Page 1009 – RTO Insider

August 11, 2019

Monitor: PJM Markets Remain ‘Under Attack’

By Christen Smith

PJM’s wholesale power markets remain “under attack” from those concerned about the retirements of legacy generators unable to profit in the face of ever-decreasing energy prices, the Independent Market Monitor said Thursday.

In its quarterly State of the Market report released last week, the Monitor — in a thinly veiled dig at PJM’s minimum price offer rule (MOPR) revisions pending before FERC — said there’s no reason to exclude competitive capacity offers from any generator, nor artificially increase energy prices to benefit struggling nuclear and coal plants.

“The value of markets is under attack, from those who think energy prices are too low and from those who think that market outcomes do not favor their preferred technology, whether it is nuclear, coal, wind or solar,” the Monitor said.

Instead, PJM should prevent the markets from reverting back to an integrated resource planning approach “that some would reimpose because markets provide technology-neutral incentives to all market participants, including those who will introduce technologies not yet in existence.”

“Markets continue to provide the most efficient way to organize the production of power at the lowest possible cost,” the report reads. “Markets are also the most efficient way to integrate state-supported renewable technologies.”

Record Low Energy Prices

The Monitor reported that energy prices decreased 35% to $27.49/MWh in the first six months of 2019, compared to the $42.44/MWh seen a year prior. Lower fuel costs contributed to nearly a third of the decline, while decreased load and lower mark-ups comprised the rest. These are the lowest load-weighted real-time energy prices ever seen in PJM, the Monitor said.

The lower prices drove down net revenues for all unit types, including: 65% for combustion turbines, 44% for new combined cycles, 87% for new coal plants, 30% for new onshore wind and 34% for new nuclear plants.

The last includes the subsidized Quad Cities and three other Exelon nuclear facilities in Illinois — Braidwood, Byron and LaSalle. Based on current forward prices, the Monitor said, all four of the plants will fail to recover their avoidable costs in two of the three forward years, with an average annual shortfall of 73 cents/MWh during the shortfall years.

PJM — Quad Cities nuclear plant | *Exelon*

Exelon told investors earlier this month that without substantive legislative action, the company will close unprofitable plants so as to not “damage the balance sheet sitting around for years with negative free cash flow or negative earnings.” (See related story, Exelon to Close Three Mile Island.)

The Monitor acknowledged PJM’s markets are imperfect and said a carbon price would provide a market-based solution to reducing emissions and supporting nuclear plants’ economics. But it said “the fact that some plants are uneconomic [without a carbon price] does not call into question the fundamentals of PJM markets. Many generating plants have retired in PJM since the introduction of markets, and many generating plants have been built since the introduction of markets.”

Energy Market Competitive, Capacity Market not

The Monitor said PJM’s energy market remains competitive while the capacity market does not — consistent with the Monitor’s conclusions in reports released in March and May. (See Energy Market Competitive in Q1, PJM Monitor Says.)

As an alternative to PJM’s MOPR for addressing the dilemma between “market solutions and potentially inconsistent state policy initiatives,” the Monitor again touted its proposed Sustainable Market Rule (SMR). (See PJM Monitor Reiterates Concerns in Quarterly SOM Report.)

Under the SMR proposal, all nonmarket resources could participate in the energy market without limits, with the capacity market used as a “balancing mechanism” for providing incentives for resources to enter and exit.

“The SMR approach to the capacity market design is simple, based in economic logic, based on the PJM competitive market design and does not require complex rule changes to implement,” the report reads. “The SMR would provide a straightforward way to harmonize federal and state approaches to the provision of energy, while respecting the distinction between federal and state authority. The SMR reaffirms the definition of a competitive offer in the PJM capacity market and removes noncompetitive barriers to the participation of renewables.”

The Monitor also criticized PJM’s energy price formation plan, saying that it guarantees double recovery for generation owners “by breaking the tight link between energy and capacity markets that has been essential to the success of the PJM market design.” It also accused the RTO of creating unintended consequences by pushing through substantial energy market revisions without any explanation of how such changes would “enhance or even maintain the competitiveness of the markets.”

