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November 19, 2024

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NYISO Management Committee Briefs: April 24, 2019

New DER Market Design Approved

RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved proposed Tariff revisions that would create a path for aggregated distributed energy resources to participate in the ISO’s wholesale market.

James Pigeon, the ISO’s manager of distributed resource integration, presented the new construct, which would entail electrically mapping each individual DER facility to local transmission nodes to incent location-specific DER investment. It would also authorize entities to provide meter services to aggregations within the DER participation model and reliability-based demand response programs.

When the Business Issues Committee recommended the new design on April 17, several stakeholders expressed concerns about issues such as mitigation and the terms for dual participation, which would allow DERs that participate in the wholesale market to also provide services to another entity, such as a utility or host facility. (See NYISO Business Issues Committee Briefs: April 17, 2019.)

| NYISO

In response to those concerns, Pigeon offered a draft Tariff clarification on dual-participation DERs, with one phrase highlighted as new: “In accordance with ISO procedures, the ISO has the authority to determine schedules and/or dispatch for these resources.”

NYISO also agreed to stakeholder requests to add language to the FERC filing letter clarifying that the ISO is the ultimate authority over such dual-participation resources.

“A definition [of DER] is one thing stakeholders wanted, so we added that” as well, Pigeon said.

The Tariff would define a DER as a:

  • Facility comprising two or more resource types behind a single point of interconnection with an injection limit of 20 MW or less; or
  • Demand-side resource; or
  • Generator with an injection limit of 20 MW or less.

All DERs must be electrically located in the New York Control Area and capable of responding in real time to NYISO dispatch instructions.

The state Public Service Commission earlier this month ruled on what constitutes appropriate compensation for the capacity value of distributed energy resources (VDER) (Case 15-E-0751; 15-E-0082). (See NYPSC Refines Value Stack, Boosts Community DG.)

SRE Penalty Provisions Delayed

The MC delayed considering a new external supplemental resource evaluation (SRE) penalty scheme to improve the ISO’s ability to call on external resources that have sold into its markets, mainly because of implementation concerns raised by the Market Monitoring Unit.

The changes would take effect in the third quarter, which led one stakeholder to ask whether NYISO will consider fast-tracking the measure, given its importance and complexity. Interim CEO Rob Fernandez, who said he pulled the item from the agenda, affirmed that the ISO would.

Under the new proposal, any external resource that fails to meet delivery criteria would be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours to which a supplier fails to respond.

External capacity suppliers would not be subject to the penalty if their failure to deliver is beyond their control. The ISO would calculate deficiencies monthly, using the total number of SRE call hours in a given month that the resource could be available and the total megawatt shortfall in that month.

— Michael Kuser

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More Details Divulged on New NYISO Carbon Pricing Study

By Michael Kuser

RENSSELAER, N.Y. — Third-party consultant Analysis Group is putting the finishing touches on a NYISO study examining the impacts of pricing carbon into New York’s wholesale electricity markets.

The study will augment the Brattle Group report process that concluded in December.

“There are lots and lots of unknowns,” Sue Tierney, a senior adviser with Analysis Group, said Tuesday as she presented the ISO’s Installed Capacity/Market Issues Working Group with an update on the new study. Tierney expects to release the technical report and an executive summary for policymakers at the end of May.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, asked whether Analysis Group would be redoing or revising Brattle’s analyses or simply accepting and building off the results. He noted that Brattle had concluded that increases in energy market prices from carbon pricing would lead to a dollar-for-dollar reduction in future renewable energy credit prices, an assumption he thought overly optimistic. He asked whether Analysis Group would be revisiting that type of conclusion by Brattle or incorporating it into its own analyses.

“We are not going back and trying to tweak their results and see what we can find,” Tierney said. “You and the Brattle Group and the other stakeholders have already spent months on that, and it’s a standalone work. We’re going to be using Brattle data to run slightly different analyses … all of which are hypothetical, ‘what-if’ analyses.”

“We’re saying, ‘If you did this, what would the price impact be?’” Tierney said. “We’ll be looking at direct and indirect economic impact and induced effects. Going to the dynamic effects, a carbon price works in tandem with other New York policies to accomplish the state’s environmental goals.”

NYISO’s discussion around carbon pricing has prompted the question of whether any fossil fuel generation – like the Big Allis plant pictured – will ever again be built or re-powered in the New York City area.

Carbon Context

Since her initial presentation last month, Tierney received comments from several stakeholders, including the Long Island Power Authority, which she said had a number of questions on carbon pricing policy designs, implications of a carbon price and beneficial electrification. (See Analysis Group Presents NYISO Carbon Pricing Study Plan.)

