Page 1292 – RTO Insider

August 11, 2017

NEPOOL Markets Committee Briefs

ISO-NE on Tuesday advanced the idea of excluding competitive new resources from functioning as demand in a proposed “substitution” capacity auction, which is designed to enable generators with retirement bids that cleared in a primary Forward Capacity Auction to transfer their obligations to subsidized resources that did not clear because of the must-offer price rule.

The grid operator proposed the exclusion to help keep Forward Capacity Market prices competitive and maintain its “cash for clunkers” framework for retiring aging fossil fuel generators.

ISO-NE NEPOOL markets committee — Real-Time Marginal Units by Fuel Type | *ISO-NE*

ISO-NE economist Christopher Geissler presented the RTO’s conceptual approach to Competitive Auctions with Sponsored Policy Resources (CASPR) to the New England Power Pool Markets Committee, which met Aug. 8-10 at Cape Neddick, Maine.

CASPR is designed to accommodate the entry of “sponsored” resources — such as resources mandated by a renewable portfolio standard or other state policy — into the FCM over time, while maintaining competitively based capacity prices for other resources. The RTO’s latest proposal comes in response to stakeholders concerned that sponsored policy resources could unfairly reduce primary FCA prices and crowd out competitive generation. (See Public Power Skeptical of ISO-NE Two-Tier Capacity Auction.)

Part of the grid operator’s Integrating Markets and Public Policy (IMAPP) initiative, the latest proposal is intended to head off stakeholder concerns about competitive resources “walking down the demand curve” of the FCA by ensuring that the substitution auction coordinates entry of sponsored resources and exit of older generators.

To limit the potential ability of public entities to reduce consumer costs by sponsoring lower-cost (e.g., combined cycle/combustion turbine) resources, stakeholders had suggested imposing additional restrictions on the types of capacity eligible to participate as supply or requiring additional documentation to show that the resource was being built to meet a public policy need.

ISO-NE said it does not plan to propose rules that would require the RTO to evaluate whether a sponsored resource meets public policy needs. The grid operator said its two-tier auction proposal “incents the continued participation of competitive new resources in the FCM, when market conditions allow.”

IMM: Spring 2017 Energy Costs up on Gas Prices

Higher natural gas prices drove ISO-NE wholesale market costs up 26% this spring compared with a year earlier, to $1.3 billion.

ISO-NE Director of Market Monitoring and Compliance Robert Laurita presented the Internal Market Monitor’s Spring 2017 Quarterly Markets Report, attributing most of the gas price increase to March, when gas prices jumped 127% from the same month in 2016 because of significantly colder temperatures.

Gas prices averaged $3.59/MMBtu, up 54% compared with spring 2016, which saw unusually low prices because of increased production, above-average storage and low heating demand during the winter. Spring 2017 gas prices were 18% below 2015 levels.

Hourly electricity demand averaged 12,853 MW, comparable to last spring because of similar weather conditions, the report said. March was unseasonably cold, while April and May saw slight reductions in load compared to the same months in the previous year.

Day-ahead and real-time energy market prices at the New England Hub averaged $30.78/MWh and $31.92/MWh, respectively, up 32% and 44% from last spring. Energy prices continued to closely track underlying natural gas prices. The positive deviation in real-time prices for the period was driven by several days with high loads and unit outages during early April, as well as two days in mid-May when high temperatures resulted in higher loads than forecasted. In addition, several units experienced forced outages.

Northern Discounts

Energy prices among the load zones deviated only in Maine, New Hampshire and Vermont, which had lower average prices than the hub. These discounts were the largest — in both dollar and percentage terms — over the two-and-a-half-year period assessed by the Market Monitor. Discounts from the hub ranged from 6% in Vermont to 16% in Maine.

The report attributed the differentials to the prevalence of renewable generators in those export-constrained areas, as well as “various planned and unplanned line reductions or outages during the period that further reduced the transmission capability available to export power to the rest of the system.” The discounts were “less pronounced” in the day-ahead market.

Real-time reserve payments for the season totaled $8.9 million, well more than last spring’s total of $700,000 and 33% above the 2015 total of $6.7 million. This spring’s payments primarily accrued over May 18-19, which accounted for 54% ($4.8 million) of the credits. Those two days saw the grid operator frequently redispatch generation to maintain reserves. Deficiencies several times triggered the reserve constraint penalty factors for 10-minute spinning reserves and 30-minute operating reserves.

