Page 1271 – RTO Insider

July 21, 2017

NEPOOL Reliability, Tx Committee Briefs

ISO-NE on Tuesday proposed a plan to refine the procedural and technical requirements for determining whether new or modified distribution-connected generation should be interconnected by the RTO or a local utility.

Cheryl Ruell, manager of transmission services for ISO-NE, delivered a presentation on guidance for distribution-connected generation to the NEPOOL Reliability/Transmission Committee, which met July 18-19 in Meredith, N.H.

The grid operator’s proposal would consider the location and status of the distribution circuit to which the resource connects — as well as the size of the proposed generator — to determine the nature of any application approval required under Section I.3.9 of the Tariff. The interconnecting transmission owner would submit an application on behalf of generators that don’t participate in the wholesale market. Distribution-connected generators less than 5 MW may file a special category notification form, while those under 1 MW are exempt under the Tariff.

Existing state interconnection processes would continue to apply to any Public Utility Regulatory Policies Act qualified facilities in cases when the generator is interconnecting to a FERC-jurisdictional facility, but only if those projects produce energy to be consumed only on the retail customer’s site or sell 100% of their output to the interconnecting utility, rather than selling to RTO markets. If the host utility wishes to register the qualifying facility in the wholesale market, the host utility must meet all ISO-NE registration, modeling and operating requirements.

Forward Capacity Market and Interconnection Standards

ISO-NE also presented the committee with the current procedures for integrating a new generator with the Forward Capacity Market and interconnecting an elective transmission upgrade (ETU), which is a merchant-funded transmission interconnection.

distribution-connected generation NEPOOL — | *ISO-NE*

Director of Resource Adequacy Carissa Sedlacek and Director of Transmission Strategy and Services Al McBride covered timelines for interconnection, resource deliverability and application of the overlapping impact test.

The grid operator analyzes generators and ETU projects in the order they entered the queue and allocates transmission upgrades accordingly. Overlapping interconnection impacts restrict qualification when the upgrades identified for a new generator cannot be completed by the start of the requested capacity commitment period.

Under FERC rules, it may not be just and reasonable “for a generator in one location to sell its capacity as a capacity resource to, and receive capacity payments from, a load in another location if the generator’s output is not deliverable to the load that buys the capacity.”

Queue reforms in 2008 improved the FCM and generator interconnection process by replacing the “first-come, first-served” approach with a combination of a “first-come, first-served” and “first-cleared, first-served” approach. The changes established two types of interconnection service: capacity network resource interconnection service (CNRIS) and network resource interconnection service (NRIS).

Generators are not required to participate in the FCM in order to interconnect to the New England transmission system.

The grid operator uses overlapping impact analysis to identify qualifying transmission upgrades. The study resource — whether transmission or generation — is responsible for impacts where the addition of the capacity results in an overload on a transmission element that is greater than or equal to 2% of the applicable thermal rating or greater than 10 MVA of the applicable thermal rating.

Generation redispatch depends on the distribution factor (DFAX) of the generators on a transmission element in the subsystem, which is a measure of the change in electrical loading on an element such as transmission line or transformer because of a change in output from a given generator. Generation with a DFAX greater than or equal to 3% on a monitored element for a given contingency — “harmer” generation — is not to be redispatched to relieve the constraint for a given study dispatch.

— Michael Kuser

July 21, 2017

OMS Issues EE Market Participation Opinion

By Amanda Durish Cook

The Organization of MISO States (OMS) on Monday voted to lodge a protest in an ongoing dispute over whether states can prohibit energy efficiency resources from entering RTO markets.

OMS Executive Director Tanya Paslawski said the protest asks FERC to apply the same treatment to EE resources as it did to demand response in Order 719. It also affirms the authority of states to have final say in the matter.

The protest filing was approved by the OMS Board of Directors at a July 17 meeting held during the National Association of Regulatory Utility Commissioners Summer Policy Summit in San Diego.

oms energy efficiency — The Organization of MISO States Board of Directors during the winter National Association of Regulatory Utility Commissioners meeting in Washington | © *RTO Insider*

FERC Order 719 required RTOs to accept bids from DR resources for certain ancillary services “on a basis comparable to other resources” and allowed aggregators to bid DR on behalf of retail customers directly into the market under certain circumstances.

