deviations in the variable output component of the hybrid resource,” he wrote.

The co-located resources plan is slated to take effect this fall. The hybrid resources component is scheduled to be brought before the board in November and implemented one year later.

Some stakeholders have expressed concern that CAISO is moving too fast to bring new storage online, but others have said the speed is warranted by the impending shortfall and the number of projects lined up.

CAISO’s interconnection queue contains about 24 GW of mixed-generation projects, including 20 GW of storage projects. Much of the storage is proposed for sites where solar arrays and wind farms already operate.

“Developers are adding storage to existing sites because adding resources at these locations can be done more quickly and at a lower cost than establishing new interconnections,” Rothleder said. “Lower costs are achieved due to the existing infrastructure, such as step-up transformer equipment that is already a part of the existing facility.”

In addition, he said, “siting at existing facilities takes less time to go through the ISO’s interconnection process because the capacity addition can be considered through the material-modification process, rather than the process of siting a new facility, which includes additional analysis and approvals.”

The integration of hybrid resources is expected to be a major issue for CAISO and other organized markets, as battery storage paired with renewables plays an ever greater role.

FERC held a technical conference Thursday to discuss the issue. (See FERC, RTOs Need to Set Hyb rid Rules, Experts Say and FERC Sets Tech Conference on Hybrid R esources.)

July 24, 2020

Consultant Tells MISO Microcities are Wave of the Future

If one business consultant’s vision proves correct, MISO stakeholders learned Tuesday, future neighborhoods will be self-contained developments with their own power sources.

Speaking at MISO’s July Informational Forum, Josh Hodge, CFO of Peoria, Ill.-based Dukes Business Consulting, said zero-carbon-footprint microcities independent of the grid are a possibility. He said the future could lead to vertical gardens on city blocks and parking garages with solar canopies and car-charging stations.

Hodge said microcities offer a sustainable model that can tackle the affordable housing crisis and cities’ “food deserts”: urban areas that lack easy access to fresh and nutritious food.

He said the developments would include hybrid, solar-and-storage resources. The net-zero electricity use could mean residents won’t have electricity bills.

“Massachusetts and California already require solar installations to be coupled with storage, and we expect to see this trend to spread,” Hodge said.

MISO microcities — EverForce Energy’s Magnetic Transducer Generator | *EverForce Energy*

EverForce Energy’s new Magnetic Transducer Generator stands to be a gamechanger for microcities, he said. Hodge said the technology can produce continuous energy without a fuel source, with one 5-MW generator providing uninterrupted, clean energy for roughly 1,000 homes for more than 20 years.

“And this is all with minimal maintenance and minimal impact on the environment,” he said.

Hodge said microcities can “supply and manage their own energy needs, and only connect to the grid to sell excess energy.”

“During emergencies, they could disconnect from the grid to protect themselves or the larger grid,” he said.

Hodge acknowledged microgrids will also cut the need for new generation and transmission and could draw customers away from utilities. While that may be bad news for utilities, he said some could make lemonade from lemons and embrace the increased reactive power and frequency and voltage regulation.

He also said new monitoring technologies on distribution systems could allow utilities to use microgrids’ stored supply when necessary.

July 24, 2020

MISO Members Make 1st Rules on Sectors

MISO’s Advisory Committee members this week adopted the first set of standards for creating and joining stakeholder sectors.

During a virtual meeting Wednesday, committee members adopted new rules that make MISO or its Board of Directors the mediator and final arbiter when a new entity is refused entry to a sector.

“This will effectively eliminate a sector’s ability to ‘veto’ an organization’s request to join that sector,” the AC said.

The rules also mean that sectors must establish their criteria for joining and post them on the public MISO website.

“Sectors are encouraged to be as inclusive as possible, which ideally ensures a new entity can find a fit within the existing set of sectors except in the rarest of circumstances,” the AC wrote.

The committee this spring created a miscellaneous Affiliate sector to serve as a catch-all for new, hard-to-pin-down members. The move prompted the board to charge the committee with making rules on how new members join sectors and how new sectors are created. (See Board OKs 11th MISO Sector, Orders Redesign.)