The Monitor outlined five steps to address what it called legitimate concerns about price formation in the energy and reserves markets:

Consolidate the tier 1 and tier 2 synchronized markets.
Increase the scarcity price to reflect the highest generator energy offer allowed.
Increase the transparency of operator actions, with explicit pricing for defined actions.
Implement clear rules governing real-time pricing through the selection of real-time security constrained economic dispatch (RT SCED) and locational price calculator (LPC) cases. LPC, which uses the latest approved RT SCED case as its reference case, produces financially binding LMPs and reserve market clearing prices.
Develop a consistent definition of energy and reserves products in the day-ahead and real-time markets, including recognition of the appropriate role of demand-side resources.

“This should not be the end of the discussion, but the beginning of a longer, more complete discussion which would lead to incremental steps to improve markets,” the report concluded.

Recommendations

The Monitor provided three new recommendations for PJM stakeholders to consider:

Demand response reductions based entirely on behind-the-meter generation should be capped at the lower of economic maximum or actual generation output.
Load and generation located at separate nodes should be treated as separate resources.
FERC should require that the open firm flow entitlement (FFE) and firm flow limit freeze date issues be addressed at a technical conference, and that a deadline to resolve the issues that result from the freeze date be set. PJM, Outside Parties Slow MISO-PJM Freeze Date Thaw.)

August 11, 2019

ERCOT, WMS Collaborate on Price Corrections

By Tom Kleckner

ERCOT staff have laid out a plan to work with stakeholders in addressing a May pricing event that has led to a complaint filed with Texas regulators against the grid operator.

Kenan Ögelman, ERCOT’s vice president of commercial operations, met with the Wholesale Market Subcommittee on Wednesday and proposed three issues for further discussion with market participants, including potential changes to the grid operator’s price-correction methodology; adding filters, requirements or different standards to the external telemetry coming into ERCOT; and improving the communications structure around price corrections.

Ögelman said staff would return to the WMS in September with an issues list. He said he expects “more topics than any solutions.”

“We’d like to give a high-level presentation and see if you have any other issues,” Ögelman said. “I think it’s important everyone see all the issues and where they’re going so we can get a solution.”

On May 30, prices briefly reached the $9,000/MWh maximum when the security-constrained economic dispatch system received bad telemetry data from Calpine. Staff quickly corrected the data, but they have refused to correct the prices because the data were external.

“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman told the grid operator’s Board of Directors in June.

Aspire Commodities, an energy broker, has filed a complaint with the Public Utility Commission of Texas asking that generators refund the market $18 million (49673). (See ERCOT Asks PUC to Dismiss Trader’s Complaint.)

Morgan Stanley’s Clayton Greer, who has complimented ERCOT on its quick response to the pricing error, urged quick decisions in the future.

“You let us know you were not going to reprice that day. The market understands once you do that, it’s final,” he said. “If you could find a way to put into words what you did [on May 30] into the protocols, that would be optimal.”

“We want prices to reflect the fundamentals of the market,” Reliant Energy Retail Services’ Bill Barnes said.

Luminant Generation’s Ian Haley indicated his company preferred to see bad telemetry rejected.

“We don’t think ERCOT should be in the business of determining what is and what isn’t correct,” he said.

August 11, 2019

MISO to Limit Capacity Resource Extended Outages

By Amanda Durish Cook

CARMEL, Ind. — MISO is working quickly to ensure its capacity resources are mostly accessible for the planning year after this spring’s auction cleared a Michigan generator scheduled to be on outage for the entire period.

The RTO proposed a provisional solution at the Resource Adequacy Subcommittee meeting Wednesday that would limit extended planned outages to fewer than 90 days to qualify for participation in the Planning Resource Auction. Additionally, resources expected to be unavailable for the first 90 days of the planning year would not qualify for PRA participation.

Cleared resources with planned outages lasting 90 days or longer must replace their capacity or be penalized at MISO’s approximately $250/MW-day cost of new entry. Currently, the RTO doesn’t impose any penalties for capacity resources that take extended outages.

“If you think about MISO’s resource adequacy construct, there is a reasonable expectation of availability,” Director of Resource Adequacy Coordination Matt Ellis said.

MISO plans to file the proposal with FERC by mid-October to have it in place in time for the 2020/21 PRA, an unusually fast turnaround for the RTO, which can spend several months to a few years formulating new Tariff language. MISO said it also plans to seek more fleshed-out outage rules for the 2021/22 auction.

Ellis said that while MISO may not be able to make a comprehensive filing now because it must examine several possible unintended consequences, it can impose a straightforward, 90-day requirement.