OMS’s request stems from a recent disagreement between PJM and the Kentucky Public Service Commission. Citing the need to prevent expensive and unnecessary capacity purchases, the commission issued an order restricting EE resources from participating in PJM wholesale markets except in special cases. PJM staff responded by producing a problem statement contesting state regulators’ authority to restrict EE participation its capacity market. (See “EE Problem Statement Narrowly Approved,” PJM Market Implementation Committee Briefs.) National trade group Advanced Energy Economy petitioned FERC in June for a declaratory order, asking the commission to assert jurisdiction over the terms of EE participation in RTO/ISO markets (EL17-75).

Paslawski said that while FERC expressly left EE resources out of the order, OMS supports their market participation.

OMS members at the San Diego meeting agreed with the filing’s tone to uphold state jurisdiction. Commissioner Ken Anderson said the filing’s “thrust” on the jurisdiction of states was fitting.

MISO Asks OMS for DER Ideas

MISO Executive Director of Market Design Jeff Bladen appeared at the OMS meeting to inform state regulators that the RTO is beginning to work on developing market rules for distributed energy resources — and that he’d like input from the organization.

“Like all emerging issues, this is very much a work in progress,” Bladen said.

MISO seeks to create a common definition for DERs, rather than defining resources by technology type, the first step to developing future policy and planning processes, Bladen said. The RTO is currently running simulations with increased concentrations of DERs in hypothetical conditions to determine how it can create a more coordinated grid in which DERs do not stress transmission operations and real-time reliability conditions.

“We’re trying to test scenarios to see if we’re on the right track,” Bladen said.

Michigan Public Service Commission Chair Sally Talberg asked if MISO could carry out such simulations without communicating with generation owners.

“We’re essentially ignoring the method of dispatch” at this point in our studies, Bladen said.

Stakeholders will again take up DERs as their “hot topic” discussion item at MISO’s next full board meeting in September. Bladen said MISO will ask for stakeholder ideas on how to best integrate the resources.

“We see ourselves as just another collaborator on this rather than giving the answers.”

July 20, 2017October 31, 2023

Rates, Renewables Boost Avangrid Q2 Earnings

By Michael Kuser

Avangrid earned $120 million in the second quarter, up 17% because of new rate plans in New York and Connecticut, improved cost management and a 4% increase in renewable energy production, the company reported Wednesday.

Avangrid CEO James P. Torgerson | Avangrid

The company attributed last quarter’s spike in renewable output to the recently completed 208-MW Amazon Wind Farm in North Carolina but said production at its other wind facilities came in below average. Avangrid plans to sign power purchase agreements equating to 1,800 MW of new wind and solar through 2020.

“We’ve already secured 1,000 MW of that — or 55%,” CEO James P. Torgerson told investors and analysts during an earnings call.

Avangrid controlled more than 6,000 MW of renewable resources by the end of June, 349 MW of which was added this year. Another 600 MW is slated to come online during the second half of 2017, with wind representing 534 MW and solar making up the remainder.

Renewables Rising

The company manages two primary lines of business: Avangrid Networks comprises eight electric and natural gas utilities serving around 3.2 million customers in New York and New England, while Avangrid Renewables operates more than 6 GW of mostly wind power in 23 U.S. states.

Avangrid Renewables Pipeline | Avangrid

Avangrid is this year focusing on reducing its exposure to wholesale markets by decreasing its merchant capacity from 35% to 27%.

“Year-to-date, we’ve executed 589 MW of fixed-price contracts to reduce our merchant capacity, and we’re really committed to keeping on track and adding even more as we see opportunities,” Torgerson said. “The company targets to be at 75 to 85% PPA plus hedges that we have on merchant capacity, so by adding the long-term hedges, we will actually be over 80%.”

The Networks business continues to dominate the company, contributing 73% of overall adjusted net income year-to-date, up 9% over the same period last year. But the Renewables division is playing catch-up, seeing its adjusted net income rise 26% for the same period.

Offshore wind platform | Avangrid

The company sees clean energy and offshore wind initiatives in Massachusetts as “key opportunities” to increase income beyond its long-term plan, Torgerson said.

Avangrid plans to bid “multiple transmission and/or renewable solutions” into a collaborative effort by the Massachusetts Department of Energy Resources, Eversource Energy, National Grid and Unitil to solicit clean energy proposals for 9.45 TWh annually of renewable generation.

