Page 1490 – RTO Insider

August 17, 2017October 31, 2023

Massachusetts Tightens GHG Limits for Generators

By Michael Kuser

Massachusetts regulators have issued new, stricter limits on greenhouse gas emissions from the state’s fossil fuel power plants and ordered utilities to buy at least 16% of their electricity from clean energy sources in 2018.

The regulations, announced Aug. 11 in response to a 2016 court order, include a Clean Energy Standard (CES) that requires utilities and competitive suppliers in the state to procure increasing amounts of electricity from clean energy sources every year, with the minimum percentage increasing 2 points annually to reach 80% in 2050.

The new rules also set annually declining limits on aggregate CO₂ emissions from 21 large fossil fuel-fired power plants in the state, from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. The regulations establish an allowance trading program for CO₂ emissions from generators, with allowance auctions beginning in 2019 and direct allocations for 2018. The rules offer flexibility in the form of limited allowance banking and a “deferred compliance” option to address electricity grid reliability.

allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER

The regulations also reduce allowable methane emissions from natural gas pipelines and distribution systems. They also tap the transportation sector by requiring state, city and regional transportation planning agencies to evaluate and report the aggregate GHG emissions of their facilities, fleets and programs.

The new procurement rules are like those of the Massachusetts Renewable Portfolio Standard, while the emissions targets are stricter than CO₂ limits under the Regional Greenhouse Gas Initiative, the cap-and-trade system agreed on by nine Northeastern states.

Pushed to Act

The state acted in response to a 2014 lawsuit by the Conservation Law Foundation that accused Massachusetts officials of failing to enact regulations needed to meet the targets set by the 2008 Global Warming Solutions Act. The state’s top court ruled in favor of CLF in May 2016.

CLF helped win passage of the climate change law, which requires Massachusetts to issue regulations to incrementally reduce greenhouse gas emissions each year.

“These rules re-establish the commonwealth as a national leader in developing sensible, enforceable standards to transition our economy to a low-carbon future,” CLF President Bradley Campbell said in a statement. “Much more needs to be done, and Gov. [Charlie] Baker’s leadership will be essential to getting neighboring states to take meaningful action to prepare New England for the energy future being shaped by the Paris Climate Agreement.”

20-year levelized cost of renewable energy resources | Mass. DOER

Last September, Baker issued an executive order that set a deadline of Aug. 11 for the secretary of energy and environmental Affairs and the Department of Environmental Protection to have “designed such regulations to ensure that the commonwealth meets the 2020 statewide emissions limit mandated by the GWSA.”

That limit — a 25% reduction in emissions below 1990 levels — was established seven years ago by the state to meet the GWSA requirement of a minimum 80% reduction by 2050. Officials estimate that by 2014, Massachusetts had already cut carbon emissions by 21% from 1990 levels.

“These regulations will help ensure the commonwealth meets the rigorous emission reductions limits established in the Global Warming Solutions Act in order to protect our residents, communities and natural resources from the effects of climate change,” Baker said.

Limited Effect on Consumers

The DEP concluded that the emissions targets and clean procurement rules would likely increase customer electricity bills by 1 to 2% per year.

The Bay State has been busy this year ramping up its environmental regulations. Officials earlier this summer announced that the state’s electric distribution utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020. (See Massachusetts Underwhelms with 200-MWh Storage Target.)

In late July, the state received more than half a dozen proposals to meet its call for 9.45 TWh a year of renewable generation. Projects will be selected next January, with contracts to be submitted in late April. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)

In response to public comment, the final CES included limited grandfathering to accommodate electricity sold in 2018 and 2019 under existing contracts. For the next three years, the alternative compliance payment rate is being increased to 75% of the RPS amount, but it will drop to 50% of the RPS amount in 2021. The use of banked clean energy credits is not allowed until 2021.

allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER

The RGGI emissions cap represents a regional budget for CO₂ emissions from the power sector, with each CO₂ allowance representing an authorization to emit 1 short ton from a regulated source. The nine RGGI states agreed on a 2014 cap of 91 million short tons. The CO₂ cap declines by 2.5 percentage points each year from 2015 to 2020.

August 17, 2017

Solar Eclipse to have Minimal Impact on SPP

By Tom Kleckner

Next week’s total solar eclipse will not disrupt SPP operations despite 100% obscuration levels in parts of its 14-state footprint, according to a report by RTO staff.

The eclipse will pass over North America on Monday, with parts of Nebraska, Kansas and Missouri experiencing totality — complete obscuration of the sun — for almost three minutes. Kansas City and Lincoln, Neb., are among the municipalities in the totality path. Other states in the SPP region will experience solar obscuration levels of 80% or more.

“The eclipse is expected to have some impact on resources and loads in our region,” said Lanny Nickell, SPP’s vice president of engineering.

The RTO expects to lose about 200 MW of solar PV generation during the height of the eclipse, assuming clear skies. The system currently has 215 MW of registered utility solar resources; SPP has identified another 111 MW of distributed PV on its system, including residential rooftop solar and commercial solar farms.

The eclipse will pass over the SPP footprint for about three hours, beginning at the western edge around 11:30 a.m. CT and ending at the eastern edge around 2:45 p.m.

