Page 1242 – RTO Insider

December 5, 2017

PJM IMM Opposes Frequency Response Payment Bid

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM’s Independent Market Monitor and the RTO are at odds over whether generators should receive additional compensation for providing FERC-mandated primary frequency response.

PJM led most of last week’s meeting of the Primary Frequency Response Senior Task Force because, aside from the compensation issue, the Monitor’s proposal is nearly identical to the RTO’s. But that single issue attracted criticism from stakeholders. (See “Market-Based Frequency Response Solution Hard to ID,” PJM Operating Committee Briefs: Nov. 7, 2017.)

The Market Monitor argued that compensation for primary frequency response, in terms of capacity costs, avoidable maintenance costs and any heat rate loss is already accounted for in PJM’s existing capacity and energy markets. That position is “kind of a nonstarter from a generator side,” American Electric Power’s Brock Ondayko said. The payments are necessary because the revenue provided by PJM’s capacity and energy auctions are “nowhere near the supporting levels for those types of resources,” he said.

PJM IMM frequency response frequency response — Monitoring Analytics’ Haas (left) and Joe Bowring | © *RTO Insider*

Howard Haas of Monitoring Analytics argued that all of the costs involved in providing primary frequency response are baked into the market already through the cost of new entry calculation and should be included in resources’ capacity auction offers. PJM’s interconnection agreement requires all new units to provide the service.

“There is an obligation to provide the service,” Haas said. “To the extent that you’re eligible to participate in the capacity market … you have the opportunity to recover associated capacity costs and any going-forward, avoidable costs. … The capacity market does not make a distinction between new and old units, and the CONE unit includes the capability to provide the service.” (See FERC Has More Questions on Frequency Response NOPR.)

Providing primary frequency response isn’t new to PJM, and any heat-rate losses can be accounted for in the 10% adder included with energy-market offers, he said.

Ondayko dismissed that, saying the only way to receive auction revenue is to offer well below the unit’s costs.

Haas acknowledged that the natural gas boom “turned the market upside down” and that “the prices are low.” But he said prices are low, in part, because “the market is long on supply” and uneconomic units should retire.

PJM IMM frequency response primary frequency response — Hyzinski | © *RTO Insider*

“You can get up to one-and-a-half times CONE if the market is short. It’s not,” he said.

Tom Hyzinski of GT Power Group questioned Haas on competition from demand response, which doesn’t provide the inertial benefits necessary for frequency response. Haas agreed that DR should be a demand-side product rather than supply and said more needs to be done to address speculative DR offers. However, load is not required to sign an interconnection agreement.

The Argument for Compensation

PJM’s Glen Boyle said “there is a cost” to providing primary frequency response. “We want to offer a way to recover it similar to reactive supply,” he said.

He envisioned a process similar to PJM’s current payment for reactive power in which market participants make an informational filing with FERC, which directs the RTO on how much to compensate the filer. The requests would need to be newly incurred costs that are not included in the unit’s variable operations and maintenance (VOM) calculations.

“We really need stakeholder feedback on what they think the costs would be,” Boyle said.

Those determinations might get tricky. When one stakeholder calling into the meeting suggested there might be ongoing costs for maintaining the operational flexibility to increase or decrease output, PJM’s Eric Hsia said those sounded like lost opportunity costs, which FERC likely wouldn’t accept.

He said compensation would have to focus on operations and maintenance costs like those incurred for maintaining a heat rate. He said care would be taken to write the rule such that generators can’t “double dip” on costs they’ve already recovered.

Carl Johnson, who represents the PJM Public Power Coalition, questioned the wisdom of having generators file at FERC. “We’re going to struggle with just allowing anybody going in with anything they deem reasonable,” Johnson said.

Stakeholders also debated whether traditional generators with large rotating masses that produce synchronous inertia provide different benefits than renewables with converter-based “synthetic” inertia and should be compensated differently.

Ondayko said such issues should be included in the primary frequency response discussion; otherwise the discussion would be “missing out” on the “mix of resources” necessary to provide grid-scale inertia, he said.

Other Factors

PJM’s proposal would analyze primary frequency response performance by measuring the difference between the RTO’s requested action during a frequency event and how the unit responds when called. Units would have to be online and providing energy, operating between their minimum and maximum real-power output, with available headroom or footroom and assigned Tier 1 or Tier 2 reserves. The analysis would include a pass-or-fail threshold.

“We would take into account the available headroom or footroom and the expected response would reflect that,” said PJM’s Danielle Croop, adding that the analysis wouldn’t “nitpick” on small changes in performance.