“They’re looking for incremental hydro on a firm basis, but also new Class I renewable portfolio standard [resources], which would be wind and solar,” Torgerson said. “A combination of both could include transmission projects under a FERC tariff.”

Massachusetts is also soliciting up to 1,600 MW of offshore wind proposals due in December, and Avangrid intends to bid into that in partnership with Copenhagen Infrastructure Partners, Torgerson said. The projects will be selected in April 2018.

NYPSC Quorum Commended

Torgerson lauded the recent appointment of a new chair and two additional commissioners to the New York Public Service Commission, which operated for several months with only two of five seats filled, causing a backlog.

As part of New York State’s Reforming the Energy Vision initiative, Avangrid subsidiaries New York State Electric and Gas and Rochester Gas & Electric have filed a combined proposal with the commission to launch an Energy Smart Community project. The two utilities have already installed 20,000 smart meters under the program.

Quorum Pending at FERC

Avangrid could stand to benefit — or not — from the restoration of FERC’s quorum. The D.C. Circuit Court of Appeals (15-1118) in April overturned FERC’s 2014 order setting the base return on equity for a group of New England transmission owners — including Avangrid’s Central Maine Power — at 10.57%. The court ruled that the commission failed to meet its burden of proof in finding the existing 11.14% rate to be unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.) The TOs are seeking to begin billing at the prior ROE.

“That is the most recent rate that’s legally in effect at this point, and we requested to begin billing that again 60 days after FERC has a quorum, with retroactive billing to June 8 of this year,” Torgerson said. “If no FERC decision is reached, we’ll start doing that.”

FERC has lacked the necessary three-person quorum since the February departure of former Chair Norman Bay, and has been down to one commissioner — acting Chair Cheryl LaFleur — since Colette Honorable left last month.

LaFleur may be joined by four new members if Democrat Richard Glick and Republicans Kevin McIntyre, Robert Powelson and Neil Chatterjee win Senate confirmation. (See Trump Names Energy Lawyer McIntyre as FERC Chair.) Glick is a former vice president of government affairs for Avangrid.

July 20, 2017

Congestion Projects, Siting Review on MISO Slate

By Amanda Durish Cook

MISO’s Planning Advisory Committee on Wednesday heard updates on the RTO’s ambitious slate of current planning studies and process improvements.

miso market congestion planning — Ghodsian | © *RTO Insider*

Stakeholders got a first look at the preliminary projects resulting from MISO’s yearly market congestion planning study during the July 19 PAC meeting. The RTO has so far floated three potential projects in the West of the Atchafalaya Basin (WOTAB) area straddling Texas and Louisiana:

A new $137.6 million 500-kV line and substation expansion from Hartburg to Sabine in southeastern Texas that would qualify as a market efficiency project and is expected to be in service by 2023.
A $2.8 million replacement of 26 transmission structures along the Sam Rayburn-Fork Creek-Doucette 138-kV line in southeastern Texas, expected to be complete by 2020.
Equipment upgrades valued at $500,000 for the existing Carlyss substation in southwestern Louisiana by 2020.

Arash Ghodsian, MISO manager of economic studies, said the RTO’s market congestion planning footprint diversity studies will produce final project recommendations in August. Project candidates will be submitted for approval by the Board of Directors at the end of the year. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs.)

MTEP Siting Up for Review

MISO is also planning on updating siting guidelines for projects included in its Transmission Expansion Plan.

This year’s siting model will be slightly altered to add likely wind and solar zones. MISO will also consider zonal resource adequacy requirements when determining siting and exclude thermal unit development from non-attainment areas subject the National Ambient Air Quality Standards.

The RTO plans to further improve its siting modeling process for the 2019 cycle through a series of stakeholder workshops that will begin in September. Matt Ellis, a MISO policy studies engineer, said the overhaul will focus on the placement of new technology, including 100 MW of queued energy storage resources, future utility-scale renewables, rooftop solar — predicted to reach 10 GW by 2027 — and the addition of more electric vehicles and their demands on load.

Ellis said projects in the interconnection queue generally exhaust themselves within a three- to five-year cycle, but MISO plans for its transmission system 15 years into the future.

He also asked for stakeholders to submit ideas by Aug. 11 on how MISO’s siting process can account for new technology.