Although solar generation will be reduced, the eclipse also will reduce air conditioning loads because of falling temperatures. But the temperature drop also will cut wind speeds, reducing wind generation, according to the report, which was prepared by a summer engineering intern. A drop in solar generation connected to the distribution system will appear as an increase in load from the transmission system’s perspective.

The report expects demand for lighting will increase during the eclipse, which would require additional generation.

“The eclipse is worthy of study in light of the increasing numbers of distributed generators in the SPP footprint,” the report said.

That study could come in handy in 2024, when another solar eclipse will cover Texas and Arkansas on its way to the Northeast. The National Renewable Energy Laboratory (NREL) projects the SPP region may have up to 1.1 GW of distributed PV in at that time.

Utility-scale solar is also likely to increase, given more than 7 GW of solar generation is being studied in the generator interconnection queue.

August 17, 2017

Ohio PUC Upholds FirstEnergy Subsidy

By Rich Heidorn Jr.

Ohio regulators on Wednesday rejected challenges to their order awarding FirstEnergy a subsidy worth more than $600 million, assistance the company said it needed to avoid having its credit rating reduced below investment grade.

The Public Utilities Commission of Ohio also rejected some rehearing requests by FirstEnergy while also granting others (14-1297-EL-SSO).

Opponents of the rider immediately vowed to appeal to the state Supreme Court.

In October, the commission unanimously rejected FirstEnergy’s request for an eight-year retail rate stability (RRS) rider totaling $4.46 billion, which the company said it needed to ensure its financial health at a time in which its coal- and nuclear-fueled generation is challenged by low natural gas prices.

Instead, the commission approved a three-year distribution modernization rider (DMR) totaling about $612 million for subsidiaries Ohio Edison, Cleveland Electric Illuminating and Toledo Edison. The commission said the additional money would allow the company to make investments in grid modernization. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)

Ohio firstenergy PUCO — Ohio Edison workers in a switchyard | *FirstEnergy*

In December, the commission agreed to consider FirstEnergy’s rehearing request, along with challenges by environmentalists, independent power producers, large customers and the Ohio Consumers Counsel (OCC).

In its unanimous ruling Wednesday, the commission said that it had already “thoroughly addressed” issues raised by OCC, the Northwest Ohio Aggregation Coalition, Cleveland Municipal School District and the Sierra Club. Commissioner Lawrence K. Friedeman recused himself.

It said the risk of FirstEnergy’s and its subsidiaries’ credit ratings dropping to below investment grade was “sufficient to constitute an emergency that threatens the utility’s financial integrity,” rejecting opponents’ claim that it should rely on the current credit ratings of the companies.

The commission also approved FirstEnergy’s request to strike portions of filings by the Ohio Manufacturers’ Association Energy Group, saying “new information should not be introduced after the closure of the record.” It also struck news articles included in filings by the Northeast Ohio Public Energy Council, which it said were hearsay.

In response to a request from FirstEnergy, it clarified its earlier ruling, saying that if Electric Security Plan (ESP) IV is terminated, the Rider Delivery Capital Recovery (DCR) revenue cap increases currently in place will continue until the commission establishes a new standard service offer (SSO). “If FirstEnergy exercises its right to terminate ESP IV at some point in the future following rehearing or an appeal, the Rider DCR revenue cap increases yet to be implemented at the time of termination will also be terminated along with the remaining provisions of ESP IV. However, FirstEnergy will be permitted to continue to recover costs already incurred under Rider DCR,” it said.

PUCO said it was “not persuaded by FirstEnergy’s assertion that DMR revenue could be recovered through a base distribution rate case. We do agree that certain costs of grid modernization, specifically the costs of any acquisition and deployment of advanced metering, including the costs of any meters prematurely retired as a result of the advanced metering implementation, may be recovered outside of an ESP [electric security plan]. Moreover, we also agree that the $568 million annual economic impact of the retention of the FirstEnergy Corp. headquarters is an economic benefit under the ESP and should be included as a consideration in the ESP versus MRO [market rate offer] test.”

Opponents of the rider reacted sharply, saying they will take their arguments to the Ohio Supreme Court.

“There is simply no basis in Ohio law to force utility customers to pay for a slush fund for FirstEnergy Corp. and its shareholders,” said Shannon Fisk, managing attorney at Earthjustice.

“We are very disappointed in the commission’s continued unwillingness to shield customers from FirstEnergy’s poor business decisions,” said Dan Sawmiller, senior representative for Sierra Club’s Beyond Coal Campaign. “The PUCO has missed yet another opportunity to focus the company on real efforts to modernize our electric grid and invest in new, clean energy technologies and instead has forced customers to pay up for unwise investments in outdated coal and nuclear plants.”

The Environmental Defense Fund said it was “confident the Ohio Supreme Court will … reject the regulators’ latest giveaway to dirty energy.”

FirstEnergy spokesman Doug Colafella said the ruling “affirmed the commission’s previous order that will help support future investments to modernize our electric system.”

“Grid modernization will benefit our customers and competitive suppliers by enhancing service reliability and enabling new products and services,” he said.

August 16, 2017

NY Clean Energy Commitment Spurs Procurement

By Michael Kuser

NEW YORK — While timelines for completing large power projects can be especially long in New York, developers are finding it easier to invest here now that the state is providing more predictability around clean energy procurement and market fundamentals.