FCA Payments Stable

Spring 2017 coincided with the last three months of the commitment period associated with FCA 7, in which the NEMA-Boston zone cleared at $15/kW-month for new resources and $6.66/kW-month for existing resources, while Rest-of-Pool cleared at the floor price of $3.15/kW-month. Capacity payments for the season totaled $287 million and were within 1% of spring 2016 payments. Peak energy rent adjustments remained relatively high at $26 million because of the high real-time energy prices occurring in August 2016.

ISO-NE in April held the forward reserve auction for the summer 2017 delivery period, which saw supply offers exceed the requirements for both the 30-minute operating reserve and 10-minute non-spinning reserve, with no pivotal suppliers. The clearing prices for offline 30- and 10-minute reserves for the control area were $1,000/MW-month and $2,000/MW-month, respectively. Summer 2016 10- and 30-minute reserves cleared at $2,000/MW-month and $2,498/MW-month, respectively. Of the three local reserve zones, only NEMA/Boston had a different price than the control area. Because of inadequate supply (meaning all suppliers were pivotal suppliers), the 30-minute reserve price for NEMA/Boston was set to the auction’s offer price cap of $9,000/MW-month, the same outcome as the summer 2016 auction.

— Michael Kuser

August 11, 2017

Wary FERC Approval for Powerex EIM Agreement

By Jason Fordney

FERC staff have accepted CAISO’s implementation agreement for Canadian energy marketer Powerex to join the Western Energy Imbalance Market (EIM) but cautioned that the arrangement could be subject to further scrutiny once the commission meets after restoring its quorum.

“Preliminary analysis indicates that CAISO’s proposed implementation agreement has not been shown to be just and reasonable and may be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful,” FERC staff said in its delegated order (ER17-1796).

The order’s language suggests that the commission could compel the ISO to address certain EIM stakeholder concerns about the agreement. FERC’s quorum was restored Thursday with the swearing in of former Pennsylvania Public Utility Commissioner Robert Powelson, joining former Senate Republican aide Neil Chatterjee, whom President Trump named acting chairman. (See Chatterjee Named Acting FERC Chair as Quorum is Restored.)

Powerex, which markets hydroelectric generation from parent BC Hydro, finalized the agreement with CAISO in May after announcing its intention to join the West’s only real-time energy market. (See Powerex Slated to Become First Non-US EIM Member.) The company’s membership would provide the EIM increased access to about 17,000 MW of generating capacity, about 12,000 MW of which is hydro. Powerex currently markets power across the U.S. and as far south as Mexico.

FERC CAISO EIM Powerex — Powerex markets BC Hydro output from assets such as the Mica Dam on the Columbia River

In filings with the commission, some commenters raised concerns about “the principles set forth to guide the negotiation and implementation of additional agreements necessary for Powerex’s EIM participation,” as well as potential changes to the EIM framework that would be required to integrate the company into the market, FERC said.

CAISO said that the specifics of Powerex’s participation in the EIM will be detailed in separate filing to FERC before the company is integrated. The ISO has told FERC that concerns about the way Powerex is integrated are beyond the scope of the proceeding and can be addressed in future filings.

“The implementation agreement does not establish binding terms for Powerex’s participation in the EIM but merely commits the CAISO and Powerex to work in good faith to reach agreement on an acceptable framework,” CAISO said in a July 14 answer to filed comments. As a Canadian entity, Powerex has unique legal and regulatory circumstances, but that does not mean that it will be subject to a different set of rules than other EIM participants, CAISO said.

EIM participants Pacific Gas and Electric and Southern California Edison did not oppose the Powerex integration and did not ask for it to be modified.

Market participants are concerned, however, about a provision in the agreement that allow it to be modified to include additional parties, which they say is unique to the Powerex integration. CAISO would be required to make additional filings to explain why the agreement should be modified to allow additional parties, which the grid operator said is not currently being contemplated.

In a joint filing with FERC, EIM participants — including PacifiCorp, Idaho Power, Portland General Electric, Puget Sound Energy and NV Energy — said that Powerex’s entry is a new model because it is a merchant market participant that is not located within or pseudo-tied with any EIM participant. They were concerned about provisions in the agreement that enable Powerex to enter into non-EIM transactions after submitting its base schedules to the market.

EIM entities that enter into transactions after the submission of base schedules can be subject to energy imbalance charges. The companies said CAISO should explain whether Powerex will be subject to the same bidding deadlines and charges, “or will be the only merchant participant permitted to enter modifications to base schedules as if it were an EIM entity.” They said they “look forward to the development of subsequent agreements with Powerex and BC Hydro that demonstrate uniform (not just compatible) market rules are applied to all market participants.”

The implementation agreement becomes effective Aug. 15, with Powerex slated to join the EIM in April 2018.