MISO will also conduct a multi-value project triennial review this year, sizing up its existing portfolio and quantifying benefits. FERC requires a full review of the approved portfolio benefit every three years.

Project manager David Lucian said the review will have no effect on cost allocation for existing projects, but findings could be used to adjust project criteria in future projects. The review includes analyses of economic benefits, generator flexibility, renewable target standards, natural gas risks and job creation.

MISO last conducted an MVP triennial review in 2014, concluding that the portfolio held a benefit-to-cost ratio ranging from 2.6 to 3.9 and should create anywhere from $13.1 billion to $49.6 billion in net benefits over the next 20 to 40 years.

The triennial review report will be filed with FERC by the end of the year, PAC Chair Cynthia Crane said. Results will also be published in the MTEP 17 report due in December.

July 20, 2017

NARUC: Industry, Regulators See Changing Energy Landscape

By Jason Fordney

SAN DIEGO — New electricity business and regulatory models will be needed in the U.S. to transition to a future with more distributed and renewable resources, changing customer needs and new technologies, market participants and regulators said this week.

Industry representatives and state regulators gave an overview of the changing landscape at the National Association of Regulatory Utility Commissioners Summer Policy Summit. Common themes were the growth of distributed resources, managing large amounts of new renewables and developing fresh approaches as more electricity consumers also become producers.

Pacific Gas and Electric CEO Geisha Williams said that the key is to implement renewables, distributed generation and other new technologies “and not leave anybody behind.” About 40% of the utility’s customers are low-income, and they should not have to choose between paying for electricity and other critical expenses such as health care, she said.

The model of billing energy consumers purely based on the amount of electricity they use is becoming obsolete, Williams said. “That model is fundamentally at risk at this point.”

Many electric consumers are also producers, as behind-the-meter and distributed resources grow. Retail energy sales in the future “may very well likely not be a one-size-fits-all,” she said, similar to how mobile phone users have different data plans because they have widely different needs. This could entail using a tiered approach, service and access charges and new incentives for capital investment.

It is important that regulators and lawmakers put the right policies in place to implement new technologies and practices in an affordable way, Williams said, adding that “affordability is a strategic imperative to us.”

The country’s generation and distribution systems “are really undergoing a period of very dramatic change,” Nuclear Energy Institute CEO Maria Korsnick said. She contended that nuclear, particularly small modular reactors, should play a role in maintaining clean and affordable energy.

NEI President Maria Korsnick speaks at panel including PG&E CEO Geisha Williams (third from right) | © *RTO Insider*

“Small modular reactors could be game-changers in many respects,” Korsnick said, providing smaller increments of power compared with a large central station plant and giving utilities more discretion in meeting demand. Modular reactors can also bring off-grid power to remote places and cycle up and down like a natural gas plant — but with no emissions.

NARUC renewables — Pennsylvania PUC member John Coleman | © *RTO Insider*

In Pennsylvania, distributed resources are “popping up as a result of new opportunities,” Public Utility Commissioner John Coleman said. The agricultural sector is learning that biodigesters can help manage waste products while producing electricity. The question is to how to compensate these new resources.

As for the traditional ratemaking model: “Maybe it is at risk,” Coleman said. “Maybe it is time to start thinking of some of these things in a different way.”

The Pennsylvania PUC is surveying industry on new compensation approaches and ways to incentivize investment. He noted that the majority of the state’s consumers are served by competitive suppliers and electricity rates have dropped by about 30%. Natural gas plants are also rapidly replacing coal-fired units in the state.

Other than distributed resources, utility-scale generation is also changing, according to Ohio Public Utilities Commissioner Beth Trombold. The state has a potential 8,000 MW of new gas-fired generation coming online, with four gas plants under construction, one certified and four more under review. There is about 1,200 MW of new wind and 400 MW of new solar waiting in the wings, which will greatly increase the amount of renewables in the state.

Ohio is also in the middle of a grid modernization program and asking, “What kind of regulations and technological innovation are out there to enhance the customer-utility relationship?” Trombold said.

California Public Utilities Commission Chairman Michael Picker said that integrating renewables in the state has not been as challenging as was feared, and it is now more important to consider where they are placed.

Legislation is in the works in California to achieve a zero-carbon electricity grid by 2045 and the state recently extended its cap-and-trade program to 2030. (See California Zero-Carbon Power Bill Advances and California Lawmakers Extend Cap-and-Trade.)