That was the consensus of panelists discussing the impact of the state’s Clean Energy Standard (CES) on procurement at the Infocast New York Energy REVolution Summit held earlier this month at Times Square.

new york clean energy procurement — Procurement Panel (L-R) Noah Hyte,Cypress Creek Renewables; Karlis Povisils, Apex Clean Energy; Jack Godshall, Invenergy; Dennis Phayre, Entersolar; Doreen Harris, NYSERDA; and moderator Sean Garren, Vote Solar. | © *RTO Insider*

Gov. Andrew Cuomo’s Reforming the Energy Vision (REV) and its associated CES aim to meet two goals by 2030: a reduction in New York’s greenhouse gas emissions to 40% below 1990 levels and that renewables generate 50% of the state’s electricity.

To support those objectives, the governor in June announced the largest-ever state-mandated clean energy procurement, authorizing the New York State Energy Research and Development Authority (NYSERDA) and the New York Power Authority to oversee up to $1.5 billion of investment in major renewable energy projects, including offshore wind and solar.

“We’re encouraged by the number of projects, both in the interconnection queue at the ISO, and also in the pipeline of projects that are moving through Article 10,” said Doreen Harris, director of large scale renewables at NYSERDA. Article 10 is New York’s primary permitting process for authorizing the construction and operation of all utility-scale power projects 25 MW and above.

“It’s a good signal to us of the interest in New York and the supply that’s to come.”

Steady Wind

Harris said NYSERDA is focusing on three main areas around renewables: solicitation of long-term contracts; behind-the-scenes work running tracking systems and working with 152 load-serving entities; and aggressive pursuit of offshore wind.

Cuomo in January called for the development of 2,400 MW of offshore wind projects by 2030, starting with the 90-MW South Fork Project off Montauk, Long Island. (See New York Seeks to Lead US in Offshore Wind.)

“The way we are evaluating proposals is more complex than it used to be under the [renewable portfolio standard] in the sense that, first of all, we are looking to signal through some new threshold criteria the desire to really move projects through the pipeline in New York state,” Harris said.

Having the state replace goals with actual standards to achieve over five to 10 years “enhances the ability of developers to focus specifically on development of the best possible assets, with appropriate timelines,” said Jack Godshall, vice president of origination at Invenergy, the largest renewable energy provider in North America.

Firm procurement targets allow companies to spend time and capital developing assets for which they know there will be a market in coming years, Godshall said. “And that’s great for the state and also for the developers.”

Beneficial Load

Corporate clients deciding to “go solar” have shifted toward more and more larger procurements and off-site developments, according to Dennis Phayre, director of business development for EnterSolar, the top solar developer in New York.

Phayre (left) and Harris | © *RTO Insider*

“New York state now is limited to 2 MW on the distributed generation level, soon going up to 5 MW, but in our world, with the clientele we deal with, we certainly have to be looking at what comes beyond that,” Phayre said. “Having appropriate maturity barriers, so that we don’t have churn in awards, is super important to ensure that NYSERDA isn’t rebidding the same 100,000 MWh over and over again.”

NYSERDA Director of Policy and Regulatory Affairs John Williams said people tend to think of the DG outcomes of REV, but the program “always envisioned the supply side needing to undergo some pretty dramatic changes as well, and the Clean Energy Standard is the primary mechanism. When planning for a dynamic grid, we always imagined that there’s going to be a lot of dynamic activity on the supply side.”

Why all the focus on the power generation sector when it only represents about 20% of GHG in New York? Over the past decade, New York has nearly halved the sector’s GHG emissions, with an accompanying shift in load, according to Williams.

“The CES actually needs to take account of the shift of load,” Williams said. “We like to call it beneficial load, but clean energy-powered load only becomes beneficial to the degree that we can get consistent and continuous emissions reductions and a shift in that emissions profile in that electric generation sector. The value in an aggressive, continuous focus on power generation sector emissions is necessary because it winds up being the solution to emissions reductions that we need to see in other sectors.”

August 16, 2017

Great River Energy Seeks Test for Inverter-Based Generation

Great River Energy is urging MISO to account for the effects of inverter-based generation in the RTO’s transmission planning studies.

Inverter-based generation — often new technology resources asynchronously connected to the grid via an electronic interface — can harm reliability in weak power systems, Great River Energy’s Mike Steckelberg said at an Aug. 15 MISO Planning Subcommittee meeting. The Minnesota utility discovered the issue during a recent analysis, he said.

Great River Energy linemen | *Great River Energy*

Steckelberg cited a June NERC report warning that such resources can affect dispatch and reliability — including voltage control, frequency response and ramping — when too many of them are interconnected into weak power systems.

The company said MISO’s annual Transmission Expansion Plan study process should include screening for transmission with low short-circuit currents, comparing the megavolt-ampere level before a inverter-based resource is connected to the nominal power rating of that resource. If the calculation does not meet a certain threshold, MISO should remedy the transmission by modifying controls, connecting to a stronger source, planning for more transmission or reducing the size of the generation project.

“This is a fairly easy screen to be doing ahead of time,” Steckelberg said. While the screen would not have to be a “full-blown study,” it does need to be incorporated into MISO’s generation interconnection studies.

Steckelberg said MISO’s Interconnection Process Task Force and Planning Subcommittee both need to address the issue, and transmission owners and planners should be able to review new interconnection requests for low short-circuit current issues.