Large consumers, such as Multiple Intervenors, wanted to know more about the implications of an incremental carbon price on business location decisions, she said, or the extent to which the study would be examining where firms should invest. She said the study would not try to guess what a carbon pricing scheme might mean for manufacturers deciding whether to stay or make more investments in the state; instead, it would use NOx and SOx emissions data to calculate particulate emissions and health impacts.

While the comments submitted so far will eventually be posted for all stakeholders to read, they are not yet available; however, a sense of some stakeholders’ positions can be gleaned from related proceedings.

In discussing Brattle’s estimates of the impacts of a carbon pricing mechanism on wholesale market and consumer prices, Tierney said that she wanted to talk about customer bill impacts in addition to price impacts.

“New York’s economy is very efficient in terms of electric energy use, more efficient than Alabama, for example, even though the latter’s prices are lower than in New York. So we don’t want to look just at price impacts; we also want to look at bills,” Tierney said.

Mager said large industrial customers look at rates, not bills, while Erin Hogan, representing the New York Department of State’s Utility Intervention Unit, said it was not fair to compare Alabama and New York because “they don’t have our heating load.”

Tierney replied that she made that comparison to highlight a point: “It’s just to illustrate that we will talk about both rates and bills. Some people discuss rates only, which is also a distortion.”

The new analysis will address the possible application of NYISO buyer-side mitigation to resources receiving RECs and zero-emission credits and other potential revenue streams outside ISO markets.

In describing how the Analysis Group might approach discussion of any direct — or indirect — relationship between the adoption of a carbon price and any action by FERC, Tierney refused to guess how the commission would act on concerns regarding the entry of out-of-market resources, the potential exercise of market power, or the potential risks and cost implications of changes in buyer-side mitigation in New York.

“We don’t know where FERC is going on this or even who’s going to be on the commission,” Tierney said.

Draft 2019 Master Plan

Ryan Patterson, NYISO capacity market design associate, presented the working group with an initial draft of the ISO’s 2019 Master Plan, a single document intended to provide a roadmap for future capacity market enhancements.

NYISO last year created the first master plan at the request of stakeholders, with each project grouped into one of three initiatives discussed in the ISO’s 2019-2023 Strategic Plan, including grid reliability and resilience, efficient markets, and new resource integration.

Mike DeSocio, the ISO’s senior manager for market design, asked what stakeholders want from this year’s master plan.

Troutman Sanders attorney Stu Caplan, representing NY Transmission Owners, said some factors were outside the control of the ISO.

“It could be a FERC compliance filing or something that requires interim attention, such as a market exploitation that must be corrected,” he told RTO Insider in an email. “The simple point is, stakeholders appreciate updates from the ISO.”

Caplan asked Patterson if it would be feasible to provide a semiannual update for those projects that enter the plan outside of the project prioritization process.

“Yes, that’s the point here,” Patterson said.

“I don’t want to suggest that the only way to get a project in is by putting it through the project prioritization process,” DeSocio said.

The ISO will release and discuss an updated draft on May 22, issue a final draft Aug. 27 and release the final Master Plan in December in conjunction with the 2020 Business Plan.

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Carbon Pricing Steers Discussion on PJM’s Future

By Christen Smith

PHILADELPHIA — Stakeholders agree PJM’s future likely involves carbon pricing, but they lack consensus on how the RTO will manage as many as 13 different state policies within the wholesale market over the next decade.

Stu Bresler, PJM’s senior vice president of operations and markets, said Wednesday that the RTO views its role in implementing external pricing as advisory and supplemental to state-enacted rules. Given the breadth of PJM’s territory, however, it’s not clear what such a system would look like or how varied it might be.

“I don’t think PJM has the authority to implement a carbon price,” Bresler said. “If state policymakers decide to price carbon in their jurisdiction, we could make it relatively simple as long as it’s systemwide and still achievable — but more complicated — if it’s only some states.”

Panelists discuss the future of PJM’s wholesale markets during a Raab Associates’ Energy Policy Rountdtable in Philadelphia. | © RTO Insider

Bresler’s comments came during Raab Associates’ Energy Policy Roundtable in the PJM Footprint, where panelists discussed what the PJM market might look like in 2030. They talked about their respective priorities on ensuring grid reliability, fuel security and resilience, and anticipating future technologies and integrating more renewable resources. Carbon pricing, however, dominated the conversation.