“At this point, it’s not about getting more, it’s what you get, where you get it … and when it’s available,” Picker said of renewable generation. The state is experiencing lower electricity demand overall but higher peaks. The PUC is moving away from “silos” in terms of what kind of resources are put on the grid, but back to an integrated resource plan model, he said.

In terms of reducing greenhouse gases, more of the transportation sector must be electrified, he said. The transportation sector emits 40% of GHG in the state; gas for heating and other uses emit about 30%, while just 20% is emitted from the electricity generation.

July 19, 2017

CAISO Solar Eclipse Prep Relies on Conventional Mix

By Robert Mullin

CAISO will lean heavily on increased output from conventional generators — and a backstop of regulation reserves — to fill the void left by reduced energy production from California solar resources during next month’s solar eclipse.

The grid operator estimates that about 4,194 MW of utility-scale solar will fall off the system from the time the moon begins to pass in front of the sun (9 a.m.) to the moment of peak obscuration (10:22 a.m.) during the Aug. 21 event.

caiso solar eclipse — Graph shows a comparison between CAISO’s Aug. 21 eclipse load forecast compared with that for full-sun conditions. | *CAISO*

At the peak, grid-connected solar generation will come up about 5,600 MW short of what would be expected under full-sun conditions. Net load will surge to about 6,000 MW above normal because of diminished output from rooftop installations.

But the grid operator has been preparing its response since last year. (See CAISO Planners Looking Ahead to Summer 2017 Solar Eclipse and With Solar Eclipse Looming, CAISO Weighs its Options.) After a winter of ample precipitation, “large and fast-moving” hydroelectric resources are being positioned for rapid response during both the loss and return of solar, according to Deane Lyon, a CAISO real-time operations shift manager.

Planners are also banking on gas-fired generators to help cover the gap.

“We’re actually working with Pacific Gas and Electric and [Southern California Gas] and coordinating with their gas control centers because, besides the hydro, the gas-fired thermal is going to have to make up for a lot of the loss of solar generation,” Lyon said Tuesday during a bimonthly Market Performance and Planning Forum.

The ISO will also procure about 900 to 1,200 MW of regulation up reserves for the three-hour period affected by the eclipse — compared with a typical procurement of 300 to 400 MW.

“That’ll help us manage as the solar goes away,” Lyon said.

Lyon noted that CAISO has been consulting with Western Energy Imbalance Market (EIM) participants to develop a “consistent policy” regarding transfer service requests (ETSRs) — or dynamic transfers across balancing areas — during the eclipse so that the ISO can take advantage of imports to the greatest extent possible.

“We got commitments from the operations folks at the EIM entities that they’re willing to keep the ETSRs wide open and fully operational for the balance of the eclipse,” Lyon said, acknowledging that the ISO does not expect a “huge” uptick in transfers given that Arizona Public Service and NV Energy will also be losing solar off their systems at about the same time.

On the flip side, the eclipse is not expected to actually undercut imports.

“APS has solar, but not PacifiCorp,” Lyon said. “We don’t expect it will have that big of an effect.”

Paula Lipka, of PG&E’s short-term electricity supply team, asked if the ISO intends to increase its procurement of flexible ramping and spinning reserves — as well as regulation.

“An increase in flex ramp procurement is being considered. As far as spinning and non-spinning reserves, we will have adequate amounts of that,” Lyon responded.

Regulation reserves are the ISO’s key concern.

“We’re trying to maintain our system balance for the duration of the sun going away and returning, which is going to be a pretty big challenge,” Lyon said.

July 19, 2017

SPP Seeks Experts for Competitive Tx Panel

SPP is accepting applications from industry experts to serve on an independent panel reviewing the RTO’s 2018 competitive transmission construction proposals.

The panel will review, rank and score proposals for competitive projects under FERC Order 1000. The previous two panels recommended one such project — a 22.6-mile, 115-kV line from Walkemeyer to North Liberal in southwest Kansas. However, the project was withdrawn because of decreased load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

spp competitive transmission — | *Westar*

Interested candidates must have expertise in at least one of the following transmission-related areas:

Engineering design;
Project management and construction;
Operations;
Rate design and analysis; or
Finance.