Entergy’s Yarrow Etheredge and American Transmission Co.’s Patrick Gerum said their companies shared GRE’s concerns.

Customized Energy Solutions’ Ginger Hodge asked for MISO’s response on the issue.

MISO Director of Planning Jeff Webb said he and his staff would review the request and put together a response at the Planning Subcommittee’s next meeting in October.

— Amanda Durish Cook

August 16, 2017

CAISO Demand Response Problems Erode Participation

By Jason Fordney

Frequent rule changes and an uncertain market structure are causing dissatisfaction among CAISO demand response providers and eroding participation in the programs, those providers say.

Problems with data verification and settlement required the ISO to recalculate its 2016 DR results, and providers say there are other issues with the program, which aggregates utility customers to facilitate their participation in the ISO’s wholesale markets.

“We have not received any energy payment of any dispatch of our resources going back to June 2016,” EnerNOC Director of Regulatory Affairs Mona Tierney-Lloyd told RTO Insider. While Tierney-Lloyd doesn’t think there are large payments still outstanding, “it is obviously sub-optimal,” she said.

EnerNOC and other companies aggregate retail electric customers and bid the load reductions into the CAISO market to offset the need for generation. Wholesale DR aggregates and compensates electricity users that reduce their consumption to below a pre-established baseline. Separately, utilities also maintain DR programs in which they provide customers a financial incentive to decrease load.

Tierney-Lloyd believes there are several factors causing the decline in DR program participation, including rule changes and modifications to the way DR resources are dispatched. There are also inconsistencies between CAISO and California Public Utilities Commission rules, she said. Agency misalignment is the primary cause of what she said is significant decline in DR program participation.

Participation in PG&E, SCE Demand Response Programs, 2011-2016 | *EnerNOC*

“It takes work on our side to get those customers familiar with those rule changes,” which also adds costs, she said.

During hot weather, it is more difficult for customers to reduce their usage below baseline, resulting in some taking efforts to reduce demand without getting paid. Others keep a close eye on CAISO operations and don’t understand why they are getting dispatches when no shortages are seen on the system.

CAISO uses DR as a way to make the grid more efficient and reduce greenhouse gases associated with climate change. While the ISO has a number of DR program improvements underway, its past problems slowed payments to market participants. (See CAISO Resettling 2016 Demand Response Results.)

In 2016, the DR system was sometimes unaware that an event had occurred, or the system did not deliver settlement data, CAISO said. The system was not receiving the correct “payload” to identify that a DR event occurred, so the system was unaware of the event and no performance measurement was completed. But even when the event day and historic meter data were available, the DR system in some cases did not send the values to the settlement system, so no settlement occurred. The ISO’s full resettlement should be completed in October.

The CAISO Board of Governors recently approved the second phase of a program meant to make distributed resource integration easier, dubbed the Energy Storage and Distributed Energy Resources (ESDER) Phase 2 proposal. (See New CAISO Rules Spell Increased DER Role.) ESDER includes a set of alternative energy usage baselines to assess the performance of proxy demand resources, one of a series of refinements to the DR program.

August 15, 2017

PJM PC/TEAC Briefs: Aug. 10, 2017

VALLEY FORGE, Pa. — PJM’s Michael Herman told members at last week’s Planning Committee meeting that proposed Manual 14B updates to incorporate modeling changes reflecting the cancellation of the Con Ed-PSEG “wheel” would include reductions in emergency transmission limits.

The capacity emergency transfer limits (CETLs) would be reduced in certain load deliverability areas (LDAs), including by 500 MW in EMAAC, 1,100 MW in MAAC, 1,527 MW in PSEG and 1,309 in PS North.

At PSEG, that would put the CETL at just 574 MW above the capacity emergency transfer objective (CETO), the threshold for necessary transfer capacity to ensure reliability in an emergency. In PS North, the difference between CETL and CETO would be just 335 MW.

The modeling adjustments come in response to Consolidated Edison’s decision to end a decades-long agreement with PJM to route 1,000 MW from upstate New York to New York City through Public Service Electric and Gas’ northern New Jersey territory. The change necessitated reanalysis of regional power flows, which eventually identified that continuing an “operational base flow” of 400 MW would be the most reliable solution. (See Analysis Recommends Continuing Reduced Con Ed-PSEG ‘Wheel’ for Grid Stability.)

Reliability Pricing Model PJM — Sims | © *RTO Insider*

In the updated CETL calculations, PJM removed any non-firm energy transfers. However, it kept them in its updated capacity import limit calculations. Stakeholders questioned why non-firm was removed from the CETL.

“If it’s a non-firm product, we just can’t depend on it during these critical times,” PJM’s Mark Sims said. “There could be a time when our system is stressed, the neighboring system is stressed, and then to depend on non-firm energy to support your system … just doesn’t make sense.”

The revisions were approved by acclamation with one objection and 14 abstentions.

PJM has scheduled a webcast on Aug. 30 from 1-3 p.m. to address questions about the CETL procedural changes.

Resilience Planning to Recognize Outage Propagation Potential

Sometimes, resilience means knowing when to give up.

In analyzing its planning criteria, PJM will be considering what is likely to happen downstream when a piece of equipment fails. Sometimes, this will mean the equipment simply collapses at that point. But it could also open a pathway for cascading failures further throughout the system and a larger collapse. (See “Resilience to Become Planning Driver,” PJM PC/TEAC Briefs: July 13, 2017.)