“It’s an incremental change. It’s intended to be a step in the right direction — something we can refine further as we go along,” Ellis said.

April’s PRA cleared a large generator in Michigan’s Zone 7 as a capacity resource for the 2019/20 planning year even though it is slated to be on an extended outage for the entire year. The Independent Market Monitor first criticized the move in June. (See “Extended Outages and the Capacity Auction,” Monitor Splits with MISO on Summer Readiness.)

Ellis said the 90-day requirement is meant to capture the possibility that a planning resource will be out for an entire season. Requiring availability in the first 90 days of the planning year also ensures that capacity resources will be available during summer months when availability is more critical. MISO planning years begin June 1.

Stakeholders immediately inquired about planned outages that come in just under the threshold, but Ellis said MISO is starting by drawing the line at 90 days.

“And honestly, when we discussed this internally, that’s the first thing that came up: ‘What if units take an 89-day outage?’” Ellis said. “What’s the bright line? We chose 90.”

Ellis said MISO will revisit its proposal if 88- to 89-day outages begin to become “habitual.”

When stakeholders asked what would happen if a generator extends an outage to 90 days or longer, Ellis responded it wouldn’t be retroactively penalized to cover replacement capacity. However, MISO and the Monitor would keep a sharp eye for resource owners that might be seeking to game the rule with sudden extensions. Under the plan, the Monitor would have Tariff authority to audit outages for physical withholding.

Stakeholders said the proposal could encourage generators to take forced outages — and the accompanying hit to resource accreditation — over taking a long-term planned outage that would exclude them from a capacity payment for a planning year or face having to replace the capacity at a high cost.

MISO has left the proposal open to other stakeholder comments through Aug. 23.

August 11, 2019

NYPSC Opens Resource Adequacy Proceeding

By Michael Kuser

New York regulators on Thursday kicked off a proceeding to examine how to reconcile NYISO’s resource adequacy (RA) programs with the state’s renewable energy and carbon emission-reduction goals (Case 19-E-0530).

“This item to open an inquiry is important and timely,” Public Service Commission Chair John B. Rhodes said. “We at the commission have a duty to ensure safe and adequate power. Safe means safe, and adequate means, in this case, [that] there’s power when New Yorkers need it. … It’s becoming questionable whether the answers that were organized at least 20 years ago are in fact the best answers for the situation we face today.”

David Drexler, the PSC’s managing attorney, said “a major impetus” for the RA inquiry is New York’s recently passed Climate Leadership and Community Protection Act (A8429) — particularly its mandate that 70% of the state’s electricity be generated by renewable resources by 2030.

Commissioner Diane Burman said she understood the need to examine electricity issues, “but I do find it disingenuous to say that we have an obligation to do this when there are many other issues that we have an obligation to examine,” pointing to Consolidated Edison’s moratorium on providing new customers with natural gas hookups in Westchester County until it can ensure adequate supply to the region.

The PSC held its regular monthly session in Albany on Aug. 8, 2019.

“I think the chairman nailed it when he said that the current approach was set 15 to 20 years ago, and it’s based on the cost attributes of a fossil generator,” said Warren Myers, director of regulatory and market economics for the state’s Department of Public Service.

The inquiry will focus on answering several questions, including:

Are the state’s energy policies and mandates, such as those related to offshore wind, photovoltaics, other renewables and energy storage, compatible with NYISO’s RA mechanisms? If not, what issues are manifested? Also, if not, how could they be aligned? Do policies and market structure mechanisms result in safe, adequate service at just and reasonable rates?
Is an installed capacity (ICAP) product an effective long-term solution for RA given the required future generating resource mix, which may have lower marginal costs or different availability profiles than many current generation resources in operation? What are the salient attributes of such long-term solutions?
Is there a preferred mechanism for ensuring RA? What are the cost impacts and benefits to consumers under the various potential RA mechanisms?
Should alternative approaches be considered to ensure that procurement of generation resources is aligned with state policy goals? If so, which ones? Are there existing or proposed models that might be instructive, such as the state overseeing the RA portfolios of load-serving entities as in California, or should NYISO rules be restructured to accommodate state policies?
What is the state’s role with respect to RA matters?
What, if any, next steps should the commission take with respect to RA matters?

First of Many

NYPSC Resource Adequacy — Commissioner Diane Burman

Burman said she would ask the “elephant-in-the-room question,” wanting to clarify that the PSC’s new effort would not seek to “undo the role of the ISO” regarding RA, “but in fact is looking at how can we work on these issues.”