Units that are providing frequency regulation wouldn’t be assessed. Nuclear units would still be exempted, as would units that are going to be deactivated and units with technical limitations. Operators would need to submit exemption requests within six months of the rule going into effect.

Stakeholders noted that some units can’t set their deadband operation — which represents the upper and lower bands of acceptable operation — and that retrofits would be prohibitively expensive on units with exceptionally low capacity factors, particularly because they usually run when there are plenty of other units online to provide primary frequency response.

PJM’s Vince Stefanowicz hesitated to agree, saying that during a restoration scenario where frequency regulation hasn’t yet been established, “primary frequency response is kind of our first line of defense.”

Johnson asked if there was a frequency event during the expectedly cold temperatures in the winter of 2014 often referred to as the polar vortex. Hsia said staff are looking into it.

The task force’s next meeting is Dec. 20, when stakeholders will discuss implementation details, including concepts proposed by Dominion Energy.

December 5, 2017

NYISO Readies Market for Energy Storage, State Targets

By Michael Kuser

NYISO has developed a three-phase approach to opening its wholesale electricity market to storage resources, the ISO said Monday upon release of a comprehensive energy storage report describing the plan.

The plan will complement whatever energy storage target New York regulators set later this month for the state’s electricity providers. Gov. Andrew Cuomo on Nov. 29 signed legislation requiring the Public Service Commission to establish targets by the end of the year. (See NY Bill Sets Stage for Storage Targets.)

NYISO energy storage wholesale market — | *NYISO*

The ISO report, “State of Storage: Energy Storage Resources in New York’s Wholesale Markets,” lays out three stages to facilitate storage participation — integration, optimization and aggregation with other distributed energy resources, NYISO Senior Vice President of Market Structures Rana Mukerji said Dec. 4.

“The intermittent outputs of renewable solar and wind resources have to be balanced to provide reliable electricity to consumers,” Mukerji said. “Storage resources will be increasingly important in this environment and help balance the intermittency of renewables and provide valuable grid services.”

New York’s electricity grid is in the midst of change driven by the state’s Clean Energy Standard and Reforming the Energy Vision initiatives, designed to transition the state from an aging mix of gas and steam turbines to a greener and more distributed grid.

“We are trying to remove barriers for storage to enter into the market, and actual penetration levels for the various technologies will depend on other factors, such as the price of natural gas, the intermittency in the system — which drives price fluctuations, and also what level of incentives storage is getting from the state public policy initiatives,” Mukerji said.

Grid Flexibility

Michael DeSocio, NYISO senior manager for market design, said the ISO is working on incorporating the latest technological advances in storage, as well as developments in public policy, to allow the grid operator to take better advantage of the capabilities of storage resources.

“Energy storage is not a new concept, but advances in technology have brought energy storage within reach as a viable, competitive energy asset,” DeSocio said. “These new storage technologies can offer the flexibility that quick-start gas turbines provide, while also helping absorb the excess energy that is produced from intermittent resources like solar and wind.”

The ISO’s new report distinguishes between storage in front of the meter and behind the meter (BTM), with the former more likely to participate in wholesale market transactions, although BTM storage could become a wholesale player when aggregated with other distributed resources. Storage developers and utilities in New York have been working with NYISO to establish dual participation of storage in retail and wholesale markets. (See New York Sees Storage in Retail and Wholesale Markets.)

“Today energy storage resources have to choose between providing only one or two ancillary services, and must be at least 1 MW in size,” De Socio said. “NYISO’s future energy storage model will allow storage resources to provide all of the grid services that they’re capable of, while also reducing the minimum participation size from 1 MW to 0.1 MW, thereby increasing the facility for storage to be integrated into the grid.”

Market-Ready by 2020

The ISO has kicked off the integration phase with stakeholders and “plans on having market rules ready for commercial use in 2020,” which will complement the ISO’s DER Roadmap issued in February, DeSocio said.

“A lot of the work that is already being contemplated in the DER program will inform this effort — things like how to aggregate resources — will be reused for integrating storage into the markets as well,” DeSocio said. “So as we think about how to integrate smaller and smaller resources, leveraging a lot of that work has already been done.”

DeSocio also addressed how the new market design will affect capacity bids.

“Today, storage resources that are participating in the wholesale markets must identify their desire to inject or withdraw electricity well in advance of the operating horizon,” De Socio said. “Today, they have to tell us that roughly 75 minutes before that operating horizon.”

The first phase envisions storage resources being able to provide a single offer indicating their willingness to inject or withdraw over the next hour. The markets could then help the resources group their utilization because market operators will have better information than is available 75 minutes before delivery, he said.

“That’s the main improvement: allowing a single offer to be considered and letting the ISO select whether they should be withdrawing or injecting in any particular [interval],” DeSocio said.