“If you had an existing station where you improved the strength of it such that during an event, where normally it would be lost very quickly and cleanly, it’s now hanging on,” Sims said.

As a result, the grid operator could face a scenario “where the system collapsed instead of being bounded because you actually have a stronger part of the system which allows the event to propagate further and in the end the result is worse,” he said.

To prepare for such a contingency, PJM is developing appropriate metrics and criteria for factoring resilience into planning.

“These are not events that happen often. I can’t pull data on voltage collapses,” Sims said. “We have to do our best to make some valid assumptions.”

Stakeholders have previously asked how PJM plans to address the subjectivity of the topic.

“To PJM, megawatts would just be load, but to others, megawatts are customers,” said John Farber with the Delaware Public Service Commission. He asked if PJM plans on considering the amount of load that would be impacted by a piece of equipment failing.

“I don’t know if you’re suggesting that some load is perhaps more critical than others, [but] I think many people would generally agree with that,” PJM’s Paul McGlynn said.

“I salute your eagerness to swim with the alligators,” Farber replied.

Market Efficiency Analysis Ongoing

Staff have completed analysis of market efficiency projects in the Reliability Pricing Model and are nearly finished examining interregional projects, Sims told members at last week’s Transmission Expansion Advisory Committee.

The RTO is currently reviewing projects from PPL’s zone.

The analysis identified six projects to be recommended for approval by the Board of Managers, including four in Commonwealth Edison’s LDA and one in Duke Energy Ohio/Kentucky. Two of the ComEd projects were proposed by American Electric Power.

Six other proposals — two from AEP and Exelon, one from Transource Energy and three from Northeast Transmission Development — were not recommended. PJM is expecting to seek approval on recommended projects at the board’s October meeting.

Reliability Analysis for 2022 Finds 190 Violations

PJM’s reliability analysis of the Regional Transmission Expansion Plan for 2022 conditions found violations at 190 flowgates.

The majority (115) were generation delivery issues, with most of those (50) being on 138-kV lines on the western side of the RTO’s footprint. Overall, the 138-kV system had the most issues, with 77 violations identified.

The runner-up was the 345-kV system, with 46 violations identified. That system also had 35 of the 37 overall total high-voltage violations. All 35 were in the MAAC region.

Of the total 190 flowgates identified with violations, 41 will be included in the 2017 RTEP proposal window: 33 in the West region, five in the South region and three in MAAC. Generation delivery issues account for 35 of the available projects and six are N-1 thermal violations.

The remaining 149 flowgates were excluded because they were either “immediate need” projects or under 200 kV, which are expected to be addressed by the incumbent transmission owner.

— Rory D. Sweeney

August 15, 2017

PJM Market Implementation Committee Briefs: Aug. 9, 2017

VALLEY FORGE, Pa. — Going into last week’s Market Implementation Committee meeting, it appeared that PJM and its Independent Market Monitor would not find common ground regarding several changes to Manual 11 in preparation for implementing intraday offers on Nov. 1. (See “Revision on Intraday Offers Postpones Vote,” PJM MIC Briefs: July 12, 2017.)

“I don’t believe we are going to come to agreement on [the differences], so even if we delay the vote until next month, there is still going to be a difference of opinion,” said PJM’s Lisa Morelli.

But stakeholders pressed the sides to coalesce around a proposal, which resulted in PJM and Monitor staff — along with Calpine’s David “Scarp” Scarpignato — huddling during a break to hash out their dispute. The outcome is expected to be available for the Markets and Reliability Committee meeting on Aug. 24.

The issues were twofold: first, whether or not generators’ ability to “opt in” to utilizing intraday offers must be enunciated in their fuel-cost policies; and second, how to apply offer caps when a unit decides to change its offer after it has already received a commitment and failed the three-pivotal-supplier test.

Later in the meeting, IMM staff member Joel Romero Luna detailed differences with PJM on the triggers for updating price- and cost-based offers. The Monitor argued that they need to be updated simultaneously, even if the generator only wishes to update one, and the fuel-cost policy must specify the events that will trigger an update. If both offers did not have to change at the same time, it would permit the exercise of market power, the Monitor said.

“The point of intraday offers is to ensure that the current market value of gas is reflected in power prices. If the cost of gas goes down during a day and the generation owner does not have to reduce the offer, then the result is the exercise of market power,” Monitor Joe Bowring said. “If the generation owner opts for flexibility, which we think is a good idea, flexibility must reflect both increases in gas costs and decreases in gas costs.”

The Monitor also argued that all market-power mitigation analysis and approval should keep up with offer updates, but PJM said those revisions would require additional Tariff changes that might not receive FERC approval by the necessary Nov. 1 implementation date. PJM’s revisions, staff argued, could be implemented immediately. The Monitor’s changes would also require additional software changes, Morelli said.

PJM hoped to have its revisions approved and then work with the Monitor on its revision requests, but stakeholders asked that the two staffs resolve their differences before taking a vote.

“You can get it together now, or let’s go straight for guns and lawyers,” said Ruth Ann Price of the Delaware Division of the Public Advocate office. She expressed worry that no process had been defined or agreed upon to address the Monitor’s concerns if the PJM revisions were endorsed, and about the costly and time-consuming process involved in filing an action at FERC that could impede the smooth implementation of intraday offers.