SPP will accept applications through Sept. 1 and choose panelists later this year based on recommendations by the RTO’s Oversight Committee, which must be approved by the Board of Directors. Selected panelists will be considered contractors and will be compensated through a monthly retainer and hourly rate.

Panelist applications, instructions and more information can be found on SPP’s website or by contacting Ben Bright, the RTO’s regulatory processes manager.

— Tom Kleckner

July 18, 2017

MISO Resource Adequacy Subcommittee Briefs: July 12, 2017

MISO has introduced a three-step checklist that owners of behind-the-meter (BTM) generation can use to prove deliverability for the Planning Resource Auction, but some stakeholders are calling foul on the differing auction requirements.

The three-pronged approach will involve different sign-offs from affected load-serving entities, transmission owners and MISO. The LSE will determine whether the BTM customer can participate in the wholesale or retail market, while the TO will ascertain study requirements for access to the transmission system when the BTM generator interconnects to a non-transferred facility. The RTO will determine the resource’s deliverability or transmission service procurement in order to use the transmission system.

btm generation MISO Resource Adequacy Subcommittee Briefs — | *MISO*

“This is meant to provide some guidance on the more intricate relationship between LSEs and TOs,” MISO Manager of Resource Adequacy John Harmon said during a July 12 Resource Adequacy Subcommittee meeting. “MISO is not looking to gain new authority in this endeavor; we’re trying to stay within the bounds of our Tariff.”

Since the beginning of the year, MISO staff have been grappling with deliverability rules that would allow BTM generation in excess of a utility’s planning reserve margin requirement — but without existing transmission service — to enter the annual capacity auction. The RTO last month proposed requiring that a BTM resource submit to an optional engineering study to identify a deliverable volume of capacity eligible to be bid into a single auction. However, the study would have only temporary value. The resource would then be required to enter the same volume into the interconnection queue study process before offering capacity into any subsequent auctions. (See MISO Proposes Deliverability Rules for Behind-the-Meter Capacity.)

Harmon said MISO is proposing to adopt the optional study avenue for two planning years until June 1, 2019. After that, resource owners will have to enter the interconnection queue.

Deliverability amounts discovered in the optional study will have a “limited applicability” and will not be used to determine deliverability in the interconnection queue process, Harmon said.

Indianapolis Power and Light’s Lin Franks asked why BTM generation should essentially be treated as “free riders” on the grid, and not supported by utility aggregators.

“I don’t know of any place where behind-the-meter generation [has] paid for transmission service. They’ve paid nothing whatsoever for access to the Bulk Electric System,” Franks said. “There are some holes.”

Harmon said BTM will only have access on an as-available basis, and that the proposal is an “interim solution” to ushering BTM generation into a more formal interconnection process.

Dynegy’s Mark Volpe asked if MISO was proposing a go-around to the rules that every other capacity resource has to abide by.

“You’ve got a gigantic comparability issue here,” Volpe said.

MISO Resource Adequacy Subcommittee Briefs BTM generation — | *MISO*

Harmon pointed out that before this year, excess BTM generation was delivered undetected. “We think there’s good cause for a transition period,” Harmon said. He also added that the proposal might not be “100%” yet, but that MISO and stakeholders are striving toward the same goal.

He asked for additional stakeholder feedback on the deliverability proposal by July 26.

PRA Qualification Deferral to Become a Reality

MISO will file Tariff changes this fall to give certain capacity resources the option for additional time to qualify for the PRA.

The deferral will also be spelled out in the Business Practices Manuals and will allow certain resources to postpone completion of generator verification tests or installed capacity value calculations until after the auction. Capacity resource owners that intend to defer must inform the RTO before Feb. 15 and complete a generator verification test no later than May 31 in order to participate in the upcoming planning year.

MISO uses the verification test to determine the total capacity that a planning resource can reliably provide based on performance and availability data for summer peak conditions.

The draft BPM language states that the deferral is for untested new planning resources, existing resources “returning to operation from a catastrophic outage or suspension,” resources in the midst of increasing capability, suspended resources and resources “awaiting other miscellaneous resource approvals to achieve commercial operation.”

Analyst Scott Thompson said deferrals could also be used by intermittent capacity resources that have yet to come online at the time of the auction or generators that are completing environmental upgrades that prevent operation.