As to how quickly storage will come online in 2020, DeSocio said, “We haven’t particularly forecast the future of storage, but we are aware of storage resources today that are looking to participate, and we expect there will be more of them as they become more cost-effective and as policies evolve.”

The ISO’s new storage policies will not eliminate the need for peaking plants but complement them as storage provides a “more environmentally friendly” alternative, Mukerji said.

December 5, 2017

Mexico Market Director Seeks Increased Participation

By Tom Kleckner

MEXICO CITY — A top official with Mexico’s wholesale electricity market accepted praise last week for the outcome of the country’s latest capacity auction, but he said he is still intent on increasing participation in the effort.

CENACE mexico capacity market — Attendees gather for the GCPA’s November breakfast meeting in Mexico City | © *RTO Insider*

“There are barriers to true efficiency in the market,” Marcos Valenzuela, director of the National Energy Control Center’s (CENACE) wholesale market, said during a Gulf Coast Power Association breakfast Nov. 30. “I think we need to incorporate more participants, more qualified suppliers, to give more offers to the end users.”

Valenzuela, one of three top directors for CENACE, made his comment after telling his audience that competition had helped narrow offer spreads and drive down prices during Mexico’s third long-term auction in November. Only 16 offers were completed, though in larger packages than in the first two auctions.

According to Mexican energy consulting firm Zumma rg+c, the auction resulted in a world-record low price for wind energy, at $17.76/MWh. But the company said solar energy still accounted for 55% of the energy and clean energy certificates in the auction, with a price of $18.93/MWh.

Jose Maria Lujambio kicks off the GCPA’s breakfast meeting in Mexico City | © *RTO Insider*

Only three load-serving entities participated on the buyer-side: the state-owned Federal Electricity Commission (CFE); Spanish multinational Iberdola; and Mekent, an electricity retail division of CEMEX Energia, the second-largest construction materials company in the world. Together they bought a combined 593 MW/year of capacity in the national interconnected system, 5.49 TWh/year of energy and 5.95 million clean energy certificates per year.

Valenzuela said he has focused on increasing the number of private buyers by aggregating qualified buyers. CENACE hopes to attract more participants by establishing a clearinghouse like those used by U.S. RTOs, he said. The clearinghouse is designed to allow buyers other than CFE to participate in the auction process.

Valenzuela said implementing Mexico’s market reforms has been a “big challenge” but pointed to the speed with which the market has ramped up operations. Market reform was written into the country’s constitution just three years ago, and CENACE was able to implement a short-term market in less than a year and a half and run its first long-term auction within five months, he said.

Roll-out of Mexico’s spot market has been postponed to give market participants more time to develop market-rate — rather than cost-based — bids.

“The [timing] is very tight. Not just for us, but even for the participants, because they need to understand … the process,” he said.

Valenzuela’s comments came during the second of what Mexican representatives hope will be a recurring breakfast. Jonathan Pinzon, a partner with Zumma, said he and fellow consultant, Que Advisors’ Peter Nance, hope to schedule eight to 10 meetings in 2018, focusing on intimate gatherings that avoid “death by PowerPoint.”

“We bring together different actors from across the industry,” Pinzon said. “We’ve always thought that small-group partnerships help develop further relationships in the market. It also brings out some good questions not reflected in PowerPoint.”

Pinzon credited GCPA Executive Director Tom Foreman for helping the new effort, recognizing that Mexico is also part of the Gulf Coast. The GCPA has scheduled its next conference on the Mexican power market for May 16 in Mexico City.

December 5, 2017

NERC Parts Ways with Chief Security Officer

By Rich Heidorn Jr.

Just days after losing its CEO, NERC has seen another senior management departure.

NERC Chief Security Officer Marcus Sachs — Sachs | © *RTO Insider*

Senior Vice President and Chief Security Officer Marcus Sachs, one of seven direct reports to NERC’s CEO, “resigned” effective Nov. 27, the organization said in a statement.

However, three sources knowledgeable about the matter said Sachs was forced to leave. One former NERC staffer said Sachs was ousted because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the planned expansion of the Electricity Information Sharing and Analysis Center (E-ISAC).

“The ESCC didn’t have confidence in him taking the ISAC forward,” the former staffer said. “I don’t know if it was GridEx-related; I don’t know if it was storm-related or that Marc came from a communications background.”

Sachs joined NERC in May 2015 from Verizon, where he was vice president of national security policy. Prior to Verizon, he was deputy director of the computer science lab at SRI International and the founder of a computer security consultancy. He also worked for several months as cyber program director at the U.S. Department of Homeland Security and served more than 20 years in the U.S. Army. He has degrees in civil engineering and computer science in addition to a Ph.D. in public policy.