“We’ve reached an equilibrium where the natural gas units are no longer going to push coal retirements, and carbon emissions will increase,” said Ralph Izzo, CEO of Public Service Enterprise Group. “PJM must put in an external price marker … or it will become an irrelevant wholesale power market.”

In New Jersey, home to PSEG headquarters, the Board of Public Utilities on April 18 approved $300 million worth of zero-emission credits for its three nuclear reactors that struggle to profit at low wholesale prices set by polluting fossil fuels. Nuclear power provides more than a third of New Jersey’s emissions-free energy and remains vital to achieving the state’s ambitious clean energy goals, regulators said. (See NJ Approves $300M ZECs for Salem, Hope Creek Nukes.)

Pennsylvania lawmakers likewise continue talks on a pair of bills that would create the largest nuclear subsidy program in the country, while legislatures in Illinois, New York and Connecticut have approved their own nuclear subsidies. Executives at Exelon and FirstEnergy say the programs prevent premature retirements of reactors that provide clean, reliable energy 24/7, 365 days a year, despite a market design that doesn’t appropriately reimburse them for such service. (See Nuke Talks Continue in Pa. Assembly.)

“Many states probably have many questions beyond just, ‘What will the cost on carbon be?’ or ‘What happens to all the revenues?’” said Morris Schreim, senior adviser of the Maryland Public Service Commission on issues relating to PJM and FERC. “These could include, ‘Will our environmental policies be overtaken by for-profit utilities and other entities?’ Or, ‘Who will have jurisdiction over the air we breathe?’ Keep in mind, [Regional Greenhouse Gas Initiative] states never gave up their rights to a regional entity. Success in 2030 will be ensured if the answers to these questions stay within the realm of state policymakers.”

Kristin Munsch, deputy director of the Illinois Citizens Utility Board and president of the Consumer Advocates of PJM States, encouraged the RTO to take a more direct role rather than leaving it all to a “one-size-fits-all market design.”

“What I’d like to see PJM do is move from accommodating state policy to enabling it,” she said. “PJM in 2030 absolutely needs to think about how you enable this market.”

Izzo said an effective carbon price would drive onshore wind development and transmission expansion, while reducing the need for nuclear subsidies and crushing demand for rooftop solar — the most expensive of all renewable resource technologies, he said. More fossil fuel plants would likely retire, Bresler added.

PJM’s Markets and Reliability Committee endorsed a problem statement and issue charge on Thursday about implementing carbon pricing in the RTO. The effort will likely take more than two years, and it will consider ways to balance the concerns of states uninterested in enacting the policy. (See PJM Members Welcome Carbon Pricing Talks.)

“Dialogue is always important,” Schreim said of the effort. “An open stakeholder process could identify ways to provide value in meeting consumers’ needs that have never been considered before.”

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NERC Standards Retirements Go to Final Ballot

NERC Standards Retirements Go to Final Ballot

By Rich Heidorn Jr.

A NERC standards drafting team (SDT) has opened a final ballot on the elimination of all or parts of 18 reliability standards as Phase 1 of the organization’s standards efficiency review (SER) nears its conclusion.

Ballot pool members will have until May 2 to vote on the changes: the withdrawal of one proposed reliability standard, the complete retirement of 10 standards and the elimination of certain requirements for seven standards. (See chart.)

All the proposed retirements received 88 to 99% support in segment-weighted voting in the initial ballot that closed April 12. “They all passed at pretty high percentages,” observed NERC’s Laura Anderson, standards developer for the SDT at a team meeting April 17.

NERC’s ballot body, representing its 10 industry segments, currently has 525 members.

Proposed retirements that clear a two-thirds segment-weighted threshold on the final ballot will proceed to final approval by NERC’s Board of Trustees, likely at the board’s May meeting. Votes from the initial ballot are automatically included in the final ballot, although voters can change their positions.

Pruning the Rules

The Standards Efficiency Review Retirements effort (Project 2018-03) was created to take a second look at the rules that have been created since FERC certified NERC as the electric reliability organization (ERO) in 2006.

Three teams — representing real-time operations, long-term planning, and operations planning — identified for elimination requirements that were duplicative, obsolete or that were administrative and did not provide reliability benefits. Many of the standards to be retired relate to commercial business practices governed by the North American Energy Standards Board (NAESB) Wholesale Electric Quadrant (WEQ).