In its new rules, the AC called new sector creation a “last resort” and said that a group of organizations wishing to form a new sector must make their case in writing and boast documented participation in MISO’s stakeholder committees. While the committee can recommend a new sector’s creation, the board will have the final say.

MISO sector rules — North Dakota PSC Commissioner Julie Fedorchak | © *RTO Insider*

The AC also said that if a band of stakeholders wants to create a new sector, it should be at least 10 organizations strong. If not, the organizations may have to join the Affiliate sector.

North Dakota Public Service Commissioner Julie Fedorchak said the 10-organization threshold seems a little high, considering that most stakeholders would probably find a home in MISO’s existing 11 sectors.

“It seems that having that minimum threshold there is a little restricting,” Fedorchak said. In response, the committee added language giving the board the ability to override the 10-organization requirement.

The AC isn’t finished on sector restructuring. The committee will next discuss divvying up voting rights and how to consolidate like-minded sectors.

Advisory Tx Planning Principles?

Meanwhile, some AC members want to have a say in MISO’s effort to better coordinate its transmission planning processes.

The RTO currently uses separate planning processes to study transmission buildout for its generator interconnection queue and the reliability and economic projects under its annual Transmission Expansion Plan. Several committees are coming up with ideas to better link the planning studies and identify more cost-effective network upgrades that can meet multiple transmission needs. (See MISO Unveils 1st Proposal to Consolidate Tx Planning.)

The AC is debating whether it should draft principles to guide the committees’ discussions. Members of the Municipals Cooperatives and Transmission-Dependent Utilities sector asked the committee to draft coordinated transmission planning principles.

“We’re looking for something more than meeting notes,” DTE Energy’s Nick Griffin said.

Several committee members, however, are opposed to the idea, saying transmission planning isn’t in the committee’s bailiwick.

Environmental and Other Stakeholder Groups sector representative Natalie McIntire, of Clean Grid Alliance, said a set of transmission planning principles would constrain the committees’ work and “confuse the stakeholder process.” She also said it isn’t the AC’s place to shape MISO planning policy.

ITC Holdings’ Cynthia Crane, chair of the Planning Advisory Committee, also said a set of AC principles might muzzle some committee discussions.

Fedorchak said it would be a “pretty heavy lift” for sectors to reach consensus on consolidated planning.

Xcel Energy’s Carolyn Wetterlin, who also chairs MISO’s cost allocation stakeholder group, questioned what purpose the principles would serve and agreed that consensus would be hard to come by.

The AC will again discuss the principles during its August teleconference.

July 24, 2020

FERC OKs Negotiated Rates for Merchant Tx Line

FERC on Thursday approved SOO Green HVDC Link’s request to charge negotiated rates on its proposed 350-mile, 2,100-MW transmission line, which the developers hope to use to deliver renewable energy from upper MISO to Illinois and the PJM grid (ER20-1665).

In June, PJM stakeholders agreed to consider integrating HVDC converters as a new type of capacity resource in the RTO at SOO Green’s request. (See HVDC Initiative Endorsed by PJM Stakeholders.)

The SOO Green line is planned to run underground, primarily along existing rail rights of way from Mason City, Iowa, to Plano, Ill. Construction is expected to begin in early 2022 and be completed by 2024.

SOO Green is owned 80% by Copenhagen Infrastructure III, 10% by Jingoli Power Transmission and 10% by Siemens Energy. None of the owners or their affiliates owns any other transmission facilities, except for generation interconnection facilities, the developers said. (A Jingoli affiliate owns less than 10% of a small cogeneration facility in Michigan, and Siemens holds a minority interest in a combined cycle generation facility near Cleveland.)

The developer has hired London Economics International to design an open solicitation process and serve as its independent evaluator.