A second former NERC official said he was told Sachs was fired out but that he didn’t know the reason. “All I heard was that NERC forced him out,” the ex-staffer said. “My understanding is his departure was very sudden.”

But the first ex-staffer said the resignation “was supposed to be in the works before” Cauley’s Nov. 10 arrest on domestic abuse charges.

NERC did not respond to a request for comment Monday.

Sachs has joined Ridge-Lane LP, a merchant bank co-founded by former Homeland Security Secretary and Pennsylvania Gov. Tom Ridge. In an email, Sachs called his departure from NERC “a strategic move for me, which will allow me to assist other companies and organizations as they grow and develop.”

“I look forward to the next chapter of my career, and to be able to give back to others many of the lessons I have learned,” he added.

The ESCC, which serves as a liaison between industry and the federal government, is dominated by CEOs of investor-owned utilities.

Tim Roxey, a NERC vice president who serves as chief operations officer for the E-ISAC, was named interim chief security officer with responsibility for overseeing the E-ISAC and directing security risk assessment and mitigation activities. Bill Lawrence, a senior director with the E-ISAC who led GridEx IV last month, will assume day-to-day management of the center. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.)

MidAmerican Energy CEO William Fehrman, vice chair of the NERC Members Executive Committee, will provide “strategic counsel and guidance” on the E-ISAC’s expansion during the search for Sachs’ replacement, NERC said. Fehrman referred an interview request to NERC.

The E-ISAC is the primary security communications channel for the electricity sector, helping grid operators and others prepare for and respond to cyber and physical threats.

NERC’s 2018 Business Plan calls for improving the E-ISAC’s “technical and analytical capabilities with a goal of becoming the electricity industry’s leading, trusted source for analysis and sharing of security information.” The E-ISAC’s staffing will increase to 29 full-time equivalent employees from less than 20, funded by a $21.9 million budget, a $3.3 million increase from 2017.

“The long-term strategic plan is to transform the E-ISAC into a world-class intelligence collecting and analytical capability for the electricity industry,” according to the plan.

NERC General Counsel Charles Berardesco, who was appointed interim CEO following the Nov. 20 resignation of former CEO Gerry Cauley, said in a statement that he was “confident the E-ISAC, under Tim and Bill’s leadership, will continue to effectively carry out its responsibilities.” (See Cauley Resigns; NERC Launches Search for Replacement.)

Ridge-Lane says it sponsors “public-private partnerships to finance social infrastructure and advance modern urban developments across the U.S., as well as specialty venture capital and corporate development services to commercialize and scale innovative technology companies.”

The company did not respond to a request for comment.

December 4, 2017

NYISO Q3 Prices Fall on Lower Demand, Gas Costs

By Michael Kuser

NYISO third-quarter energy prices fell 16 to 30% compared with the same period a year ago because of mild summer conditions, lower natural gas prices and higher output from nuclear and hydropower plants, the ISO’s Market Monitoring Unit reported last week.

Reduced congestion into Long Island and increased congestion out of NYISO’s North Zone contributed to the decline, as well as to “substantially lower” ancillary service prices and uplift costs, MMU Director Pallas LeeVanSchaick, of Potomac Economics, told the ISO’s Market Issues Working Group on Nov. 29.

nyiso natural gas electricity demand — | *Potomac Economics*

While the Q3 report showed that NYISO’s market was competitive and that most prices and costs were down substantially compared with last year, the Monitor continued to identify potential improvements to market performance.

The report noted that a mild summer helped reduce loads by 1.8 GW on average, while natural gas prices in most of eastern New York and New England fell 12 to 19%. Nuclear and hydro units increased their average output by up to 640 MW.

Day-ahead congestion revenue fell 20% to $104 million partly because of the lower loads. West Zone lines accounted for the largest share of the congestion (25%) during the quarter, as imports from Ontario and hydro output met with bottlenecks while flowing east. New York City lines accounted for 20%, increasing because of higher gas prices relative to other regions and the expiration of the Con Ed-PSEG wheel. Long Island’s share was down sharply to 17% because of fewer major transmission outages.

Flows from the North Zone accounted for 21% of congestion, as transmission outages and derates and hydroelectric output increased, leading to several extreme negative pricing events.

Actions used to manage 115-kV congestion in western and northern New York led to import limitations from Ontario and Quebec, as well as congestion on the higher-voltage system in other parts of the state. The MMU said the costs and reliability effects of this congestion could be reduced by modeling the 115-kV constraints in the day-ahead and real-time markets.