NERC last month closed the comment period on Phase 2 of the SER project. The phase involves considering changes in six areas of the organization’s operations and planning (O&P) and critical infrastructure protection (CIP) standards, including evidence retention time frames, moving requirements to guidance, simplifying training requirements and consolidating data exchange requirements. (See “Chair Urges Comments on Standards Efficiency Review,” NERC Standards Committee Briefs: March 20, 2019.)

The comments on the Phase 1 recommendations indicated how much the industry has changed since NERC became the ERO and gained enforcement authority.

For example, Black Hills Corp. said requirements 16 and 17 of standard TOP-001-4 provide no reliability benefit. The rule is intended to ensure prompt action to prevent or mitigate instability, uncontrolled separation or cascading outages.

The requirements direct transmission operators and balancing authorities to provide their system operators with authority to approve planned outages of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels.

The requirements “don’t even align with most, if not all, standard business processes,” Black Hills’ Maryanne Darling-Reich said. “The outage coordinator, [supervisory control and data acquisition emergency management system], IT networking and communications departments determine the impacts of all ‘planned’ outages of telemetry equipment. Most system operators do not even have the technical knowledge to make a substantiated decision to delay or postpone this work.”

MOD Standards

Eight of the 18 standards proposed for retirement were from NERC’s modeling (MOD) family of rules. The SDT proposed the elimination of seven of the MOD standards, including those on calculations of capacity benefit margins, transmission reliability margins and transfer capability — requirements incorporated in NAESB standards.

The standard authorization request (SAR) that initiated the SER project said that available transfer capability (ATC) and available flowgate capability (AFC) are “commercially based values used to facilitate a market for unused transmission capacity in an open access environment and that the values do not directly control the operation of the [bulk power system]. … [Transmission operators] are ultimately responsible for operating the grid in a reliable manner consistent with system operating limits, not ATC/AFC values.”

The team also proposed not implementing MOD-001-2, which has been awaiting FERC approval since February 2014 (RM14-7). It was intended to ensure calculations of available transmission system capability support reliability and that the methodology and data behind the calculations are disclosed to applicable registered entities.

The SAR said MOD-001-2 was not needed because although ATC and AFC values can influence real-time conditions, other standards, including subsequent improvements to TOP rules, ensure that real-time operations observe system operation limits. The “commercially based values and market related issues [regarding ATC/AFC] should not be addressed through NERC reliability standards,” it said.

Despite the high level of support for the retirements, there were some forceful dissents.

Duke Energy, for example, said it could not support the elimination of the seven existing MOD standards if MOD-001-2 is withdrawn.

“We disagree with the commercial-based focus that the drafting team took in the technical rationale document,” Duke’s Kim Thomas wrote. “While these MOD standards (and ATC calculation) may have some commercial-based elements to them, they also put in place valuable boundaries that help promote consistency in how the industry calculates these values. Removing these boundaries does not promote reliability for the bulk electric system and introduces additional burden to the real-time system operator.”

Southern Co. took a similar position, saying that transferring the seven MOD standards to NAESB without enacting MOD-001-2 would upset the “appropriate balance of addressing reliability-related concerns, while incorporating any market related issues.

“Simply stating that ATC/AFC calculations are primarily commercially focused elements and that there are mechanisms in place to address reliability in real time is an oversimplification of the ATC/AFC concept,” Southern’s Marsha Morgan wrote. “Inaccurately modeling and assessing transfer capability which considers real physical transmission limits on both the host and neighboring systems can create extremely complicated situations in real time that can unduly burden system operators.”

PJM, which was neutral on the elimination of MOD-001-2, supported the proposal to transfer the other MOD standards to NAESB, saying “reliability components of congestion management are handled amongst Eastern Interconnect parties through various established coordination processes.”

It warned against additional revisions to the NAESB WEQ rules, “especially those driven by issues unique to particular seams or between specific entities, as those issues may not be realized by other parties.”

“Therefore, blanket revisions may unnecessarily impact reliability and/or market aspects for other entities,” PJM’s Preston Walker said.

INT Standards

Also proposed for retirement are four interchange scheduling and coordination (INT) standards relating to interchange coordination, dynamic schedules, pseudo-ties and transmission loading relief procedures.

The SAR said the standards are duplicative of NAESB rules and that two of them are unenforceable because the “purchasing selling entity” is no longer a NERC registered function.

Duke also opposed the retirement of requirements 3.1, 4 and 5 of INT-006-4.

“We are not confident that this issue is adequately covered in the NAESB standards. Unlike the NERC standards which aim to promote reliability, the NAESB standards are commercially focused, and are not viewed as essential to maintaining a reliable system,” Thomas said. “We believe that not having these conditions outlined could negatively impact reliability.”