August 10, 2017

NYISO Business Issues Committee Briefs: Aug. 9, 2017

RENSSELAER, N.Y. — NYISO’s Business Issues Committee on Wednesday approved steps intended to improve the efficiency of the interconnection queue process while maintaining needed reliability evaluations. The committee voted to recommend that the Management Committee approve the changes at its next meeting on Aug. 30. NYISO foresees filing associated Tariff changes with FERC in late September following Board of Directors approval next month.

Thinh Nguyen, NYISO interconnection projects manager, led an Aug. 9 presentation detailing changes to increase administrative efficiency and speed up the interconnection study process. Those changes should allow developers to move through the queue more quickly, particularly the Class Year Study phase, which evaluates the cumulative impact of a group of projects that have reached similar milestones. New rules that bifurcate the class year to allow some projects to advance have the potential to shave nine months off the phase.

The proposed changes clarify and update existing practices and procedures, except for the transmission interconnection procedures, which have already been filed with FERC and are still pending acceptance.

NYISO proposed effective dates and transitional rules that would allow projects currently in the interconnection process to benefit from the proposed changes. Proposals requiring Tariff revisions will become effective the date of the FERC order accepting the revisions, unless otherwise specified.

Market mitigation analyst Lorenzo Seirup assisted with the presentation, as did Market Manager Gregory R. Williams and Zachary T. Smith, installed capacity (ICAP) market operations supervisor.

ICAP Manual Changes for Demand Curve Reset Updates

The BIC approved ICAP manual revisions needed to reflect the process changes stemming from the ISO’s demand curve reset.

Smith presented the proposed revisions, which reflect Tariff changes that lengthen the period between demand curve resets and implement an annual update process.

The initial updates to the manual include quadrennial reviews of both the demand curve adjustment process and the annual update process. NYISO also removed language that merely repeated what is stated in the Tariff.

Changes also indicate that the results of each annual update will be posted on or before Nov. 30 of the year prior to the start of the capability year for which updated ICAP demand curves will apply. Based on a stakeholder comment at the July 27 ICAP Working Group meeting, language was added stating that NYISO will present the results to stakeholders.

NYISO Prepares DER Pilot Program Framework

The BIC also heard about NYISO’s pilot program to test the ability of the Bulk Electric System to adapt to distributed energy resources. The two-year pilot is slated to begin in April 2018.

NYISO Market Design Specialist Brian Yung presented a DER Pilot Program framework, which aims to assess the capability of DER to provide benefits to the wholesale market, develop performance measurement standards and establish and evaluate coordination between the ISO and DER aggregators.

The ISO’s DER Roadmap outlines its plans for integrating DER into its ancillary services, capacity and energy markets over the next five years and also pledges the grid operator to establish pilot programs. (See NY DER Question: Deployment or Markets First?)

The framework sets a statewide enrollment limit of 50 MW at any one time, with a maximum of 10 MW in enrolled capability serving a single transmission node. The limits are intended to minimize market and operational impacts at the node. NYISO also proposes a maximum of five individual pilot projects at any one time but will consider adjusting this limit based on staffing requirements and other factors.

The program limits individual pilot projects to a minimum of 100 kW of aggregated capability for energy and reserves, 200 kW for regulation service and a maximum of 10 MW of aggregated capability — and sets a 12-month cap on project duration. NYISO can either extend or stop an individual project to meet program objectives.

Resources participating in the wholesale markets — except for demand-side resources — will not be eligible to participate in the pilot program. NYISO will review wholesale market demand-side resource participation on a case-by-case basis to ensure the resource can meet its existing wholesale market obligations while participating in the pilot.

The ISO will select proposed pilots based on how well they can demonstrate energy and/or ancillary services, blend of resource types, technology maturity, DER and aggregation deployment experience, and testing availability. Preference will be given to proposals that can meet the desired six-second telemetry scan rate. The program will focus on testing the technical capabilities of aggregations rather than price signaling, NYISO said.

One market participant recommended that the grid operator work with the New York State Energy Research and Development Authority to market the program. Others said that a highly public rollout would improve the success of the program, and that the ISO should make clear whether the program includes aggregated storage.

— Michael Kuser

August 10, 2017

CAISO Resettling 2016 Demand Response Results

By Jason Fordney

SACRAMENTO, Calif. — While CAISO has in recent years made strides in incorporating demand response into its wholesale market, it was forced to recalculate its 2016 DR settlements because of missing performance data, the grid operator said Tuesday.