— Amanda Durish Cook

July 18, 2017

4 LMRs Face Penalties after MISO Max Gen Emergency

By Amanda Durish Cook

Most load-modifying resources called up for the first time in a decade during MISO’s April 4 maximum generation event failed to respond properly to scheduling instructions, officials said last week.

MISO load-modifying resources — Harmon | © *RTO Insider*

MISO Manager of Resource Adequacy John Harmon said 19 LMRs — demand resources and behind-the-meter generation that provide capacity — responded to meet a maximum scheduling instruction of 715 MW during the emergency in MISO South. Four LMRs failed respond at all and will face penalties under Module E of the RTO’s Tariff.

Harmon said the underperformance by some LMRs was offset by the larger-than-expected load reductions by others. The RTO was short about 25 MW of scheduling instructions in the last hour of the emergency declaration.

He stressed the importance of LMR owners providing accurate load curtailment capability to MISO every day. “It’s important that LMRs update their availability daily in the MISO communication system. Our operators rely on these each day and … are banking on the numbers when the need could arise to shed firm load,” Harmon said at a July 13 Market Subcommittee meeting.

LMRs are only required to be available for emergencies during the summer peak season and do not have to be available during non-summer months. However, the plants must notify MISO when they are unavailable through the RTO’s communication system.

In May, the RTO promised to conduct a performance evaluation of the LMRs during the event. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs.)

MISO has calculated a total penalty of about $2,000 for the four LMRs that failed to respond. The revenue from the penalties will be allocated to all market participants with load in the Entergy Arkansas local balancing authority, and on a market load ratio share basis to the Entergy New Orleans, Louisiana, Texas and Mississippi LBAs.

The RTO will assess and begin to distribute penalties this week. The generators could avoid punishment if they can identify force majeure reasons that prevented them from responding.

Harmon said MISO will review its approach to training and operations drills to improve LMR performance. It also will review its current process and Tariff to make sure LMRs are “incentivized to update availability each operating day,” he said.

“We saw a lower rate of LMRs being able to meet the load reduction that they said they could meet. That suggests to us that market participants can tighten up the precision of the information that they provide to MISO on a daily basis,” Harmon said.

Executive Director of Market Design Jeff Bladen said there might be a disconnect between what market participants can provide in load curtailment and MISO’s scheduling instructions.

“The issue is when someone tells us that they can drop from 100 MW to 10 MW, and they’re operating at 70 MW and drop to 10 MW, that’s not a 90-MW drop; that’s a 60-MW drop. Whether there’s a penalty or not, we want to operate reliably. It’s not a question of right or wrong, it’s a question of can we operate reliably,” Bladen said.

The April 4 event was driven by unseasonably high temperatures and an unusually high amount of transmission and generation outages in MISO South. It prompted the Independent Market Monitor to call for greater MISO authority in approving maintenance outages. (See MISO South Outages Worry RTO, Monitor.)

July 18, 2017

PJM OC Briefs: July 11, 2017

VALLEY FORGE, Pa. — PJM last week presented Operating Committee members with a proposed pro forma agreement for dynamic schedules, saying it would eliminate potential confusion and improve reliability.

Dynamic schedules are power flows into the RTO from a generator that is controlled by and located in a different grid operator’s territory. Unlike pseudo-tied units, the flows are not modeled in PJM’s systems as internal supply.

pjm dynamic schedules — D’Antonio | © *RTO Insider*

Because PJM lacks a standard agreement for dynamic schedules, individual agreements may contain variations in language that can result in incorrect operating procedures, the RTO said.

Under PJM’s proposal, the native balancing authority would only need to acknowledge awareness of the agreement because it remains operationally responsible for the resource. Unlike pseudo-ties, dynamic schedules require tagging and are subject to curtailment under NERC’s transmission loading relief procedures, PJM’s Phil D’Antonio said.

D’Antonio said PJM hadn’t yet decided whether they would seek to make the agreement retroactively enforceable for existing schedules. The agreement will be brought to a vote at next month’s OC meeting.

PJM’s Jacqui Hugee gave the OC an update on additional Joint Operating Agreement revisions MISO has requested relating to the pro forma pseudo-tie agreement. “For the most part, the changes are to clarify the language that is there,” she said. (See Late Agreement with MISO Forces Another Delay on Pseudo-Ties.)