Capacity Market Spot Prices Down

Third-quarter spot prices for capacity ranged from $2.21/kW-month in Rest of State (ROS) to $9.97/kW-month in New York City. Average spot prices were down 18% in the city and 41% in ROS, but up 6% in the G-J Locality and 51% on Long Island. Demand curve revisions reflecting changes to assumptions about the unit net cost of new entry were a primary driver for the increased prices.

While an increase in installed capacity (ICAP) was a dominant factor in the ROS price rise, supply was up only modestly from a year ago, reflecting higher test values for dependable maximum net capability, the revival of the Greenridge 4 coal unit and new wind capacity upstate. Cleared import capacity rose 350 MW from a year ago, primarily from PJM. Import capacity from Ontario increased by an average of 105 MW, offset by a similar reduction from New England.

Reserve margin and locational capacity requirements rose in all regions as a result of a recent study by the New York State Reliability Council. However, peak load forecasts fell across all regions, neutralizing the price impact from higher installed reserve margins and locational requirements.

Sharp Fall in Reserve Prices

The report also showed that day-ahead reserve prices fell by 28 to 44% from a year ago, consistent with lower load levels and lower locational-based marginal prices and primarily attributable to a decrease in reserve offer prices. After reserve market design changes in November 2015, the MMU observed offers above the standard competitive benchmark (i.e., estimated marginal cost), which it said is partly attributable to the difficulty in accurately estimating the marginal cost of providing operating reserves. However, day-ahead reserve offer prices have gradually fallen as suppliers gain more experience.

In the third quarter, a large number of units offering reserve capacity — particularly fast-start resources in eastern New York — further reduced their offer prices. The MMU said it continues to monitor day-ahead reserve offer patterns and consider potential rule changes, including whether to modify the existing $5/MWh “safe harbor” for reserve offers in the ISO’s market power mitigation measures.

Congestion Management and Pricing

The MMU noted that the ISO’s market-to-market phase angle regulator (PAR) coordination process expanded in May after the expiration of the 1,000-MW Con Ed-PSEG Wheel. (See NYISO Members OK End to ConEd-PSEG Wheel.) Congestion increased through Millwood and into New York City. In general, transmission lines in the A/B/C and J/K zones were operated more efficiently. However, the MMU observed that PARs in those areas were often not utilized to help manage congestion, being adjusted only one to five times per day on average.

The Monitor found that NYISO improved its transmission shortage pricing in June by modifying the second step of the graduated transmission demand curve (GTDC) from $2,350/MW to $1,175/MW, removing the feasibility screen and applying the GTDC to all constraints with a non-zero constraint reliability margin. As a result, constraint relaxation has been much less frequent, with violations occurring in 6% of interval during the third quarter, compared with 59% last year.

Average constraint shadow prices during transmission shortages fell moderately in most areas. Constraint relaxation leads to inefficient prices that are volatile and uncorrelated with the severity of congestion, the MMU said. Despite improved pricing outcomes, constraint shadow prices still did not properly reflect the importance of some transmission shortages. Accordingly, the MMU continues to recommend developing constraint-specific transmission demand curves.

December 4, 2017

MISO, PJM Pursue Pseudo-Tie Double-Charge Relief

By Amanda Durish Cook

CARMEL, Ind. — MISO and PJM expect to begin implementing a two-part remedy to their double-charging of congestion fees on pseudo-tied generation early next year.

MISO and PJM began collaborating to remove the overlapping congestion charges soon after the first complaint about the issue was filed with FERC last year. Stakeholders have lodged five complaints against the RTOs, including filings last year by Tilton Energy (EL16-108), American Municipal Power (EL17-29, EL17-37) and Northern Illinois Municipal Power Agency (EL17-31). Dynegy and Illinois Power Marketing filed jointly against MISO in March and added a motion to consolidate the previous complaints (EL17-54).

In an update to FERC on Nov. 22, the RTOs said their plan to address the complaints will ultimately treat pseudo-tie transactions like dynamically scheduled interchange transactions, in which two parties agree on a metered energy purchase and schedule it in both the day-ahead and real-time markets. The original value is first estimated then updated after delivery.

The first stage of the plan — slated to be in place by March — adds market-to-market settlement and day-ahead coordination of pseudo-tie transactions to the RTOs’ joint operating agreement. The second stage will have the RTOs alter their individual tariffs to address congestion charges, credits, rebates and hedges.

pjm miso pseudo-tie — Horger | © *RTO Insider*

“There’s been several challenges with the modeling on these ever since they’ve entered the market,” PJM Director of Energy Market Operations Tim Horger said during a Nov. 29 Joint and Common Market meeting of the two RTOs.