ISO representatives, DR companies, utilities and others industry participants met with state regulators to discuss the challenges associated with implementing more DR into grid operations and markets.

CAISO Infrastructure and Regulatory Policy Manager Jill Powers said the grid operator last year altered its market models to make DR registration and ISO modeling more efficient. But problems within the legacy DR system resulted in settlements that relied on incomplete and missing performance data.

The ISO reprocessed all 2016 DR performance data, which will be reflected on the next settlement recalculation statements for DR providers. Full resettlement is due to be completed by October. The ISO next year will replace its legacy DR process with “more robust systems,” she said.

“We have taken corrective actions for all the dates identified,” Powers said.

CAISO in 2015 implemented a program that allowed emergency-triggered DR to offer spinning reserve services into the ISO market. San Diego Gas & Electric began providing non-spin and spinning reserve market services through the program that same year.

demand response caiso california energy commission — The California Energy Commission discussed progress on DR integration in Sacramento | © *RTO Insider*

The grid operator is currently managing a number of initiatives regarding integration of DR and distributed energy resources. The ISO’s Board of Governors last month approved a package of market rules that included new baselines to better reflect the performance of various types of DR. (See CAISO Flex Capacity Effort Targets Increased Variability.)

CAISO’s 2016 enhancements significantly reduced processing timelines and management of new DR resources. They also implemented new sub-load aggregation point boundaries and relaxed telemetry requirements, which lengthened the scan rate when providing telemetry to help lower costs for DR.

An uncertain market structure and frequent rule changes are inhibiting expansion of DR, as well as increasing complexity of integration, EnerNOC Director of Regulatory Affairs Mona Tierney-Lloyd said. There are inconsistencies between CAISO rules and Public Utilities Commission rules and frequent changes in program requirements, she said. EnerNOC supplies DR services around the world.

California Energy Commission Chair Robert Weisenmiller said that integrating DR is “a very challenging area.”

“We are moving to a system that is going to be highly decentralized, and we are going to need visibility and automation to manage it,” he said.

On Wednesday, the commission adopted new guidelines for ensuring that publicly owned utility resource plans comply with requirements from SB 350, the 2015 law that included new greenhouse gas emission reductions and increased renewables procurement for utilities.

August 10, 2017

Status Quo Kept for MISO Steering Committee Selection

By Amanda Durish Cook

MISO’s Advisory Committee sectors voted against a proposal to allow stakeholders to annually elect leaders of the RTO’s Steering Committee through an independent nomination and voting process.

The outcome of the email ballot will keep intact MISO’s eight-year-old practice of automatically appointing the chair and vice chair of the Advisory Committee to serve in their opposite capacities on the Steering Committee. The motion, which failed 7-11 with two abstentions, would have permitted Steering Committee leaders to be selected in a process identical to that of the Advisory Committee.

MISO’s Transmission Owners sector had requested the vote to grant the Steering Committee greater independence from the Advisory Committee, which in June decided to delay action on the proposal. (See MISO Steering Committee Elections Decision Delayed.)

MISO steering committee advisory committee — MISO Advisory Committee discusses Steering Committee leadership in June | © *RTO Insider*

“There is an interlocking nature between the Advisory Committee and the Steering Committee,” current Steering Committee Chair — and Advisory Committee Vice Chair — Tia Elliott said during a July 26 Advisory Committee conference call. She said both committees receive stakeholder committee reports and work together to select topics to discuss before the Board of Directors.

MISO Stakeholder Relations Specialist Alison Lane said the Steering Committee began as an ad hoc group to assist the Advisory Committee in “managing the many different topics and charters of the many working groups and task forces” that existed at the start of the RTO’s market.

Ameren’s Ray McCausland said MISO at that time was “a small, start-up RTO” and the “flip-flop” leadership was put in place because there weren’t many stakeholder volunteers from which to choose.

With the stakeholder redesign two years ago, the Steering Committee took on an expanded role, with more authority to update MISO’s Stakeholder Governance Guide, which provides the governing guidelines to stakeholder committees. The redesign also dictated that issues must first be submitted to the Steering Committee for committee assignment in order to be discussed in stakeholder meetings or added to the Market Roadmap list of market improvements.

“The genesis of this proposal really goes back to the stakeholder redesign effort,” said Entergy Vice President of Federal Policy Matt Brown, whose TO sector submitted the unsuccessful motion. “We think it would be more effective and an improvement to directly elect those leadership positions. It’s really just housekeeping — or routine maintenance might be a better way to put it — to improve Steering Committee leadership. It’s anomalous right now. Every other MISO stakeholder committee leadership is elected.”