Morgan disagreed, saying requirements 4 and 5 are duplicative of the NAESB e-Tagging specifications “and are not a reliability-related task performed by a NERC registered entity.”

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Washington, Nevada Join 100% Clean Energy Movement

By Hudson Sangree

Washington state lawmakers approved legislation Monday requiring the state to rely entirely on zero-emissions and renewable energy by 2045.

Gov. Jay Inslee, a Democratic presidential candidate who heavily promoted the effort,  said he looked forward to signing SB 5116 just after the state Senate voted to send it to his desk. Once that happens, Washington will become the fifth state — after Hawaii, California, New Mexico and most recently Nevada — to adopt a 100% clean energy mandate.

“On this Earth Day, I couldn’t be more proud of the Legislature’s action to pass the country’s most forward-looking clean energy bill,” Inslee said in a statement. “[T]his bill will fundamentally transform Washington’s energy future and transition us to 100% clean energy.”

Washington state’s clean-energy resources include the Windy Flats project in Klickitat County. | © RTO Insider

Nevada Gov. Steve Sisolak signed legislation Monday to achieve a similar outcome. SB 358 requires Nevada to produce enough carbon-free electricity by 2050 to meet all of the state’s needs and to get half its electricity from non-emitting sources by 2030.

“Renewable energy is a major cornerstone of my economic development plan, and this bill will put Nevada back on the path toward renewable energy leadership on a nationwide level and continue to bring well-paying jobs to our communities,” Sisolak said in a signing statement.

Also on Monday, Public Service Company of New Mexico announced it was setting a goal of providing 100% emissions-free energy by 2040, five years ahead of the requirements set by the state’s clean-energy mandate. PNM said it was the first large investor-owned utility in the nation to establish such a goal.

“We … realized that we were not only up for the challenge of 100% emissions-free by 2045 but thought we can actually do it five years early while maintaining reliability and affordability for customers,” Pat Vincent-Collawn, PNM Resources chairman, said in a news release.

“The future is changing fast,” Vincent-Collawn said. “Here at PNM we are proud of how far we have come but know there is still so much to be done.”

The number of states, cities and corporations going all green has grown so quickly that some call it contagious.

The Dalles Dam on the Columbia River is one of the major hydroelectric resources in Washington state. | © RTO Insider

The Sierra Club, which keeps an up-to–date list of state and local governments to join the movement, said this week 131 cities and counties, from Florida to Alaska, have committed to getting all their electricity from non-polluting and renewable resources and five cities — including Aspen, Colo., and Kodiak Island, Alaska — have met that goal.

The rapid spread raises concerns among utilities and regulators. During a meeting last week in Salt Lake City, Utah, many expressed concerns about having enough electricity to meet demand and maintain grid stability as fossil-fuel plants retire and intermittent renewables, such as wind and solar, proliferate. (See Westerners Wrestle with Resource Adequacy, Grid Reliability.)

Some who spoke at the joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) said parts of the West could experience shortages soon.

Ann Rendahl, a Washington state regulator, said in the Pacific Northwest, “There’s increasing uncertainty there is sufficient resource adequacy in the next five years … Everyone is agreeing we’re approaching this point.”

David Mills, Puget Sound Energy’s senior vice president of policy and energy supply, said coal plants are closing, intermittent resources are saturating the market and natural gas plants, the “last backstop of reliability,” are retiring. He and other speakers urged Western states and utilities to create a centralized entity to oversee supply.

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NextEra’s Adjusted Earnings Beat Expectations

By Tom Kleckner

NextEra Energy officials said they expect the company to continue increasing adjusted earnings near the top end of a previously disclosed 6-8% growth rate for the year.

“I’ll be disappointed if we are not able to deliver [those] financial results,” CEO Jim Robo told analysts during an earnings call Tuesday.

The company reported first-quarter earnings of $680 million ($1.41/share), compared to $4.43 billion ($9.32/share) a year ago.

NextEra Energy’s Live Oak Solar Energy Center in Candler County, Ga. | NextEra

However, adjusting for federal tax reform and investments, NextEra reported adjusted earnings of $1.06 billion ($2.20/share), beating analysts’ expectations. The Florida-based company’s adjusted earnings a year ago were $929 million ($1.96/share).

Investors reacted by driving down the company’s stock slightly to $189.79/share, a 74-cent loss during the day. NextEra’s share price has gained 9.2% since the year began and 17% over the past year.