“The elephant is prematurely in the room,” Myers responded.

Drexler said, “Actually, from a staff perspective, we’re not prejudging any of the issues at this point. This is merely meant to start the inquiry.”

Commissioner James Alesi supported the inquiry, saying that “New York is already on its way to cleaner energy consumption.”

Commissioner Tracey Edwards said it was better to start asking the right questions now than later, “when we’d be doing so in a defensive posture.”

Attending his first session since being appointed to the PSC on July 19, Commissioner John Howard said, “The truth is, the ISO and its markets work today; the lights stay on; people get paid. If you’re an incumbent, things seem to be pretty well-ensconced. However, that doesn’t mean there aren’t holes that need to be examined. … I believe this will be the first of many inquiries.”

In an Aug. 8 blog pos t, Jackson Morris and Cullen Howe of the Natural Resources Defense Council welcomed the PSC’s inquiry and raised two points.

“A central concern held by many stakeholders, including NRDC, is that NYISO’s capacity market rules could prevent clean energy resources supported by state and local policies from selling in that market, thereby depriving these resources of an essential source of revenue. …

“Another concern is that NYISO’s rules undercount the value of cleaner resources like energy storage systems, as well as wind and solar, while over-crediting highly polluting power plants.”

Burman expressed additional concern that the proceeding seems to lack direction: “Ultimately, all we seem to be addressing is the capacity markets and buyer-side mitigation, and then taking a look at, in some fashion, whether or not we want to change those rules.”

The commission has asked interested parties to submit initial comments by Nov. 8. Commenters can file with the DPS by e-filing or by email to secretary@dps.ny.gov, or through the department’s Document and Matter Management System.

“Today’s order is the beginning of an important discussion on resource adequacy, and we look forward to engaging with the Public Service Commission throughout the process to share our expertise, information and ideas,” NYISO CEO Rich Dewey said in a statement.

August 11, 2019

NERC Weighing Concerns on Reorg.

By John Funk and Rich Heidorn Jr.

NERC’s plan to streamline its top technical committees appears to face limited opposition, although officials indicated Thursday they are considering proposals to increase sector representation and lengthen the transition.

The new structure, to be discussed in detail at NERC’s quarterly meeting in Québec beginning Tuesday, would merge the Planning, Operating and Critical Infrastructure Protection committees into a new Reliability and Security Council (RSC). While the three technical committees have almost 120 voting members, the proposal would limit the RSC to 33.

Only two stakeholders made comments during a webinar Thursday on the proposal, both questioning why NERC hasn’t quantified the proposal’s supposed benefits. But NERC also has received written comments from a dozen stakeholder groups, who were nearly unanimous in calling for a longer transition and an increase in the number of sector representatives in the new organization. Some also questioned whether security issues should be combined with operations and planning.

The collapse of the existing committee structures aims to save time and money and reduce the “silos” and inefficiencies that some NERC members believe the three existing committees have created over time.

Exelon’s Jennifer Sterling, vice chair of the Member Representatives Committee (MRC) and co-chair of the Stakeholder Engagement Team (SET) that made the proposal, led the webinar.

“The idea is that we pivot quickly and focus resources rapidly,” she explained in her opening remarks. “You are all aware that our world and our industry are changing quickly and that the pace only continues to accelerate. We need to be agile. We need to be readily deployed to address these emerging issues.”

Existing subcommittees and task forces would remain intact for the time being and report to the RSC. Subcommittees that do not have recurring tasks would be eliminated or combined with others. “The whole idea is that every subcommittee should understand what their task is,” Sterling said.

Reassurances

Sterling acknowledged some stakeholders have expressed fears that the overhaul could unintentionally eliminate networking, workshops, lessons-learned sessions and similar interactions that have developed over the years.

“That was never our intention,” she said. “We would expect that the [RSC] would continue those activities going forward.”

Sterling also addressed concerns that reducing the number of committee members would diminish transparency and stakeholder involvement. “We are committed to making sure the meetings are held in spaces that are open and that provide enough space for everyone who wishes to attend,” she said.

Potential Changes

Sterling also indicated NERC is considering potential changes to the plan based on stakeholder feedback.

The SET proposed a “hybrid” of the regional representation used by the CIPC, the sector-based membership of the PC and OC, and the at-large membership of the MRC and Reliability Issues Steering Committee (RISC).