Brown pointed out that under the proposal, Advisory Committee leadership would still be eligible to run for Steering Committee leadership, albeit alongside any other interested stakeholders. “There’s no reason to restrict anyone from running for the office,” he said.

August 10, 2017

Chatterjee Named Acting FERC Chair as Quorum is Restored

By Rich Heidorn Jr.

FERC’s quorum was restored Thursday as former Pennsylvania Public Utility Commissioner Robert Powelson was sworn in, joining former Senate Republican aide Neil Chatterjee, whom President Trump named acting chairman.

The filling of the third seat allows FERC to issue rulings in contested cases, which had come to a standstill when former Chairman Norman Bay resigned in February after Trump named Commissioner Cheryl LaFleur acting chair.

ferc powelson chatterjee — Chatterjee (L) and Powelson at their Senate confirmation hearing | © *RTO Insider*

Chatterjee will serve as acting chair pending the confirmation of Republican attorney Kevin McIntyre, whom Trump selected to hold the gavel and direct the commission staff. McIntyre and Democratic Senate aide Richard Glick are scheduled to have confirmation hearings before the Senate Energy and Natural Resources Committee on Sept. 7.

“I want to thank Chairman LaFleur for the tremendous work she’s done in guiding the agency,” Chatterjee said in a statement. “The absence of a quorum was unprecedented, yet she rose to the challenge and created stability through her unwavering leadership.

“I look forward to working with Commissioner LaFleur and Commissioner Powelson on behalf of the American people. And I hope that we will have all five Commissioners here soon with the confirmation of Kevin McIntyre and Rich Glick.”

Chatterjee and Powelson were confirmed by the Senate on Aug. 3. Chatterjee was sworn in Aug. 8. (See FERC Quorum Restored as Powelson, Chatterjee Confirmed.)

The new commissioners were not immediately available for comment.

ferc chatterjee powelson — Chatterjee | © *RTO Insider*

FERC also announced that it will resume its monthly open meeting schedule next month, with the first meeting set for Wednesday, Sept. 20.

With the quorum restored, Chatterjee said, the commission will soon begin notational votes on its backlog of dockets.

FERC staffers have been acting since Feb. 4. under limited delegated authority that allowed them to grant waivers and approve settlements in uncontested cases, as well as take interim action on rate filings, subject to refund pending further orders by the commission.

According to LaFleur, FERC has issued only a fraction of the 100 commission-authorized orders it averages a month.

The delegation period will end in two weeks following the restored quorum.

August 9, 2017

Solar Powers NY City Council Candidate

By Michael Kuser

NEW YORK — Keith Powers attracted attention in energy circles last month when he wrote an op-ed in Crain’s New York Business advocating that solar panels be floated on the Central Park reservoir.

solar power Keith Powers — Keith Powers, Democratic Primary Candidate for NY City Council | © *RTO Insider*

The park abuts the 4th City Council District — the “Silk Stocking District” — from which Powers is running for a seat. He faces eight rivals in a Democratic primary Sept. 12.

When he spoke to RTO Insider at Times Square early this month, Powers had just been endorsed by the New York League of Conservation Voters, a statewide environmental organization that advocates for clean water, clean air, renewable energy and open space through political action.

“I’ve had very good feedback on my idea to put solar panels in Central Park,” Powers said. “There was a discussion on Mayor Bill de Blasio’s plan, which he calls 80 x 50, to tackle climate change, a very ambitious plan whereby New York City’s greenhouse gas emissions will be 80% lower by 2050 than in 2005. The mayor talks about environmentalism and has big ideas and a plan, so if I’m going to be down at City Hall, I need to be working to make that plan a reality.”

Can New York City on its own create a plan and follow through to reduce its carbon footprint?

“Not only create and follow through,” Powers answers, “but also show the world that a big city can achieve it, can think outside the box, can very realistically help the world tackle climate change.”

Why Floating Solar Panels?

Powers gained government experience working for the State Senate and serving as chief of staff for a member of the State Assembly. Before running for City Council, he was a vice president at Constantinople & Vallone Consulting, a lobbying firm.

He said his point in writing the op-ed piece was to propose something that had not been spoken about so far.

“The district I’m running in includes parts of Times Square, Bryant Park and Museum Mile, all the way up to the Upper East Side, so it truly is the world’s city council district,” he said. “It’s important that the person representing it thinks bigger than just local politics. New York City on its own can be both a global leader on particular issues, but also can solve certain issues just based on the density of the population.”

Solar panels would not detract from the recreational role of the reservoir in Central Park, while their presence would send a powerful signal on the city’s commitment to renewable energy, Powers said.