SOO Green transmission rates — | *SOO Green*

SOO Green hopes to attract generators, marketers, load-serving entities and end-users to obtaining transmission capacity rights, either as “anchor shippers” or later through an auction. The “registered participants” can seek commercial arrangements on their own or ask to be matched with others by the independent evaluator.

FERC evaluates negotiated rate applications based on four factors: the justness and reasonableness of the rates; the potential for undue discrimination; the potential for undue preference, including affiliate preference; and regional reliability and operational efficiency requirements. The commission said its review takes into account its open-access requirements, the Federal Power Act and the “financing realities faced by merchant transmission developers.”

No one filed interventions or protests in response to SOO Green’s application.

The commission concluded that the developers will bear the full market risk of the project and have no ability to erect barriers to entry or incentive to withhold capacity because they will turn over operational control of the line to either MISO or PJM, which will operate it under its Tariff.

“SOO Green states that while it is currently in discussions with both MISO and PJM about the many operational issues involving the project, it is unclear at this juncture which RTO will ultimately have operational control of the project,” FERC said.

The commission conditioned its approval on SOO Green’s submission of a compliance filing after the open solicitation demonstrating that the allocation process was fair and transparent and consistent with the commission’s 2013 policy statement on allocation of capacity on new merchant transmission projects (AD12-9, AD11-11).

July 24, 2020

FERC Accepts SPP, NIPCO Settlement

FERC on Wednesday accepted an uncontested settlement agreement between SPP and Northwest Iowa Power Cooperative (NIPCO) over the latter’s annual transmission revenue requirement, formula rate template and formula rate implementation protocols as a transmission-owning member of the RTO (ER15-2115).

The commission last year rejected a settlement filed by SPP, saying that, because it was contested, it couldn’t be approved under its guidelines and precedent set by a 1999 case. FERC in February then denied NIPCO’s rehearing request. (See “Co-ops Rebuffed in Settlement Rehearing Requests,” FERC Denies Rehearing in Z2 Remand Order.)

SPP NIPCO Settlement — Northwest Iowa Power Cooperative has agreed to an annual transmission revenue requirement with SPP. | *NIPCO*

NIPCO had argued that when TOs join regional grids, even indirect modifications to grandfathered agreements can trigger a threshold analysis under the Mobile-Sierra doctrine, which holds that negotiated, fixed-rate contracts are to be presumed just and reasonable under the Federal Power Act and cannot be revised by FERC without a finding that the public interest requires modification.

The commission said the Mobile-Sierra “public interest” presumption applies to an agreement only if the agreement has certain characteristics that justify the presumption.

In its latest order, FERC clarified the framework that would apply if it was required to determine the standard of review in a later challenge to the settlement by a third party or by the commission acting on its own authority.

SPP was given 30 days to file a compliance filing.

July 24, 2020

Optimism About Renewables Abounds amid Pandemic

Despite a severe spike in unemployment and some project delays amid the COVID-19 pandemic, industry stakeholders remain upbeat about the long-term prospects of renewable energy, as indicated by a panel during the National Association of Regulatory Utility Commissioners’ Summer Policy Summit on Tuesday.

Gregory Wetstone, CEO of the American Council on Renewable Energy, opened the panel with some sobering unemployment figures: 514,200 people in the clean energy sector are out of work as of this month. But most of this is on the residential solar side.

renewables pandemic — ACORE CEO Gregory Wetstone | *NARUC*

“The bigger issues from the standpoint of utility-scale have been availability of tax equity and finance,” Wetstone said, though these have been mitigated somewhat by the U.S. Treasury Department’s deadline extensions in May for projects to qualify for federal tax credits.

There’s also been “a big uptick in a focus on sustainability investing,” which has been helpful, Wetstone said. He noted BloombergNEF data suggesting that though 2020 will not see as much renewable development as expected before the pandemic hit, it will still be mostly on par with that of 2019 and more than rebound next year. (See Renewable Investors See Light at End of COVID Tunnel.)

Wetstone cited “key drivers” for continued investor confidence, including decreasing costs; increased demand from residents, companies and utilities; increasing state and local renewable and emission goals; and climate change as an ever more resonant political priority for residents.