The RSC would include one voting member from each sector (except for the regional entities), 20 at-large members, a chair and a vice chair. Members would be selected by a nominating committee of NERC officers and approved by the Board of Trustees, with selections based on interconnection diversity, subject matter expertise, and a mix of small and large entities.

“Let me emphasize the word ‘proposed’ here,” Sterling said in prefacing her description of the proposed RSC makeup.

“We have gotten a number of comments that perhaps people would like to see more sector representatives. Right now, we have one per sector, but people have asked for two. And also, there have been a number of comments that they would like to see the sectors elect their own representatives. … These will all be discussed at the upcoming [SET] meeting, and I’m sure it will be discussed next week at the MRC.”

Sterling said her team also has heard stakeholder concerns that the proposed timeline — which calls for nominating RSC members in the fourth quarter and completing the transition in the first quarter of 2020 — may be too aggressive.

Stakeholders also have expressed concern that the RSC’s name could cause confusion with the RISC. “Essentially, the RISC will be developing the lists of risks on a strategic basis,” Sterling explained. “That RISC report, along with other reports, would then be used by the RSC to develop their tactical work plans.

“There were some people who thought that name, the RSC, might be confusing,” she acknowledged. “So, we’ll talk about that as a group at our August meeting.”

Cost-benefit Analysis

Only two stakeholders had comments during the workshop. Barry Jones, of the Western Area Power Administration, asked why the plan did not include an “impact analysis.” Keen Resources’ Robert Blohm, a member of the OC, said the proposal might not produce the promised efficiencies.

“What we have now are three groups simultaneously dealing with three parts of the overall issue, saving a lot of time,” he said. “I would have been more comfortable seeing this [proposal presented in] a more objective or less presumptive fashion, where cost-benefit arguments, pro and con, are listed quite clearly.”

Sterling said the SET’s goal was achieving efficiency, “and hopefully cost savings will result.”

Mark Lauby, NERC chief reliability officer, said the revamping would increase NERC’s effectiveness at addressing issues in a holistic manner. “Going from 120, 130 people to whatever the size of this group ends up being, that will certainly be less of a burden and cost to industry,” he added.

Written Comments

The Policy Input Package for the August quarterly meetings includes written comments from 12 sets of stakeholders, including industrial consumers, cooperatives, generation owners, transmission owners, utilities and RTOs.

In addition to calling for an increase in sector representation, many of the commenters also recommended eliminating the requirement that RSC members have “executive leadership experience,” saying that subject matter expertise is more important.

The Canadian Electricity Association was among the most skeptical of the proposal. “While evolving reliability issues faced by the industry may require solutions and expertise that expand across traditional operating frameworks, many companies are still internally structured through a planning/operations/security model,” said CEA, which represents generators, transmission and distribution companies. “This reality may make it challenging to identify RSC members who can bring the necessary breadth of knowledge and experience to work across these industry areas.”

It also said issues addressed by the RSC must be “well-prioritized, while also guarding against dilution of attention due to a higher number of issues being overseen by one group rather than three.”

Several commenters said that while they agree with combining the OC and PC, they saw less synergy in combining them with the CIPC, which focuses on security.

The Electricity Consumers Resource Council (ELCON), which represents large energy consumers, recommended replacing the OC and PC while retaining a separate security committee. The ISO/RTO Council said that while “there is reasonable justification” for combining operations and planning, “including security matters in the combined group does not improve efficiency.”

The Cooperative Sector said its members were split on the restructuring. It was also critical of NERC’s transparency, saying some of its members “found it challenging to understand the deliberations of the SET meetings and that meeting notes/minutes were not provided to industry. Additionally, the proposal states that the current technical committee members were surveyed for input on the existing committee structure, but the survey results were not made public.”

Only one set of comments, from stakeholders representing state, municipal and transmission-dependent utilities, opposed the RSC proposal (Option 2) outright, saying they preferred Option 1: keeping the three committees and adding a steering committee above them.

“Option 1 provides oversight by refocusing the OC, PC and CIPC, while retaining the benefits those committees bring to NERC and the industry,” it said. “If it is not acceptable as a long-term solution, Option 1 should be adopted as the mechanism for achieving an effective and efficient transition.”

Most of the commenters called for a slower transition. Said ELCON: “Change management at this scale often takes about six months to complete.”