California is also considering floating solar panels on reservoirs because, aside from the power generation, they also decrease water loss through evaporation and prevent the kind of algae blooms currently afflicting the Central Park reservoir. The cooling effect of the water also increases the efficiency of the panels.

Steal My Idea

“We haven’t seen floating solar in New York yet, but at this moment, when we have a federal government that’s not looking to tackle climate change — in fact doing the opposite — we have cities that are trying to do that work on their own,” Powers said. “We have a very uncertain future in terms of the planet we live on, so not to put all ideas forward would be a missed opportunity.”

Powers wants people to visit New York City and say “our city should be doing that.”

“Philadelphia has a website that features what’s going on in other cities and it’s titled ‘Ideas We Should Steal’ — and I wanted this to be an idea other people would want to steal,” he said. “And many of the ideas featured on that website are from New York City. We learn from each other. I learned of floating solar because I saw that China was doing it. Ideas adapt and migrate, just like birds.”

Huainan Solar Farm in China | *Sungrow Power Supply*

A lifetime resident of the city, Powers looks to young people to bring about change over the long term — especially to public schools to equip youth with the tools to generate ideas.

“One in 300 Americans are in the New York City public school system, and solving issues like poverty or creating a cure for the next disease can come directly out of our schools,” Powers said. “When we talk about environmental issues, there’s no better way than schools for getting both our students and our city better equipped to deal with the future in terms of climate change.”

Better Buildings

Powers noted that his district has some of the poorest air quality in the city, mainly because its buildings are big polluters.

“We don’t think of buildings that way; we think of vehicles and factories, but our worst polluters in this city are the buildings that we live in,” Powers said. “With new development, we have an opportunity to change the standards and make them more eco-friendly. But with our aging infrastructure, many of the buildings are polluters, so we have bad air quality in Manhattan, period, and my district ranks badly because we’re so dense and have so many big buildings. A lot of the new office buildings are LEED-certified and very progressive in terms of their standards, but old residential buildings keep burning that dirty fuel oil.”

Changing human behavior is the most difficult part, he said.

“We can build nice buildings with the newest technology, but we still have to change human perceptions of what is right,” Powers said. “There is social pressure, the ‘do-good factor.’ And I think it’s great if a company thinks it can win public favor by being a better corporate citizen. But we all go home somewhere every day, and I think a lot of homes are still five to 10 years away from the technology that can really make them energy efficient.”

August 9, 2017

DTE Initiates Last-Ditch Effort in Clean Air Act Case

By Amanda Durish Cook

DTE Energy is making its last stand in a seven-year battle to avoid paying out millions of dollars in penalties after being found to have improperly accounted for emission increases stemming from upgrades performed at a coal plant.

The Michigan-based utility filed a writ of certiorari last week asking the U.S. Supreme Court to review a lower court’s ruling in favor of EPA in the case, in which the agency argued that the company upgraded Unit 2 at its Monroe plant without considering the resulting increase in emissions.

DTE energy supreme court clean air act — DTE Energy’s Monroe Power Plant | *Port of Monroe*

The 6th U.S. Circuit Court of Appeals declined to rehear the decision, upholding EPA’s power to halt construction at power plants the agency believes have not properly accounted for possible added air pollution (14-2274 and 14-2275).

“Left standing, the decision … threatens to paralyze substantial maintenance projects throughout the nation,” DTE said in its petition. The company filed successfully in May to delay the issuance of a mandate in the case while it petitioned the high court.

EPA sued DTE in 2010 after the utility replaced boiler components at the Monroe plant without installing additional pollution controls. The agency alleged that DTE violated the Clean Air Act’s New Source Review (NSR) provision, which is designed to protect air quality when industrial facilities are newly built or modified.

DTE maintained that the higher emissions from the Monroe plant were a product of demand growth and not caused by the boiler improvements. The company also claimed the $65 million project was routine maintenance exempted from NSR permitting.

EPA called the project a major overhaul that should have included new pollution controls and asked for civil penalties of up to $37,500 per day. By 2014, DTE had installed four selective catalytic reduction units and four flue gas desulfurization units at the plant for a total of about $2 billion.

The company maintains that it properly evaluated whether the upgrade would trigger the “costly and time-consuming” NSR permitting process, but it found no projected emissions increase.

“To add insult to injury, the government seeks to penalize DTE for failing to make that demonstrably inaccurate preconstruction emissions projection,” the company said in the petition. The utility also called EPA’s suit “an Orwellian type of enforcement action.”