ACORE said that confidence in mid-term sector growth remains strong consistent with its 2018 and 2019 surveys. | *ACORE*

Xcel Energy CEO Ben Fowke, who serves as chairman of Edison Electric Institute, also expressed confidence. “I happen to be of the mindset that we can do more with clean energy to jumpstart the economy and overcome some of the economic impacts of COVID-19,” he said.

“We have seen some delays with some of our wind farms [because of] the supply chain disruption. Fortunately, we still qualify for the 100% production tax credits for our customers because of the safe harbor extension. … So things are going OK at Xcel, and we’re looking forward to being able to be part of the solution to get the economy rolling again.”

Fowke’s company, which has set a goal to be 100% carbon-free by 2050, expects 80% of its power to come from renewables. He is not so concerned about reaching that renewable milestone as in securing the last 20% of zero-carbon resources — the unknown on which he urged investors to focus.

“I think it’s really important we get started today in nurturing those resources so we can all meet those zero-carbon goals by midcentury,” Fowke said. “I don’t know what those resources will be.” He listed advanced nuclear, carbon capture, geothermal and hydrogen as candidates. “The important thing is we need to get started today. And we need to recognize the fact that we can’t do it with 100% renewables. It defies the laws of the grid.”

Federal Aid Unlikely

The discussion occurred amid a surge in coronavirus cases in the U.S., an increase in deaths from the virus and an uptick in unemployment claims, just as federal unemployment benefits and eviction moratorium are about to expire. Congress and the White House are in the middle of negotiations on what to do next to address the crisis.

Both Fowke and Wetstone expressed a desire for aid to the renewable sector in the form of tax credit extensions or refunds, or a measure to make it easier to site interregional transmission.

But in comments before the panel, Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee, said energy-specific measures are likely going to be left out of any forthcoming stimulus legislation. She listed some measures she said there has been discussion on: extension of the tax credits; a short-term waiver of Nuclear Regulatory Commission fees for “challenged” nuclear plants; and a program to provide personal protective equipment for nonprofit utilities.

“I am hoping we can find common ground in some of these areas,” she said. “Now I can’t tell you which of these items will make it into a final package; only that, in my view, they make good sense and I think that they would enhance it.”

Murkowski also used her time to plug her American Energy Innovation Act, which faltered on the floor of the Senate in March. “If anybody has an opportunity to raise these issues with the folks on the [Environment and Public Works] Committee to separate [hydrofluorocarbons] from our energy bill, I’d appreciate it,” she said. (See FERC Targeted in Energy Bill Amendments.)

July 23, 2020

Industry Seeks Clarity on Supply Chain Orders

Government efforts to ensure the security of the bulk power system run the risk of hampering utilities’ ability to operate effectively, industry representatives warned at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit on Tuesday.

“I think it would be one thing if we get a blacklist. ‘Here are two or three vendors not to use’ — we’ll deal with that,” Mike Kormos, senior vice president of transmission and compliance at Exelon, said during the “Managing Supply Chain Risks in Critical Energy Infrastructure” panel. “If we’re being told [we’re] only allowed to use one or two, because they’ve been certified and the rest have not … [that] may not be able to fully support this industry with what we have going on.”

Supply Chain Orders — Mike Kormos, Exelon | *NARUC*

NARUC organized the panel in response to President Trump’s declaration of a national emergency in May aimed at restricting the purchase of BPS equipment from suppliers suspected of connections with foreign adversaries, defined as any foreign government or nongovernmental person connected with threats against the U.S. or its allies. (See Trump Declares BPS Supply Chain Emergency.)

Both NERC and the Department of Energy followed up on Trump’s executive order earlier this month. NERC issued a Level 2 alert requesting information on transformer control and protection systems, while DOE filed a request for information focusing on utilities’ practices for identifying and mitigating supply chain vulnerabilities. (See NERC Issues Level 2 Supply Chain Alert.) Both DOE and NERC have identified China and Russia as the most pressing adversaries, with Iran, Cuba, North Korea and Venezuela also mentioned as significant threats.