Scarp said it was important that any additional changes be discussed through the stakeholder process and not be a “grand bargain” between PJM and the Monitor. Morelli said any changes would be presented as an expedited problem statement and issue charge.

The Monitor’s position received some pushback from generation owners.

“I think that if [an offer is] not mitigated, I shouldn’t have to have people sitting around, making work for them, just to appease [the Monitor] just because we made a market decision,” American Electric Power’s Brock Ondayko said.

UGI’s Gil Crystle questioned why price- and cost-based offers should be linked in the fuel-cost policy for simultaneous updating, as price-based offers can be adjusted for little more reason than just trying to get dispatched. “My price-based offer, I can change that all day long for no apparent reason, right?” he asked. “There can be a scenario where I don’t even care. … I’ll take whatever the market bears.”

Following the conclave, the sides agreed to defer the MIC vote until September’s meeting but work together to have the single proposal prepared for the August MRC meeting. The MRC vote will be held at the September meeting. The proposal will include all revisions that both sides agree can be implemented by the Nov. 1 deadline. They will also present Tariff and manual changes that both sides agree on, but that PJM believes will require FERC approval for implementation. The Monitor will present a problem statement and issue charge in September or October for the “opt in/opt out” changes on which PJM does not agree.

In a related disagreement, PJM and the Monitor also outlined their differing Manual 11 revisions for energy market offer verification. PJM’s revisions would limit offers to a hard cap of $2,000/MWh for dispatch and setting LMPs. Only cost-based offers would be allowed to exceed $1,000, and all but those that set LMPs would require verification. The Monitor acknowledged verification is essential and raised a list of issues with PJM’s proposal focused on the inadequacies of PJM’s approach to verification.

PJM is also removing references to offer capping and market-power mitigation from Manual 28, as they are now in Manual 11.

Fuel-Cost Policy Update

As part of the preparation for implementing intraday offers on Nov. 1, PJM and IMM staff have been working with generators to get fuel-cost policies reapproved. Policies were submitted in May to conform with recently implemented analysis changes. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)

Staff from PJM and its Independent Market Monitor huddle during a break during the meeting to agree on a plan for proposing revisions necessary to implement intraday offers by the FERC-imposed Nov. 1 deadline | © *RTO Insider*

Romero Luna said 56% of units passed Monitor evaluation for Nov. 1. Among the failed submissions, some only required minor changes such as formatting, while others required major changes to conform with the new rules regarding intraday offer updates. The policies requiring major changes are “all gas units, basically,” Romero Luna said.

PJM’s Jeff Schmitt also outlined changes that the RTO is requesting for fuel-cost policy submissions, such as indicating if the variable operations and maintenance, emissions or 10% adders are used in cost-based offers.

“You’ve got to think through how you’re going to create a $1,000 offer and above,” he said.

IMM Problem Statements Approved

Stakeholders endorsed by acclamation two problem statements and issue charges proposed by the Monitor. (See “IMM Presents Problem Statements on Transmission,” PJM MIC Briefs: July 12, 2017.)

The first set addresses what the Monitor believes is the need for clear rules governing the use of transmission penalty factors in setting prices in the PJM energy market when there is locational scarcity.

The second addresses market path/interface pricing point alignment, calling out situations that can arise when market participants submit transactions that are not consistent with actual physical power flow. Market manipulation results when scheduling is inconsistent with actual power flows, Bowring said. “There’s not an explicit rule” covering the issue, he said. “There needs to be a clear rule for the benefit of those entering transactions, for other market participants and to ensure that market power is not exercised.”

— Rory D. Sweeney

August 15, 2017

MISO Market Subcommittee Briefs: Aug. 10, 2017

MISO stakeholders last week laid out what they think are the top issues the RTO should tackle in the next year.

A “Top 10” project list emerged after stakeholders ranked 34 market modification proposals in the RTO’s annual Market Roadmap process, MISO Senior Manager of Market Strategy Mia Adams said during an Aug. 10 Market Subcommittee meeting.

Stakeholder scoring results still have to be tallied alongside staff weightings to arrange what market projects the RTO will eventually undertake first.

“This is not a prioritization yet. We’ll come back again this fall with an updated work plan,” Adams said. “However, it does look like [staff and stakeholders] are in pretty good alignment this year, more so than last year.”

This year, MISO limited stakeholders’ scoring to a maximum of four “high” and six “medium” priority designations, with an unlimited number of “low” and “do not pursue” designations. This year’s market project candidates included proposals outlined in the Independent Market Monitor’s annual State of the Market report. (See MISO, Stakeholders Embark on Market Roadmap Rankings.)

Rising to the top of stakeholder priorities: energy storage. Sixty-one market participants with voting rights determined that the most pressing issue for the market is defining a new resource type to accommodate the unique qualities of energy storage. During a special storage workshop last month, stakeholders asked MISO for a storage market definition. (See MISO Rules Must Bend for Storage, Stakeholders Say.)

Three other issues earned high priority from stakeholders:

Creating an automatic generation control software enhancement that deploys fast-ramping resources more quickly. MISO currently estimates that software can be operational in late 2019;
Introducing multiday financial commitments (See MISO Exploring Multiday Market.); and
Better modeling of MISO’s approximate 40 combined cycle generators worth 29 GW, which was first requested by market participants in 2011 and is currently in a benefit analysis and design option phase. The new modeling could save an annual $14 million to $34 million in production costs, according to MISO’s Yonghong Chen, but won’t be ready until 2020.