August 11, 2019

Forecasting, Cooperation Key to Calif. Climate Challenges

By Robert Mullin

California must find new approaches to long-term forecasting and collaboration to keep pace with the accelerating effects of climate change on the state’s energy system.

That was the key takeaway from a California Energy Commission workshop Thursday focusing on developing strategies for climate adaptation in the state’s energy sector.

For California, adaptation is currently focused on the threat of wildfires and the role power lines can play in igniting them. The fire season is becoming longer in duration, increasingly destructive to natural and built environment, and more disruptive — and deadly — for the state’s inhabitants. (See California Regulators OK Utility Wildfire Plans.)

“The motivation behind this whole effort is really the stuff that we’ve seen in the news,” said David Saah, managing principal and co-founder of Spatial Informatics Group (SIG). “We’ve seen a bunch of extreme wildfire events that impact the grid, and as it impacts the grid, it impacts all of us in terms of costs, safety [and] reliability.”

The Rim Fire is an example of California's climate challenges — Rim Fire | *U.S. Department of Agriculture*

SIG describes itself as an “environmental think tank” that combines spatial analytics with ecological, economic and social sciences to gauge the impact of policy decisions on ecosystems. The group is working with the state’s Cal-Adapt team to “deliver updated wildfire models for improved electric utility grid resiliency and safety” and support California’s next Climate Change Assessment.

Saah, an associate professor at the University of San Francisco and director of its geospatial analysis lab, explained that while much of the science behind wildfires is well understood, there are still a lot of “known unknowns,” including how to fit California’s recent large outbreaks of tree mortality into existing wildfire models to understand how “large, dead trees” affect wildfire behavior.

“We also know that our existing fire weather forecasts underestimate really severe or extreme wildfire events,” he said. “Part of that is due to the scaling; part of that is due to the technology; part of that is due to the way we have our measurements built. We know we need to deal with that.”

Saah said that current wildfire models do not forecast “a long-term trajectory of where we’re going” and therefore fail to provide investor-owned utilities a roadmap that can inform their long-term planning.

“And all this is really needed by not only the IOUs to be able to predict these overall impacts to the way they operate their systems, but it’s also needed by the taxpayer, the resident, the environment that we all have here in California,” he said.

But Saah said development of new models is not enough: Industry stakeholders must incorporate them into scenario planning.

“Our state is changing. We have this whole wildland-urban interface that we need to think of, and that interface is changing, and where it’s locating, it’s [also] growing. And the way fire behavior moves through those communities — again, it’s one of these places that we need to do better in.”

To address that shortcoming and others, SIG is developing a three-pronged approach to wildfire planning.

The first part seeks to improve the situational awareness of extreme fire weather and tree mortality through “optimal configuration” of weather stations, examination of past extreme events, and analysis and mapping of tree mortality. The second part incorporates new scientific findings into near-term forecasts and long-term projections, while the third would create models that provide IOUs and other stakeholders with “actionable information” applicable to the time scales contained in those forecasts and projections.

Once those models are developed, Saah said their “source code” should be opened to the industry and wider public for critical examination.

“The more critics that we can get hammering away at it, the more learning we can actually get,” he said.

Shifting Paradigms

California regulators have lauded San Diego Gas & Electric as a model for how the state’s utilities can prevent wildfires in their service areas. (See Calif. Regulators to Scrutinize De-energization.) The utility credits its extensive weather monitoring system for the fact that its service territory hasn’t experienced a major fire since 2007.

Brian D’Agostino, SDG&E’s director of fire science and climate adaptation, said the utility isn’t resting on its laurels. The utility is instead effectively rebuilding what was once the world’s largest utility weather network. (The state’s larger IOUs are now poised to surpass SDG&E’s network as part of their wildfire plans.)

California Climate Challenges have required utilities to closely monitor weather — San Diego Gas & Electric credits its intensive weather monitoring with preventing major wildfires since 2007. | *SDG&E*

SDG&E plans to expand its network from 177 weather stations to 225 by the end of next year, with a focus on new installations along the wildland-urban interface that can provide data every 10 seconds to support emergency operations. The new stations will be positioned to perform a new function: minimizing the customer impact of power safety power shutoffs (PSPS) undertaken during periods of high fire danger.

“It’s not just where we find the windiest areas or where this weather information will best improve our fire models, but a big part of it is we have to work with the electric engineers on the system for PSPS events,” D’Agostino said.