Industry Fears Compliance Costs

While Kormos said that Exelon and its industry peers understand the need for the executive order and the urgency of the information requests, he reminded the panel of the compliance burden facing companies asked to review all of their equipment by the Aug. 21 deadline for NERC’s alert. The restriction of the alert to equipment purchased in the last 10 years helps reduce the amount of work needed, but entities might be unable to provide some of the information being demanded, he said.

“It’s one thing for us to recognize and figure out who we bought from. … We probably have those records going back 10 years,” Kormos said. “But when you start talking about potential subcomponents of these systems … [we] might have bought a transformer from one vendor, [and] who that vendor was using for subcomponents in that is something we don’t have, quite frankly.”

Kormos also voiced industry concerns over the longer-term implications of the order, particularly the possibility that utilities could be asked to “rip and replace” equipment deemed vulnerable to foreign interference. Such a requirement could leave entities with dangerously reduced inventory, unable to muster enough spare parts to repair damage from major storms or other events.

Engaging Vendors, not Punishing Them

Representatives of both DOE and NERC emphasized that they were aware of industry’s concerns and would aim to keep their communications transparent. Manny Cancel, senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center, told the panel that the intent of the executive order and the follow-on actions by NERC and DOE were not meant “to drag vendors through the mud,” but to engage with them and their expertise to protect the power grid.

“We see this order as complementing NERC’s work. … We kind of knew it was coming … and what our response would be once the order was published,” Cancel said. “The purpose of this alert is … really to establish extent of condition — how much of this effort is out there, where is it — and that will help inform subsequent actions and efforts around this.”

July 23, 2020

NJ Releases Draft Offshore Wind Plan

New Jersey has released a plan detailing how it will procure 7,500 MW in offshore wind resources in the next 15 years as part of its goal to reach 100% clean energy by 2050.

The 82-page draft of the New Jersey Offshore Wind Strategic Plan and its 428 pages of appendices, released last week, calls for the development of the resources while protecting the environment, as well as commercial and recreational fishing areas. The plan anticipates that by 2050, offshore wind will provide 23% of electricity to customers statewide.

A public meeting to discuss the plan originally scheduled for July 20 was rescheduled for Aug. 3.

The recommendations contained in the plan are supported by analyses of environmental and natural resources, ports to support the needed infrastructure, supply chains and the levelized cost of energy.

“The development of New Jersey’s offshore wind infrastructure will create thousands of high-quality jobs, bring millions of investment dollars to our state, and make our state a global leader in offshore wind development and deployment,” Gov. Phil Murphy said in the preamble of the report.

Murphy first introduced the 7,500-MW goal last November when he signed Executive Order 92 at the Liberty Science Center in Jersey City, where he was joined by former Vice President Al Gore. (See New Jersey Doubles OSW Target.)

The plan includes using public and private financing to encourage investment in the New Jersey Wind Port, a proposed 200-plus acre manufacturing facility set to be built in Lower Alloys Creek in 2021, as the region’s first major offshore wind construction and marshaling port.

It also includes ideas for working with equipment manufacturers, developers and potential ports on the development of manufacturing facilities in New Jersey to meet the projected building demands by the 2024-2026 time frame. It also incorporates utilizing the state’s WIND Institute to support research, innovation, stakeholder engagement and training.

Officials also cited continuing collaborations with PJM on offshore wind interconnection and finding the most efficient transmission expansion to accommodate future projects. The plan calls for the evaluation and incorporation of energy storage and smart grid technology.

“We are fortunate to live in a state with abundant coastline and some of the best wind resources in the world, so it is natural for New Jersey to expand this reliable, renewable, cost-effective energy source,” said Robert Asaro-Angelo, commissioner of the Department of Labor and Workforce Development. “This industry has the potential for exponential growth, with tens of thousands of good-paying, family-sustaining jobs.”