Market improvements recommended by Monitor David Patton took four of the six medium-priority designations in final stakeholder scoring:

Setting up short-term capacity pricing and reliability standards so energy can be provided within 30 minutes when needed to manage capacity needs;
Factoring seasonal needs and risks into the capacity auction;
Refining modeling and rules so demand response and storage resources “operating across multiple buses” can aggregate to meet a minimum megawatt participation limit;
Expanding conditions and temperature-adjusted transmission ratings into MISO’s Energy Management System;
Creating a virtual spread product; and
Incentivizing frequency response service.

MISO will release its final Market Roadmap by December.

Five-Minute Settlements Delayed?

Several stakeholders have asked MISO to consider pushing back the March 1, 2018, target for implementing the five-minute settlements calculation. (See “Five-Minute Settlements BPM due in Summer,” MISO Market Subcommittee Briefs.)

MISO’s Market Subcommittee meeting underway | © *RTO Insider*

Northern Indiana Public Service Co.’s Bill SeDoris said his company is still awaiting Business Practices Manual language while it works to implement five-minute settlements, and could miss the deadline while still making software and mechanical adjustments. DTE Energy’s Nick Griffin agreed.

“We are hearing from folks the same concern,” said MISO Executive Director of Market Design Jeff Bladen. “We are still subject to a FERC order. … We can ask for an extension, but we have a FERC order that we have to comply with. That said, we can only do what everyone is feasibly capable of.”

Bladen said MISO has already requested a later implementation date than other RTOs, but it will further discuss the possibility of an extension during the September Market Subcommittee meeting. He said MISO still has a team working to create five-minute settlements rules, but the work, originally due in early summer, has been delayed. It is also working on identifying units that habitually deviate from setpoint instructions, he said.

Mississippi Trading Hub

MISO has used geometric analysis to identify 159 electrical pricing node candidates to comprise Mississippi’s own commercial trading hub, said Michael Robinson, principal adviser of market design.

The nodes are located in both the MISO South and Southern Mississippi Electric Power Association territories, Robinson said. All other MISO trading hubs contain at least 100 electric pricing nodes, and the RTO’s analysis considered 622 possible nodes.

The proposed hub, the first MISO hub in the state, will be rigorously stress-tested over the next two months before final recommendation is made at the October MSC meeting, Robinson said. The RTO hopes the new hub will go live before the end of the year. (See MISO Examines Potential Mississippi Trading Hub.)

Market Reopen Incident

Stakeholders also asked why MISO had to briefly reopen its day-ahead market after market close on July 26.

MISO Executive Director of Strategy Shawn McFarlane called the reopening a “market participant issue.”

“To not correct this issue would have caused all other sorts of issues in the market,” McFarlane said, adding that the error fell into the “broad category” of data-entry errors. He declined to provide any other details.

Tariff changes made last year enable MISO to extend or reopen the day-ahead market to address technical problems. (See “Day-Ahead Market Extension to be Written into Tariff,” MISO Market Subcommittee Briefs.) Stakeholders asked MISO officials for a future presentation describing under what scenarios MISO may reopen the market. Bladen said MISO could put together a presentation for the September MSC meeting.

— Amanda Durish Cook

August 15, 2017May 20, 2025

ERCOT, Regulators Discuss Need for Pricing Rule Changes

By Tom Kleckner

AUSTIN, Texas — Industry experts and ERCOT stakeholders and staff jammed the Texas Public Utility Commission’s hearing room Friday for the first of several discussions on scarcity pricing and other price-formation issues in the grid operator’s energy-only market.

The PUC workshop was called to discuss a report commissioned by independent power producers NRG Energy and Calpine, which asserted that subsidized renewable resources, socialized transmission planning and the lack of local scarcity pricing have “exposed areas where there is a need for adjustments” to the ISO’s pricing rules. (See PUCT Workshop to Address ERCOT Market Improvements.)

Some participants were not convinced of the need for the session.

Amanda Frazier spoke for Luminant, the state’s largest generator, when she wondered aloud what ERCOT market problem needed to be solved. “We don’t believe the question was answered,” said Frazier, vice president of regulatory policy for Luminant parent Vistra Energy.

The report, “Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT,” recommends several market improvements, including adjusting the operating reserve demand curve (ORDC) and adding local scarcity pricing, to address intermittent renewables and improve incentives for generators.

“Fundamentally, we don’t see the system as broken,” said Harvard University’s William Hogan, who cowrote the report with FTI Consulting’s Susan Pope. “We tried to look at those issues … scarcity pricing and related subjects, that might be considered further. They’ve been discussed in the past and postponed, but now might be a good time to look at them.”

| Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT; William W. Hogan, Harvard University and Susan L. Pope, FTI Consulting

Commissioner Ken Anderson agreed with the report’s conclusion that the ERCOT system isn’t broken.

“It’s been six years since we went to the nodal system,” Anderson said. “I think it’s a good time to see whether we need any material improvements to the system, and what the costs and benefits to the system are.”

Unlike RTOs in the East, ERCOT does not run a capacity market, which pays generators to keep their plants ready to run. The Texas grid relies on price spikes during scarcity events — currently capped at $9,000/MWh — to incent the construction of new plants and maintenance of aging facilities.