The RTOs last month filed Tariff revisions (ER18-136, ER18-137) that would enable them to factor pseudo-tie firm flow entitlements into the day-ahead market, with the attaining balancing authority modeling the impact on flowgate capacity. In real-time M2M settlements, MISO and PJM will account for pseudo-tie market flows in payment formulas, so that charges between RTOs exclude the impacts of pseudo-tie resources on flowgates in the attaining balancing authority’s calculations, ending the double-counting of congestion on flowgates.

Horger said the change comes down to modeling “proper limits in the day-ahead market.”

“PJM was modeling limits … that weren’t reflective of what the congestion actually was,” Horger said. MISO and PJM have been using a temporary rebate program until they’re authorized to include pseudo-ties in the day-ahead scheduling process. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.)

The RTOs hope to win FERC approval by March. “We’re expecting some answers and solutions shortly,” Horger said.

Phase 2

MISO and PJM will wait until later next year to roll out the second phase of the congestion remedy because it requires more complicated Tariff changes and complex software changes. Those revisions will require an attaining balancing authority to issue either refunds or financial transmission rights to cover the day-ahead congestions costs paid by pseudo-ties with load contracts. In the real-time market, credits and charges would be levied on pseudo-tie transactions based on deviations from their day-ahead schedules. The RTOs’ would leave open the option for the native balancing authority to accept a pair of day-ahead virtual transactions for pseudo-tie transactions that have FTR hedges.

“It does require more extensive software changes because it involves a hedging mechanism for deviations between day-ahead and real-time. And it may also involve refunds,” Horger said.

PJM is looking into developing a new product exclusively for pseudo-tie owners out of PJM that would allow them to hedge in the day-ahead market, similar to existing virtual transactions, he said. MISO, however, plans to hedge using its existing virtual transaction process because of the limited capability of its market system platform.

“If there’s an under-collection or over-collection in the MISO market, it’s going to be trued up with this market flow credit,” Horger said.

The RTOs will have separate filing and implementation dates for the second stage of the plan, Horger said, with PJM planning to go live in June, with MISO lagging by a few months because of IT-related challenges.

“We’re in the process of implementing a new settlement system, so that’s going to impede our ability to deliver phase two,” said Kevin Vannoy, MISO director of forward operations planning.

Some stakeholders asked if the disparate implementation dates were even possible.

Vannoy said the solutions boil down to Tariff changes that can be made independently. He promised more details on the second phase of the plan in early 2018.

Some MISO stakeholders are hoping the RTO will file a similar plan with SPP, where the potential for double congestion charges also exists, although the RTOs exchange far fewer pseudo-tied megawatts.

“We’re hoping that the pseudo-tie congestion changes will apply to SPP as well,” said Market Subcommittee Vice Chair Megan Wisersky, reporting on activities of MISO’s Seams Management Working Group in October.

MISO Monitor not Pleased

But MISO Independent Market Monitor David Patton said that MISO and PJM have yet to make a filing that will solve the underlying congestion and dispatch issues caused by pseudo-ties.

Patton’s firm, Potomac Economics, filed a protest against the first phase of the overlap solution, saying nothing in the filings “ameliorates the myriad of significant problems” caused by the uptick in resources pseudo-tying from MISO to PJM. The Monitor also argued that FERC could not even fairly evaluate the RTOs’ filing without also evaluating at least 10 other FERC dockets containing complaints against the their pseudo-tie process.

“We hope that FERC will respond to our complaint and bring some rationality to this process,” Patton said at an Oct. 12 Market Subcommittee meeting.

Horger said that for pseudo-ties to function, PJM and MISO must have comparable treatment for external and internal capacity, a binding pro forma agreement and a solution to the RTOs’ double counting of congestion.

“We need to make sure these pseudo-tie external resources are being modeled under the same criteria,” Horger said.

December 4, 2017

EIM Governing Body Approves ‘Consolidated’ Initiatives

By Jason Fordney

BOISE, Idaho — Decision-makers for the Western Energy Imbalance Market (EIM) last week approved a set of market initiatives that represents a narrowed-down version of a package CAISO proposed to market participants earlier this year.

The EIM Governing Body on Nov. 29 unanimously approved CAISO’s “consolidated EIM initiatives,” which will automate some manual processes, facilitate bilateral settlements and improve the market’s modeling accuracy.

CAISO Senior Adviser Don Tretheway briefed body members on the three aspects of the proposal over which they had decisional authority. In a presentation, he explained that one measure allows auto-matching of balancing changes in intertie schedules between an EIM resource and a non-EIM resource, allowing a member to use the external resource to “self-balance” an intertie change.