Gulf Coast Power contributed $0.08/share to earnings, following the close of its acquisition at start the quarter. (See FERC Approves NextEra’s Gulf Power Acquisition.)

NextEra said the utility’s integration “continues to progress smoothly” despite the loss of about 7,000 customers in the aftermath of Hurricane Michael. CFO Rebecca Kujawa said the utility expects 60-80% of those customers to return, and it has filed to recover $350 million in restoration expenses.

The company said NextEra Energy Resources has added about 1 GW of renewable resources to its backlog, including its first co-located combined wind, solar and storage project. The wholesale supplier expects to develop more than 6.4 GW of wind and solar projects through 2020.

| NextEra

NextEra’s Florida Power & Light subsidiary announced in January a “30-by-30” plan to install more than 30 million solar panels by 2030.

Addressing NextEra’s reported $8 billion offer for South Carolina’s troubled state-owned utility, Santee Cooper, Robo said he expects a decision by June. The utility was involved in a failed effort to build the V.C. Summer nuclear plant.

“I think the state realizes Santee has upwards of $4-$5 billion of debt on an asset … that is never going to generate income,” Robo said. “I think the vast majority of folks in the state understand they need to address [this issue], and the key stakeholders are, I think, working hard to come to a conclusion about how the process is going to move forward. You can imagine we will continue to play in the process.”

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DER Ride Through Task Force Considers New Direction

By Christen Smith

PJM wants stakeholder feedback about whether its Distributed Energy Resource Ride Through Task Force should pivot in a new direction.

Susan McGill, manager of interconnection analysis, said Tuesday staff will poll members of both the Task Force and the Planning Committee in order to build a solutions package at its next meeting. The leading question, she said, asks stakeholders how comprehensive proposed rules for ride through settings should be, given the varied landscape of PJM’s 13-state grid.

“Originally, the thought was that PJM will develop a standard set of settings we would use across the PJM footprint,” she said. “But there’s a lot of facilities that don’t fall under FERC jurisdiction, and we wouldn’t have any authority to enforce those settings.”

PJM wants stakeholder feedback about whether its Distributed Energy Resource Ride Through Task Force should pivot in a new direction.

Before the widespread adoption of DERs, the grid was designed to handle one-way power flows, with energy moving from generating plants through the transmission system, before being stepped down to the distribution system and ultimately transmitted to end-use consumers. The growing volume of generation coming off the distribution network is forcing grid operators to rethink the system to accommodate unconventional flows.

PJM said DERs — including solar, battery storage, combined heat and power plants and some wind turbines — currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride through” the event, providing much-needed reliability, while others “trip-off” to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.

The task force has been considering ways to fix this problem — even going so far as to bring in federal experts to help develop new standards — but McGill said stakeholder feedback so far has been limited. (See DOE Lab to Join PJM DER Integration Effort.)

She said the poll will help PJM decide when settings should be developed following one of the following directives:

  • Standard settings that should be used consistently for all DER facilities across the PJM footprint;
  • Standard settings that should be used for all FERC-jurisdictional DER facilities across the PJM footprint;
  • Recommendations that can be used when the local electric distribution company does not have a standard.

“Some transmission owners are already working standards to fit their unique distribution facilities,” McGill said.

Members will have a week from receipt to answer the poll. Staff will review the answers and use the results to construct a package of standards at the task force’s May 21 meeting.

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Record Gas Demand, Production Highlights FERC Markets Report

By Rich Heidorn Jr.

WASHINGTON — Record high natural gas demand and production highlighted FERC’s 2018 State of the Markets report, released last week.

The report by the Division of Energy Market Oversight said gas demand was driven by electric generation and growing LNG exports. Despite big jumps in the Marcellus Shale and the Permian Basin regions, demand growth outpaced production increases.

As a result, storage levels were lower than average and “at times were the lowest in more than a decade,” FERC said, contributing to higher gas and power prices.

The Henry Hub benchmark averaged $3.12/MMBtu for the year, up 5% from 2017. Reduced storage inventories pushed Henry Hub prices up 31% in the fourth quarter over a year earlier.

| FERC

 

Although gas prices remained relatively low, there was increased price volatility because of storage constraints, extended winter cold and infrastructure constraints in the West. In January 2018, an East Coast cold snap pushed gas prices to $140.85/MMBtu in New York and $128.39/MMBtu in the Mid-Atlantic, with prices peaking at $78.88/MMBtu in Boston. In contrast, New York’s spot price never reached $21/MMBtu in 2017.