While the draft does not detail the potential costs of the plan, it acknowledges that the upgrade of port facilities and the New Jersey Wind Port will require hundreds of millions of dollars in investment.

“Offshore wind represents a once-in-a-generation opportunity for New Jersey,” BPU President Joseph Fiordaliso said. “By investing in this renewable resource, we can provide jobs, clean energy and millions of dollars in economic activity for our state.”

July 23, 2020

NEPOOL Reliability Committee Briefs: July 21, 2020

The New England Power Pool Reliability Committee on Tuesday narrowly approved changes to ISO-NE’s gross load forecast reconstitution methodology, recommending Participant Committee approval next month in order for Tariff changes to be filed with FERC with a requested effective date of Oct. 5.

The committee voted 60.62% in favor of the motion, just over the required 60% threshold. If approved by the PC and the commission, the RTO anticipates starting to use the methodology in the fourth quarter for its 2021 Capacity, Energy, Loads and Transmission (CELT) forecast.

A primary objective of the gross load forecast is to ensure that passive demand resources (PDRs) are not double-counted in the Forward Capacity Auction. PDRs receive compensation as a supply-side resource and reduce demand; thus, their demand-reducing impact becomes embedded in historical load data.

As presented by ISO-NE Load Forecasting Manager Jon Black, the proposed methodology ensures that PDRs are appropriately embedded in the gross load forecast by creating a smooth historical reconstitution time series.

“The smoothing enables us to include recent auction outcomes that extend beyond the historical period,” Black said. By calibrating the amount of PDRs being reconstituted to the capacity supply obligations (CSOs) from the most recently completed FCA, there are a couple of associated improvements, he said.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

“No. 1 is what we originally set out to improve upon, which is we shall not be reconstituting energy efficiency installations that are in excess of their CSO, so the accounting would no longer reflect the overperformance,” Black said.

Second, smoothing in conjunction with using the most recently completed primary auction outcomes enables the capture of more recent trends, especially expiring EE measures that are no longer participating as supply in the Forward Capacity Market, he said. The new methodology provides a framework to adjust the gross load forecast to reflect differences in FCA CSOs and those of annual reconfiguration auctions.

“I see these as very significant improvements that I believe are needed in the current forecasting environment in New England,” Black said.

At the June RC meeting, a stakeholder asked whether June 2016 rather than June 2006 would serve as a better starting point for the development of the reconstitution history.

Black said that using June 2016 as a starting point results in a reconstitution trend line with a negative slope, suggesting a decreasing amount of PDR over time, which does not reflect the longer-term CSO trend.

“Using all of history is better, right out of the gate,” Black said. “Picking sub-trends within the overall history of all the FCA outcomes is probably ill-advised.”

The revised reconstitution methodology needs to be implemented for all long-term gross forecast modeling, which is performed for the region and all states separately, and for both summer and winter months, Black said.

Changes to Operating Procedures

The RC discussed proposed changes to several operating procedures, starting with a redline review of changes to OP-17, which describes how ISO-NE monitors and performs analyses to determine allowed load power factor.

If approved by the RC next month and in September by the PC, the changes would be effective Sept. 3.

ISO-NE would use supervisory control and data acquisition system information to perform a survey that would allow it to examine points for every hour of the year instead of the current six selected annually for monitoring, said Dean LaForest, the RTO’s manager of real-time studies.

It would also determine noncompliance based upon adverse impacts to reliability or unit commitment, and would relieve market participants from having to submit annual load power factor survey data, except in cases of noncompliance to determine responsible parties.

The RC also accepted revisions to OP-12 Appendix B to support data change updates in a revision last month to OP-12 related to voltage and reactive control, effective July 20. The changes allow more frequent updates to OP-12B data by using a new format and notifying the RC of changes by email instead of their inclusion on the monthly agenda.

Lastly, the RC discussed changes to OP-21 regarding energy forecasting and actions during an energy emergency, with a proposed effective date of Oct. 18 if approved by the committee in September and the PC in October. The revisions leave existing processes substantively unchanged but would incorporate the annual Generator Winter Readiness Survey process in order to enhance ISO-NE’s situational awareness of generator pre-winter preparations.