SDG&E has also synchronized its fire behavior models with census and building data to identify the highest-risk areas with respect to population density.

D’Agostino also pointed out that SDG&E is also incorporating its database of 455,000 trees into its fire behavior modeling systems in order to identify every tree that has the potential to hit a power line. The utility is also simulating more than 10 million fires every day to determine the risks to its entire system.

“There is a lot of room for improvement, as we’ve heard [from Saah], so we’re looking closely to continue to collaborate with the ongoing statewide projects,” D’Agostino said, expressing excitement at the “open source” nature of the effort.

Speaking during a Q&A session at the end of the workshop, CEC Commissioner Andrew McAllister noted his agency must perform 10-year forecasts to help guide development of the state’s energy system. Pointing out that the CEC increasingly relies on scenario modeling as the effects of climate change “happen more quickly than anticipated,” he asked D’Agostino how SDG&E is considering higher-than-expected temperature increases as it maps out its own long-term transmission and distribution investments.

D’Agostino said he couldn’t directly speak to the utility’s funding priorities, but that as the head of meteorology, he could point to what his department is doing differently, including adopting an approach of focusing on only the most recent years’ weather data — rather than a long historical time horizon — to predict future temperatures and weather patterns.

Another change had to do with load forecasting. D’Agostino explained that SDG&E’s peak loads have historically occurred during periods when the hot, dry Santa Ana winds blow off the desert to the east of Southern California’s population centers. But a new pattern has emerged over the last 10 years in which hot, humid air masses coming from the south are accompanied by unusually warm water currents.

“Last year, we didn’t set a new [peak] load, but our water temperature off San Diego was supposed to be about 68, 69 degrees, and it was close to 80 for almost three weeks in a row, which kept our nighttime temperatures [from] even coming down to what our normal daytime high was,” D’Agostino said. “And that went on for weeks last summer and caused a lot of challenges in operating the electric system. So, we’re seeing a new type of load.”

Reiterating the point about the speed at which climate change is occurring, CEC Vice Chair Janea Scott asked, “What kinds of things do we need to do in this space to make sure that we’re doing our best to keep up or even get out ahead of things?”

“We’re entering into this no-analog scenario,” Saah responded. “We have no idea how this thing’s going to work. If you look at the way our scientific infrastructure’s been built for a long time, it’s been built around competitive science. I think that era’s over. I think we really need to get into collaborative science. And the place where we learn from each other as quickly as we can, we [will] change things as quickly as we can.”

D’Agostino said he seconded that view: “Our ability to work with each other at this point is really going to help us move faster.”

August 8, 2019

Grid Innovation Waiting on DER Rule, Group Says

By Amanda Durish Cook

Nearly 1,000 days have passed since FERC issued a Notice of Proposed Rulemaking to remove barriers to entry from aggregated distributed energy resources participating in the country’s wholesale energy markets.

And since then, potential participants in a major grid modernization have been waiting for their cue, top executives with Advanced Energy Economy told RTO Insider in an interview.

“It’s a long time,” AEE Director Dylan Reed said. The NOPR was issued Nov. 17, 2016. The commission also proposed the same treatment for energy storage resources, which eventually led to Order 841 in February 2018, but it said it needed more information on the DER portion before it could take action, opening a separate docket (RM18-9). (See FERC Rules to Boost Storage Role in Markets.)

“We’ve had members that say, ‘We’d love to participate in these markets, but we can’t or are not going to because we don’t know what the rules will be.’ … It’s regulatory uncertainty that harms investment.”

AEE is a D.C.-based trade association representing a gamut of industry players, including those involved in energy efficiency, demand response, solar, wind, electric storage, electric vehicles, fuel cells, combined heat and power and enabling software — as well as large corporate buyers of clean energy (Microsoft, Amazon, Nest and Tesla are among its members).

The group is on a mission to identify and eliminate structural barriers to participation in U.S. wholesale energy markets, which it estimates would allow the country’s high-tech energy market to expand by $65 billion.

AEE argues that many wholesale market rules are not technology-neutral and have become too outdated to be inclusive. A FERC ruling on aggregated DER participation could jumpstart a more inclusive wholesale market, it says.

Jeff Dennis, the group’s managing director and general counsel, contends RTO market rules are still generally rooted in the past and designed with older generation in mind.