Gas production averaged 80.7 Bcfd, an increase of 12% from 2017. The Marcellus Shale was the most productive basin, averaging 19.4 Bcfd for 2018, up nearly 13.5% from 2017.

Haynesville Shale production jumped to an average of 6.5 Bcfd, a 46% increase that FERC attributed to higher gas prices and lower production costs. Rising crude oil prices were a factor in the 2.1-Bcfd increase in associated natural gas production in the Permian, a jump of 41%.

More than 689 miles of commission-jurisdictional pipelines, representing 13 Bcfd of capacity, went into service during 2018, much of it connecting Marcellus and Utica supplies to markets in the Midwest, Northeast and Southeast. There was no capacity increase in New England.

| FERC

Export Growth

New pipelines also provided links to LNG export terminals and exports to Mexico.

After becoming a net gas exporter for the first time in 60 years in 2017, U.S. net exports were almost 2 Bcfd in 2018, in part because of the opening of the Cove Point LNG facility in Maryland in March and the expansion of the Sabine Pass LNG terminal in Louisiana in October. LNG exports averaged nearly 3 Bcfd in 2018, a 50% jump from 2017.

Pipeline exports to Mexico rose almost 0.5 Bcfd to a new high of 4.6 Bcfd.

| FERC

The report predicted up to 4 Bcfd of new export capacity will be added in 2019, with LNG facilities at Cameron, Corpus Christi, Elba Island and Freeport expected to go into service and an additional expansion at Sabine Pass. (See related story, Enviro Protesters Scale FERC HQ as Agency OKs More LNG.)

Power Prices Rise

As gas continued its increasing role in electric generation, fuel price increases also caused a jump in power prices across the country.

Mean day-ahead on-peak LMPs jumped almost 25% at RTO/ISO pricing nodes. Prices in SPP, MISO and CAISO increased less than 15%, while PJM and NYISO prices rose about 20%. ISO-NE was up 33% and ERCOT had the biggest jump at 44%.

As in recent years, most new generation capacity in 2018 was natural gas, wind and solar, and most retirements were from coal.

| FERC

Capacity price trends varied in grid operators’ 2018 auctions. RTO-wide average prices declined 13% in New England’s auction for 2021/22, while the weighted average price in PJM’s auction for the same period rose 36%.

In NYISO’s spot capacity auction, prices in the high-cost Hudson Valley and New York City zones fell by 3% or more. Prices for Long Island rose 5% and the New York Control Area jumped 32%.

MISO’s Planning Resource Auction saw zonal prices rise clear much lower than in the other markets with a price of 30 cents/kW-month for most of the region for 2018/19, up 25 cents from a year earlier.

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PJM: Dismiss Monitor’s Offer Cap Complaint

By Christen Smith

PJM wants FERC to toss out the Independent Market Monitor’s complaint about its default market seller offer cap (MSOC), saying the IMM’s February filing did not prove current rules encourage abuse of market power (ER19-47).

In an April 9 response filed with the commission, PJM said the Monitor didn’t provide enough evidence that its current cap — approved four years prior as part of the RTO’s Capacity Performance construct — and the results of Base Residual Auctions suddenly became unjust and unreasonable.

PJM said the commission’s order approving CP “explained that the default MSOC is just and reasonable because it reflects the amount that a competitive resource would accept to be committed as a capacity resource.”

“In particular, it is designed to allow capacity market sellers to recover the costs, investments and expenses needed to ensure that their resources can perform during emergencies occurring at any time of the year. In other words, the default MSOC is intended to reflect the opportunity cost that a resource faces when choosing whether to become a committed capacity resource,” PJM said.

PJM said the Market Monitor isn’t authorized to file a complaint on the market seller offer cap. | PJM

The Monitor said in its initial filing that PJM’s MSOC has been inflated by the “unreasonable and unsupported” expectation of 30 performance assessment hours (PAHs) annually. As a result, the Monitor said, it has been prevented from effective mitigation of market power, able to subject only a small number of very high offers to unit-specific cost reviews. (See Monitor Asks FERC to Cut PJM Capacity Offer Cap.)

Unit-specific MSOCs are supposed to be based on the opportunity cost of taking on a CP obligation, with its expectations of bonus payments or penalties for performance during an emergency, PJM said. (The time span for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAIs) in compliance with FERC Order 825 in 2018.)

In August, the Monitor concluded that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 BRA because of economic withholding encouraged by the inflated MSOC. (See IMM: PJM 2018 Capacity Auction was ‘Not Competitive’.)