The initiative also automates the updating of mirror system resources at CAISO intertie scheduling points, which is done to prevent imbalances. Those resources allow the market to solve for the ISO and another EIM area at the same time.

“Currently, EIM entities are responsible for manually updating this mirror system resource,” Trethaway said, noting that the manual process is subject to error or delays.

A third aspect of the approved initiative supports imbalance settlement of EIM base transfer schedule changes. That measure will facilitate bilateral scheduling between EIM entities, allowing settlement of energy transfers at agreed-upon financial locations for bilateral schedule changes occurring after base schedules are submitted.

In September, CAISO announced it was dropping several aspects of the consolidated EIM initiatives because of negative feedback from stakeholders. (See CAISO Drops Proposed EIM Changes.) One proposal would have allowed non-EIM third-party transmission owners to provide transfer capacity in the market, while another adjusted management of bilateral schedule changes. A third measure would have ensured payments to EIM entities that currently don’t get compensation for wheeling power through their balancing areas.

Chairman Douglas Howe clarified with Tretheway that third-party transmission providers would reduce their own congestion revenue by providing the increased capacity to the EIM “and work against” their own interests.

“Is this really a feasible initiative at all?” Howe asked. Tretheway replied that it might be workable in certain cases with EIM transfers.

The disincentive was an issue raised by stakeholders during review of the proposal, leading it to be dropped from the initial package. (See CAISO Drops EIM Third-Party Transmission Plan.)

The Governing Body last week also gave advisory approval to separate rule clarifications for CAISO’s non-generator resources (NGR) market enhancement, which allows new types of resources (such as storage) to participate in the ISO’s regulation market. Powerex is using NGR to model its participation in the EIM, and the ISO said the changes provide additional clarity on market rules for NGR — including clarifying that such resources are subject to local market power mitigation and are not eligible to account for resource adequacy capacity.

“This is something that you would be doing irrespective of whether the EIM existed?” Howe asked, which Tretheway confirmed.

December 4, 2017

New England Grid Prepared for Winter Reliability

By Michael Kuser

ISO-NE forecasts sufficient resources to meet demand for electricity this winter and will implement special operating procedures to maintain reliability in the event of higher-than-projected demand, unforeseen generator outages or natural gas supply constraints that squeeze gas-fired power plants.

The RTO on Thursday issued its 2017/2018 winter outlook, which forecast peak demand under various scenarios:

21,197 MW at normal winter low temperatures of about 7 F; and
21,895 MW in extreme winter weather dropping to 2 F.

Resources with Forward Capacity Market (FCM) supply obligations total 30,999 MW; including resources without FCM obligations, capacity totals 32,521 MW.

Last winter’s peak demand of 19,647 MW occurred on Dec. 15, 2016, between 5 and 6 p.m., while New England’s all-time winter peak of 22,818 MW occurred on Jan. 15, 2004.

Gas Concerns

The report highlighted “a continuing concern” that “the region’s natural gas delivery infrastructure has expanded only incrementally, while reliance on natural gas as the predominant fuel for both power generation and heating continues to grow.”

ISO-NE said 4,000 MW of natural gas-fired generating capacity is at risk of not being able to get fuel when needed.

The RTO said the retirement of the 1,500-MW coal- and oil-fired Brayton Point power plant in Somerset, Mass., in May removed a facility with stored fuel that helped meet demand when natural gas plants were unavailable.

ISO-NE cone cost of new entry winter reliability — The Brayton Point Power Station in Somerset, MA went offline in June 2017.

The grid operator is again running its Winter Reliability Program, which provides incentives for demand-side resources and generators that stock up on oil or contract for LNG. The program, which runs from Dec. 1, 2017, through Feb. 28, 2018, will be replaced by new capacity market performance incentive rules that go into effect June 1, 2018.

Total energy consumption and peak demand have been flat in New England in recent years because of increased energy-efficiency measures and behind-the-meter solar photovoltaic (PV) systems. Both the normal and extreme peak demand forecasts include the 1,832 MW in energy savings from EE acquired through the capacity market. While PV helps reduce energy consumption during sunny winter days, demand peaks in winter after the sun has set. By reducing demand on sunny days, PV can help preserve other fuels for use when demand is peaking.

December 4, 2017

Ruling Casts Doubt on Fate of Big Rivers Coal Plant

By Amanda Durish Cook

The prospects became bleaker for one Big Rivers Electric coal-fired generator last week after FERC declined to rehear an earlier ruling that denied a bid to extend interconnection rights for the Kentucky plant.

FERC earlier this year rejected Big Rivers’ initial request to keep its Coleman Station interconnected to FERC Refuses Interconnection Extension for Big Rivers’ Plant.)