In a late July earnings call, DTE CEO Gerard Anderson reaffirmed the company’s recent public announcement to reduce its carbon emissions by more than 80% by 2050 by eliminating coal generation. Under the plan, the 46-year-old Monroe station would cease operations in 2040. DTE has not said how it plans to replace the generation.

August 9, 2017

CAISO Drops EIM Third-Party Transmission Plan

By Jason Fordney

CAISO has dropped a proposal that would have allowed third-party transmission providers to participate in the Western Energy Imbalance Market (EIM) after getting negative feedback on the plan — but also said it might revisit the idea in the future.

The grid operator proposed that transmission owners outside the EIM be permitted to provide service between EIM balancing authority areas (BAAs) and receive congestion revenue for increasing the market’s transfer capability. But CAISO determined that the TOs would be decreasing their own potential for collecting congestion revenue by providing the increased capacity, resulting in inadequate compensation. In addition, the ISO cannot pay directly for transmission service.

CAISO EIM wheeling — Diagram of Third-Party Transmission Service | *CAISO*

“There were concerns that implementing this would outweigh the benefits,” CAISO Senior Policy Developer Megan Poage said in an Aug. 7 call. “Many parties were not sure this would be fully used.” But she asked for more comment, saying that CAISO wanted to ensure that all stakeholders were on board with removing the proposal. While the ISO said the plan could be revisited, EIM entities were generally uninterested in using the functionality.

The grid operator floated the third-party transmission idea as part of its Consolidated EIM Initiatives straw proposal being developed with market participants. The initiative also includes new wheeling policies and tools to manage bilateral schedule changes. (See Consolidated EIM Proposal Effort Gets Underway.)

Imbalance Risks

Regarding the management of bilateral schedule changes, CAISO is trying to address the fact that EIM participants are exposed to unknown imbalance settlement payments for making changes not reflected in their base schedules. Prior to the development of the EIM, firm transmission holders could make schedule changes without facing later settlement payments, CAISO said.

CAISO Senior Market Designer Don Tretheway said that a stakeholder workshop on intertie bidding unearthed concerns that, prior to the EIM, transmission holders could make schedule changes up to a certain point without being exposed to later settlement payments. He said that EIM participants through their transmission tariffs could manage the exposure, and part of it could be solved through the wheeling functionality.

Some EIM participants said that bilateral schedule changes should be subject to imbalance energy charges because they can cause the BAA to incur redispatch costs, CAISO said. However, most feedback on the proposal was neutral. Some stakeholders did say the proposal does not address fundamental issues about the inability to hedge imbalance settlement charges.

Sharing Benefits

The consolidated initiative also aims to correct an inequity that occurs when an EIM BAA wheels power between other BAAs. Wheel-throughs are on the increase as the EIM footprint expands, but wheeling entities only receive congestion revenue.

“The entity in the middle right now receives no direct financial benefit for facilitating a wheel” if there is no congestion, Poage said. But “without them being there, that transfer would not have occurred.”

The issue will become increasingly important when Powerex is integrated into the EIM in April 2018, with Puget Sound Energy positioned to wheel power from British Columbia to the south. (See Powerex Slated to Become First Non-US EIM Member.) Wheel-throughs could also start occurring in more than one BAA.

The benefit-sharing is seen as essential for some to recover costs of power flows caused by EIM dispatches, and preventing perceived price distortions and free riders. CAISO is also paying attention to cost-shifting between TOs and customers because of the loss of transmission revenues, but it said the issue will not be considered in this initiative. Others say that BAAs doing the wheeling share in other benefits and that the benefit-sharing might reduce incentive to invest in EIM-dispatchable resources. Stakeholders also expressed concerns over rate pancaking and reduced liquidity.

CAISO compiled data on EIM transfers and BAA imports and exports within the market, and asked for help in determining the net benefit of facilitating a wheel-through transaction to better quantify the benefits of the proposal. The grid operator said that net wheeling will increase as the EIM footprint expands.

For more equitable sharing of wheeling benefits, CAISO proposed either an after-the-fact payment based on the amount of net wheeling, or a market-based method that allows for competition.

As part of the Consolidated EIM Initiatives, CAISO proposed a series of new functionalities including automatically adjusting schedules of non-EIM entities to eliminate the need for physical dispatch instructions, which also facilitates management of changes to bilateral schedules.

The EIM Governing Body has primary authority for approving the changes because the market rules would not be proposed absent the existence of the EIM. The body is due to review the proposals Oct. 10, which then go before the ISO Board of Governors on Nov. 1. CAISO is taking comments until Aug. 17.