PJM asked the commission to reject the Monitor’s proposed replacement rate of 60 PAIs and instead adopt a method that applies the same measurement to equations for both the default MSOC and the nonperformance charge. This rate, the RTO asked, would not take effect until after the 2022/23 BRA, for which several compliance deadlines for market sellers have already passed.

“The Market Monitor’s proposal is unjust and unreasonable due to, among other reasons, the disconnect between the number of expected performance assessment intervals in the nonperformance charge rate and the default MSOC,” PJM said. “Retaining the same value of performance assessment intervals in both equations is essential to maintaining the underlying logic of the existing default MSOC equation.”

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Renewables Outlook to Get Boost in MTEP 20 Futures

By Amanda Durish Cook

After prodding by stakeholders, MISO now says it will boost renewable generation estimates in each of the four 15-year future scenarios that guide its annual transmission planning process.

MISO had previously proposed relying on an older set of futures to inform the 2020 Transmission Expansion Plan (MTEP 20). But stakeholder pushback prompted the RTO to increase the minimum renewable penetration levels for each future by 5%, bumping projections from 15-35% of the generation mix to 20-40%.

Speaking at a Planning Advisory Committee meeting Wednesday, MISO Planning Manager Tony Hunziker noted the high degree of consensus among stakeholders to increase renewable estimates.

Increased renewable projections in MTEP 2020 futures | MISO

The MTEP will also assume the solar investment tax credit — which allows a 30% federal tax deduction of installation costs — will continue into 2023. The RTO will also rely on the National Renewable Energy Laboratory’s Annual Technology Baseline capital cost projections for renewable generation instead of using a 30% variance on those projections.

However, some stakeholders said they’d like to see a more nuanced approach to projecting renewable growth based on subregional characteristics to avoid blindly increasing renewable projections. For instance, MISO shouldn’t expect significant wind generation growth in sunny MISO South, some noted.

“MISO is not a resource planner. We don’t dictate renewable resource additions,” Hunziker responded.

Entergy’s Yarrow Etheredge said MISO didn’t adequately support the case for a blanket increase of every type of renewable generation everywhere in its footprint.

“This is basically just an adder,” Etheredge said, asking MISO to defend the change using data.

Hunziker promised a complete rework of MTEP 21 futures with stakeholders and reminded PAC members that MISO was up against a June deadline to finalize MTEP 20 futures definitions and assumptions.

The RTO last month said it would rely on the same set of 15-year futures for the third straight year to evaluate transmission projects in MTEP 20, though some stakeholders criticized the RTO’s limited fleet change future as no longer a likely scenario. (See MISO Going Back to the Futures for MTEP 20.) The futures scenarios include a limited fleet change, continued fleet change, accelerated fleet change, and a distributed and emerging technologies future.

Hunziker said the renewable increase should alleviate specific concerns about MISO’s limited fleet change future, which has been criticized as improbable because it projects only an 11-GW growth in renewable generation through 2033. MISO’s interconnection queue currently includes about 420 projects worth a combined 70 GW; renewable resources account for about 90% of the queue. Historically, about 18% of proposed projects clear the queue.

Last month, members of MISO’s Board of Directors also questioned whether the limited fleet change future was still plausible.

“It seems like the rate of adoption is increasing,” Director Thomas Rainwater said, while also acknowledging that MISO is “no California” in terms of appetite for renewables. He asked if the RTO will consider “a more radical adoption” of renewables and distributed resources in a new set of futures for MTEP 21.

MISO Vice President of System Planning Jennifer Curran said the accelerated fleet change and distributed and emerging technologies scenario are fast becoming the most probable futures and noted the RTO will soon revisit how futures are developed. But she also cautioned that MTEP futures represent possible trends and are not meant to be forecasts.

At the April PAC meeting, Minnesota Public Utilities Commission staff member Hwikwom Ham said he remained concerned that the limited fleet change and continued fleet change scenarios still risk obsolescence because they don’t account for the zero-carbon pledges of multiple utilities and increasing electrification of the economy. He also pointed out that equity investors are now contemplating a company’s carbon footprint as a risk factor before making investments decisions.

“Who is going to be in the White House next year? It’s going to be a different business model,” Ham added, referencing President Trump’s rollbacks of environmental regulations.

Hunziker said MISO will raise those topics in the redevelopment of futures in time for MTEP 21.

Meanwhile, MTEP 20 marks the first time MISO will work with Purdue University’s State Utility Forecasting Group and Applied Energy Group to create separate load forecasts that reflect each of the four futures. The RTO this month reported that entities representing 77% of its load responded to its request for load, demand and energy data.