However, ERCOT’s nearly 20 GW of wind generation and an expected wave of solar generation threaten to push the grid’s coal- and nuclear-fired generation out of the market. Investment firm Tudor, Pickering, Holt & Co. has said all but two of Texas’ 15 coal plants are losing money.

Still, scarcity pricing is “working just as designed,” Hogan told the commissioners as he and Pope reviewed their report with the PUC.

“You’ve been fortunate in that you have a lot of capacity and short-term load growth,” Hogan said. “Scarcity pricing has been pretty small, which should happen. It’s working … but the other side of story is it’s not been severely tested.”

“If someone asked me today what’s the biggest problem with our market, it would be that we have too much power,” Commissioner Brandy Marty Marquez said. “We do have so much surplus.”

David Patton, president of Potomac Economics, ERCOT’s Independent Market Monitor, cautioned against relying on the generation surplus. The ISO has said it has 81.6 GW of capacity available this summer, more than enough to meet a projected demand peak of 72.9 GW.

“It can be easy to have a false sense of security and think you have this big surplus. Then, all of a sudden, a couple of units retire and there’s no surplus any more, in the span of a year,” Patton said. “It’s pretty clear to me there are resources in Texas under extreme economic pressure. If operators decide it’s not worth it to continue losing money, you’ll see the surplus disappear.”

Patton reminded the commission of the Monitor’s recent State of the Market report, which listed co-optimizing energy and ancillary services among seven proposed market improvements. The report suggests using a local reserve product, such as the 30-minute reserves used by other RTOs, and considering including marginal losses in LMPs. (See ERCOT Monitor: Optimizing Energy, A/S Top Priority.)

“Implement software to better commit peaking resources more economically,” Patton said. “Whatever you do to try and solve the RUC [reliability unit commitment] problem with regard to pricing, it’s probably much less if you economically commit those units and assist participants with committing those units in a short time frame.”

Patton has a supporter in Golden Spread Electric Cooperative’s Mike Wise. The co-op’s s senior vice president of regulatory and market strategy, who has railed against the use of RUCs in both ERCOT and SPP, said it has supported a local reserve product since 2013.

“Additionally, Golden Spread has had positive experiences with real-time co-optimization in [SPP] and is optimistic ERCOT can realize significant benefits from implementation of that feature as well,” Wise said. “An effective marginal-loss methodology helps achieve the best price signals in an organized wholesale electric market.”

Vistra’s Frazier disagreed.

“We’re concerned with Dr. Patton’s suggestions that we should make major changes to the wholesale market just because economists generally think they are good ideas, without assessing the costs and benefits of those changes,” Frazier said. “This is particularly the case since all three experts admitted that they had not performed any studies to evaluate the impacts of implementing marginal losses in ERCOT,” she said, referring to Patton and the study’s authors.

Assessing the costs and benefits of implementing real-time co-optimization and scarcity pricing has been left to the ISO. Staff has already estimated it will take at least $40 million and up to five years to deploy co-optimization, citing the project’s complexity and scope: It would affect 13 ERCOT systems. Staff have yet to define requirements or develop a design, and face months of testing and market trials.

“It’s a large-scale, high-impact project. It impacts multiple core systems of ERCOT,” said Chad Seely, ERCOT’s general counsel and corporate secretary. “A large assumption here is if the commission decides to move forward with real-time co-optimization, we would still work on other projects while also working on real-time co-optimization.”

“I had hoped this was a simpler process, given that other RTOs have done it,” Anderson said.

Seely told the commissioners ERCOT would likely have to rely on outside consulting to quantify the benefits of the proposed market improvements.

“I’m not sure how I think about that,” Anderson said. “I’m a little hesitant to launch off on a project of this magnitude and complexity, particularly based on ERCOT’s view that this is a four- or five-year project and a $40 million cost.”

“On the other hand, if you have too many more $50 million [reliability-must-run contracts], that load could have already bought [the project],” Marquez pointed out, referring to a costly RMR contract in Houston that recently ended. (See ERCOT Ending Greens Bayou RMR May 29.)

Implementing scarcity pricing would be a project similar in cost and scope as the co-optimization initiative, staff said. Kenan Ögelman, ERCOT’s vice president of commercial operations, said staff have discussed marginal losses and locational reserves with NYISO and ISO-NE. ERCOT has promised further information on co-optimization and scarcity pricing before the PUC’s Oct. 12 open meeting.

Anderson also asked Patton to file with the PUC a document that would put “meat on the bones” of his proposal to address RMR issues with a local reserve product.

The workshop was the first of at least two, although the next session has yet to be scheduled. Several stakeholders took advantage of the opportunity to question Hogan, Pope and Patton. Stakeholders also have been promised a chance to present their cases for and against the market recommendations.

The two commissioners — a third is not expected to be appointed until Texas’ current special legislative session ends — will take up the issue again at their next open meeting Thursday. PUC staff said they would resubmit their May 31 request for comment, which includes a list of questions for stakeholders, as a starting point in the docket (No. 47199).

“I want to chew on this cost and benefit analysis,” Anderson said. “I’m inclined to believe there are proposals, or changes or modifications, that make a lot of sense. The question is, what foundation do we need to build or support a decision like that?”