August 8, 2017

PJM Stakeholders Envision Additional Capacity Designs

By Rory D. Sweeney

VALLEY FORGE, Pa. — And then there were nine.

Weeks after stakeholders introduced six proposals for redesigning PJM’s capacity construct, another three have materialized. Many of the nine are variations on a two-stage auction repricing structure, while others envision vastly different procedures.

All nine were presented and explained at a two-day meeting last week of the Capacity Construct/Public Policy Senior Task Force, which was created earlier this year to address concerns about state subsidies of generators undermining PJM markets. It has been moving to have an agreement endorsed and filed at FERC by the end of the year. PJM has held several two-day task force meetings to accommodate the depth of discussion stakeholders have demanded for the process. (See PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)

The proposals can be broadly categorized among those revamping the entire construct, developing repricing processes that accommodate subsidized units and extending a rule intended to eliminate the impact of subsidies.

The revamp proposals include full-scale redesigns from American Municipal Power and the Natural Resources Defense Council, and a limited revision to existing fixed resource requirement (FRR) rules called “Capacity Choice” proposed by John Horstmann of Dayton Power & Light.

The repricing proposals originated from a two-stage auction design by PJM. Many felt it unfairly discriminated against units on the margin in the capacity auction and proposed tweaks that would either reduce capacity awards (NRG Energy) or reduce the clearing price (LS Power). Another proposal would trigger repricing only if the clearing price rises to a level that incentivizes new generator construction (Exelon), while a fourth would calculate the clearing price by removing subsidized offers and scaling the remaining competitive offers to replace the shortfall (Old Dominion Electric Cooperative).

ODEC’s Mike Cocco said other repricing proposals utilize reference pricing schemes to replace the market offers from subsidized resources but failed to account for what would be corresponding change in the supply stack. ODEC’s proposal was designed to fully synthesize an auction as if subsidized units never existed and competitive units covered the entire demand.

“Once you open that door and decide you’re going to reprice with reconstituted offer prices, you have to open that door all the way,” Cocco said.

Monitoring Analytics, the Independent Market Monitor, proposed an extension of the existing minimum offer price rule that would require units to undergo analysis every year they receive subsidies without an exemption — requiring them to submit the variables and equation they used to calculate their offer. The Monitor would then review the submissions for competitiveness, much like it now does with fuel-cost policies and cost-based offers. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)

“If states want control over their assets, they should reregulate — and that’s fine,” Monitor Joe Bowring said. “If we’re going to have markets, we should have markets.”

James Wilson of Wilson Energy Economics also provided comments on the redesign proposals, arguing that “markets are not as fragile as some suggest.” With enough lead time, markets have a “substantial ability to absorb incremental/decremental resources with minimal impact on prices,” said Wilson, who consults for the consumer advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C.

He predicted that the process would settle on “some sort of two-tiered pricing,” for which he has concerns. He also expressed reservations about expanding the MOPR.

The comments found some favor with AMP’s Ed Tatum, who has argued the best solution is to replace reliance on the annual capacity auction with long-term bilateral contracts between generators and load-serving entities.

“With enough notice, the true market would be able to absorb these things,” he said.

He also liked Horstmann’s “Capacity Choice” proposal, which would allow LSEs to determine how they want to fulfill their capacity obligations, either through long-term contracts under the existing fixed resource requirement (FRR) rules, annually through the existing Reliability Pricing Model or some combination of the two extremes.

All current and future subsidized units would be required to choose the FRR option, which would eliminate their potential influence on the RPM auctions. The entity enacting the subsidy would have to elect how it would be funded through its rate base.

“This is kind of a different approach than some of the ones you’ve seen before,” Horstmann said. “As opposed to being told how to manage your capacity obligation, basically what I’m putting on the table here is you get to choose how to manage your capacity obligation.”

He outlined several as-yet unanswered questions but noted that because the structure is largely already approved by FERC, it would require minimal Tariff changes. He said he analyzed the stakeholder proposals to address as many interests as possible but couldn’t include all of them — such as proposals to trigger repricing.

“Clearly it doesn’t accommodate the one that doesn’t think there’s a problem,” he said.

CCPPSTF meeting underway | © *RTO Insider*

Going forward, PJM plans to distribute a poll to judge stakeholder interest in each of the proposals, including the status quo. The poll results, if emphatic, could determine the CCPPSTF’s ongoing direction and which proposals receive the most attention.

PJM is looking to schedule another meeting on Aug. 17, followed by meetings on Aug. 23, Sept. 11, Sept. 12 (if possible), Sept. 26, Oct. 16, Nov. 1, Nov. 21 and Dec. 11.