In its rehearing request, Big Rivers did not challenge the commission’s earlier refusal to extend the rights, but instead argued that a “termination of interconnection service for the Coleman Station could potentially harm reliability and impose increased costs on Big Rivers’ members.”

FERC disagreed with that contention (EL17-15-001).

“Big Rivers cites no specific evidence in support of its claim that there are potential adverse impacts on system reliability due to termination of interconnection service to the Coleman Station,” the commission said in its Nov. 27 order. “Moreover, we note that MISO evaluated reliability concerns associated with the suspension of the Coleman Station when Big Rivers submitted its Attachment Y notice to suspend its operations.”

The commission’s ruling once again pointed out that Coleman cannot return to service until it complies with EPA’s Mercury and Air Toxics Standards. It also noted the plant does not currently have load to serve since the nearby Century Aluminum smelter — once the plant’s primary customer — completed load curtailment arrangements.

ferc big rivers electric — Employees in front of the Coleman Station in June 2017 | *Big Rivers*

“Big Rivers itself acknowledges that the decision of whether and when to return the Coleman Station to service will be a complicated one. It thus appears that the Coleman Station may not be returned to service regardless of whether its interconnection service is reinstated,” FERC said.

‘Not Unique’

In early October, Rep. Brett Guthrie (R-Ky.) wrote to Chairman Neil Chatterjee urging a “full and fair consideration” of Big Rivers’ request for rehearing.

But FERC said the challenges facing the nearly 50-year-old Coleman are commonplace: “While we appreciate the difficulties facing Big Rivers with regard to the future disposition of the Coleman Station, its circumstances are not unique. There are likely other generators that are currently uneconomic that would, if possible, reserve their interconnection service indefinitely in the hopes of future market changes.”

Big Rivers also argued that FERC was still allowing for disparate treatment of generators. While Coleman never had a generator interconnection agreement (GIA) with MISO, the RTO would be prohibited from cutting service to a generator operating under a GIA, the company contended.

FERC said the result would be the same, GIA or not, “because Big Rivers had not satisfied the requirement of taking ‘significant steps to maintain or restore operational readiness … as soon as possible.’”

Big Rivers additionally filed a motion in September asking FERC to consider the “evolving status of MISO’s policies on replacing retiring generation facilities and the interplay of MISO suspension, retirement and SSR rules.” MISO officials and stakeholders are currently considering whether SSR units facing terminations should be able to maintain service even after contract expiration in order to allow them to participate in the RTO’s annual capacity auction.

“Although styled as a motion to clarify the record, Big Rivers seeks to reopen the record and lodge the two MISO presentations for commission consideration,” FERC responded. “Evidence that MISO and its stakeholders are in the process of considering changes to the Tariff that may allow generators to retain interconnection rights following retirement do not constitute a ‘change in core circumstance’ at ‘the very heart of the case.’”

December 4, 2017

SoCalGas Pipeline Losses Spur Curtailment Warnings

By Jason Fordney

The loss of three natural gas pipelines is creating major concerns about Southern California’s gas and electricity supplies, with three state and local regulators saying that Los Angeles-area electricity generators could experience gas curtailments this winter.

The California Public Utilities Commission, California Energy Commission and Los Angeles Department of Water and Power (LADWP) last week issued a new assessment of the situation suggesting that curtailments are more likely this winter than last because of pipeline ruptures — but much will depend on the weather. Southern California Gas’ Line 235-2 ruptured on Oct. 1 and also damaged Line 4000, adding to an existing outage of Line 3000, according to the report.

SoCalGas natural gas pipeline — Southern California has three natural gas pipelines out of service

“Natural gas service is threatened to noncore customers, including electric generators, this winter,” the report said. “This threat occurs even though there is more gas in storage than at this time last year.”

The concerns arose even after SoCalGas’ Aliso Canyon gas storage facility resumed injections in July, despite objections from state agencies. (See Aliso Canyon Resumes Injections.) Operations at the facility had been halted following a massive methane release detected in October 2015 and finally plugged in February 2016. The California Division of Oil, Gas and Geothermal Resources determined it is safe for the company to resume injections at the site.

The agencies issuing last week’s report said that other actions under consideration include an emergency moratorium on new natural gas service connections in the Los Angeles County area served by Aliso Canyon.

“Another proposed measure would direct electricity generators to more frequently shift generation to facilities located outside the SoCalGas system to reduce gas use in December,” the agencies said. “This could allow SoCalGas to preserve storage inventories deeper into the winter.”

The report also said LADWP could delay electrical transmission upgrades until February in order to maintain access to power sources outside the region. The agencies are additionally considering slightly increasing the volume of gas that can be stored at Aliso Canyon.