Stakeholders voiced concerns about the language, but Hugee explained that PJM does not need, nor will it seek, stakeholder endorsement for the changes.

SCED Changes Implemented

PJM on Monday transitioned from a 15-minute to a 10-minute “look ahead” on its security-constrained economic dispatch (SCED) engine. The changes went into effect at 9 a.m.

PJM’s Joe Ciabattoni said the RTO will review the system’s performance after a week to ensure there are no reliability issues and evaluate whether to retain the changes. Ciabattoni said PJM does not need stakeholder approval to make the changes.

“We’re trying to better align real-time reserve levels with reserves calculated and dispatched by SCED,” he said. “Historically, we started with a 22-minute look ahead and have moved it over time to 15 minutes.”

Resilience Planning Moves Forward

PJM’s Jonathon Monken reviewed the RTO’s ongoing development of system resilience, noting that communication has expanded with related industries such as natural gas distributors. (See “Bryson Leads on Next Steps for Fuel Resiliency,” PJM OC Briefs.)

“I would expect that this will drive a lot of exercises and drills, recognizing that when we identify a vulnerability, we would much prefer to test it in an exercise environment than experience it in real life,” said Monken, senior director of systems resilience and strategic coordination.

He said that PJM is developing both internal and external roadmaps for enhancing resilience to severe weather, physical or cyber attacks or disruptions in fuel supplies. He also reviewed PJM’s Resilience Steering Committee, which includes himself and 14 other PJM staffers with responsibilities for various aspects of the plan.

John Farber of the Delaware Public Service Commission questioned using resilience as a driver for approving projects in the Regional Transmission Expansion Plan. While it was not listed on the current version of the external roadmap he presented, Monken confirmed that it is still a focus.

Farber warned that evaluation of resilience in RTEP projects wouldn’t be “as straightforward as described” and said completing quantifiable metrics by the end of 2018 is an aggressive timeline. “I would just note that the last time that PJM addressed drivers in the RTEP process … that took two and a half years. And those were, in my view anyway, difficult years,” he said.

“We certainly recognize the fact that we’re certainly not going to go faster than what the stakeholders would like it to go,” Monken said.

Ramp Rate Changes

PJM’s Cheryl Mae Velasco highlighted enhancements to its Markets Gateway online tool that will allow generators to adjust their regulation offers throughout the day instead of just once daily.

“The [web-coding] vendor had a chance to put them in,” Velasco said. “They’ve been on the backlog for quite a while.”

The announcement was met with appreciation, but also a request.

“These are items that could provide optionality in how we operate units, so to hear about it in the Operating Committee a week before [implementation] is, for me at least, problematic,” American Electric Power’s Brock Ondayko said. He asked that similar changes be brought to stakeholders’ attention “preferably” two or three months in advance.

“Once we found out [that the vendor had made the updates], we sent the communications out as soon as possible,” Velasco responded.

PJM’s Ken Seiler acknowledged Ondayko’s concern and said he would work with the RTO’s Tech Change Forum to provide earlier notice in the future.

Ciabattoni said that generators making changes to their ramp rates will not require corresponding price points in their cost-based offers.

Solar Eclipse Impacts

PJM estimates a loss of up to 2,500 MW in solar output during the solar eclipse that will occur on Aug. 21. The event is expected to last about an hour.

While grid-connected and behind-the-meter systems will be impacted the same, the difference in deployed amounts means that grid-connected output is expected to drop about 500 MW, while BTM resources could drop about 2,000 MW. PJM expects it will need to increase non-solar generation by about 1,000 MW if it’s an overcast day and up to 2,500 MW if it’s sunny. Coordination will be important during the ramp up and ramp down periods.

PJM’s Joe Mulhern said the eclipse is expected in the middle of the afternoon when the sun is high and solar generation is near its peak output. If it’s a hot day, load will no doubt be near its peak as well, he said. However, a NERC analysis showed no reliability impacts are expected for the Bulk Power System.

pjm dynamic schedule — Boyle | © *RTO Insider*

Primary FR Task Force Begins July 25

PJM’s Glen Boyle announced that the Primary Frequency Response Senior Task Force will have its first meeting at 9 a.m. July 25, with monthly meetings to follow for at least six months. (See “PJM Defends Interest in Paying for Frequency Response,” PJM Markets and Reliability Committee Briefs.)

– Rory D. Sweeney