The revisions also would incorporate the annual Natural Gas Critical Infrastructure Survey process in order to ensure critical infrastructure of the interstate natural gas system is not on electrical circuits subject to automatic or manual load-shedding schemes.

Committee Actions

The RC’s notice of actions included approval of several motions, noting that all sectors had a quorum.

The RC approved the 19.8 MW SR Litchfield Solar Project proposed plan application (PPA) in Harwinton, Conn. from Eversource Energy (ES-20-G167); the 7 MW BD Solar Winslow II Solar Project from Central Maine Power (CMP-20-G40); the Wareham Transformer #2 Addition Project in Wareham, Mass. from Eversource (ES-20-T33); the 10 MW SR Stonington Solar Project in North Stonington, Conn. from Eversource (ES-20-G168); the Gravel Pit Solar Generation and related Transmission Project from Gravel Pit Solar and Eversource (ES-20-G169; ES-20-T34; ES-20-T35); and the Vineyard Wind Revisions Project PPAs from Vineyard Wind (VW-19-G01-Rev. 1; VW-19-T01[through 5]-Rev. 1.

The RC also approved $6 million in Pool-Supported PTF cost recovery for transmission upgrades to address asset condition issues at the Berlin Substation of the Vermont Electric Power Company (VELCO).

July 23, 2020

FERC OKs El Paso Electric Mitigation

FERC on Wednesday approved a market power mitigation plan for an investment fund’s $4.3 billion purchase of El Paso Electric and rejected rehearing requests challenging the commission’s approval of the deal (EC19-120).

The commission’s March 30 order approving the transaction directed the companies to file a mitigation plan to address market power concerns that could arise from a premature termination of power purchase agreements for Mesquite Power, part owner of the 595-MW Mesquite Generating Station in Arizona. Mesquite Power is owned by EPE’s purchaser, the Infrastructure Investments Fund (IIF). (See FERC Conditionally OKs Purchase of EPE.)

The applicants offered two options to reduce their controlled capacity if the “surplus output contracts” for Mesquite are terminated before their scheduled expiration on May 1, 2021.

Under the first option, EPE would sell a 14-MW block of firm energy during peak periods. The energy would be supplied by an EPE generation facility that would be economic during the seasons and load periods with market power screen failures and backed by system power if the designated unit is unavailable.

EPE’s Rio Grande Plant in Sunland Park, N.M. | *El Paso Electric*

Under the second option, EPE would sell a 14-MW block of firm energy from its share of the Palo Verde nuclear plant during peak periods to a nonaffiliated third party at the Four Corners trading hub. EPE would pay liquidated damages if it is unable to deliver.

“Either option would be sufficient to mitigate the competitive harms identified by applicants’ sensitivity analysis,” FERC said in approving the proposal. It required the applicants to notify it if the contracts are terminated and which mitigation proposal will be enacted within 60 days of Mesquite receiving notice of early termination.

The commission rejected a request to rehear the March order by Public Citizen, which contends JPMorgan Chase should be considered an affiliate of IIF in FERC’s analysis of the merger. J.P. Morgan Investment Management has acknowledged it is an investment adviser of IIF, but FERC ruled that its market power analysis showed the transaction would have no adverse effect on rates even if J.P. Morgan were considered an affiliate.

“The commission did not, as Public Citizen argues, ignore the information it provided in its various pleadings. Indeed, it was partly in response to Public Citizen’s various pleadings, and applicants’ responses to them, that commission staff took the extra step of requesting additional information and explanation from applicants,” FERC said.

The commission also rejected a rehearing request on similar grounds from U.S. Sens. Jeff Merkley (D-Ore.), Ed Markey (D-Mass.) and Bernie Sanders (I-Vt.), saying they lacked standing because they did not file motions to intervene in the proceeding and were not otherwise made parties to it.