“These barriers to participation come in various different forms today,” Dennis said.

“Some are explicit barriers, but a lot of them are implicit barriers,” Reed added.

Reed pointed to MISO’s Tariff, which explicitly prohibits wind and solar generation from providing frequency regulation, spinning reserves and supplemental reserves — one of the 21 case studies AEE reviewed in a May report on real-world barriers to wholesale market participation by clean energy resources.

“It sounds like a small thing, but if you’re undercutting that, it can put financing for projects at risk,” Reed said.

Dennis also pointed to emerging proposals that could create barriers to participation, such as Study Challenges PJM Energy Storage Rule.)

“You can get a lot of capacity value out of two or four hours of discharge during that peak day. It would unfairly devalue that resource,” Dennis said.

No Risk to Cooperative Federalism

For wholesale markets to foster true competition on a technology-neutral basis, all resources should be allowed to compete on price and performance, AEE argues.

“One of the things we point out is that the markets are designed for large resources to provide lots of a product, but in the future, you’re going to have collections of smaller resources providing smaller but high-performing chunks of services,” Dennis said.

Reed added that such a grid transformation is dependent on a change in RTO market structures.

“That’s when we’re going to see a shift,” Reed said. “We’ve created these rules for all these existing resources, but the resources are changing.”

Dennis said good participation frameworks will give RTOs visibility into DER behavior and generation. He also stressed that no one is expecting perfection in early participation plans.

“There will certainly be a learning curve. I don’t want to be too hard on the RTOs,” Dennis said. But he is adamant that resources on the distribution system will be useful in providing wholesale services.

“It’s going to certainly require coordination between state and wholesale operators. FERC can play a role in ensuring that the RTOs set up frameworks for that communication and coordination,” he said.

Dennis also said distribution utilities can ask FERC to approve tariffs that allow them to recover any verifiable costs they incur from DERs participating in the wholesale markets.

“It’s not an insurmountable barrier,” he said, adding that FERC has already taken this approach with regard to distributed storage, adopting a brand of “cooperative federalism” that ensures greater utilization of those resources.

“I do worry that we’re hearing some utilities claim that FERC setting up this framework is somehow destructive to cooperative federalism,” Dennis said. “FERC has long respected state authority when it comes to wholesale participation by resources connected to distribution, and it continued to do that with storage.”

Dennis noted that, under their retail ratemaking authority, states can restrict DERs participating in retail programs from also participating in wholesale markets, which would still provide DER owners a choice of where to participate. He expects that as states gain experience with DERs, they will see the benefit in allowing wholesale DER transactions.

Despite that vision, Dennis expects the distribution system will still fundamentally serve the purpose of delivering energy to customers and not become like federally regulated transmission.

“We don’t think we’re going to see so many distributed resources participating at wholesale that it swamps the distribution system and creates a situation where [distribution and transmission] perform the same function,” he said.

In the Meantime

AEE says RTOs can take effective steps now while they wait on a FERC order, particularly in alleviating the need for DERs to undertake separate processes to interconnect with both the distribution and transmission systems.

Dennis praised PJM’s examination into how it can streamline its interconnection process for distributed resources and NYISO’s pre-emptive FERC filing to integrate DERs. AEE, however, did t ake issue with parts of the proposal, including proposed metering practices, buyer-side mitigation measures, a capacity value derate provision and a strict, six-second telemetry requirement (ER19-2276).

“I certainly appreciate that New York has gone ahead with something knowing that it’s needed, particularly in response to New York state policy,” Dennis said.

The AEE leaders say they will be pleased if FERC’s final DER rules come close to Order 841.

“I think it will look a lot like Order 841,” Dennis predicted. “We’re hoping for a rule that allows distributed energy resources to provide all the services that they’re technically capable of providing.”

AEE says that while not perfect, RTO compliance plans for storage resources are thorough and well thought out. “All of them have taken the potential of energy storage very seriously,” Dennis said.

He also expects the RTOs’ compliance with a DER rule will be as varied as their responses to Order 841. Importantly, he said, RTOs will begin that work under a FERC deadline and with commission guidance on a workable framework for participation.

“They’ll comply in their own unique way, but we’ll have markets thinking about how they can include these DERs.”

August 8, 2019

Lacking Quorum, FERC OKs ISO-NE Energy Security Plan

By Michael Kuser and Rich Heidorn Jr.

ISO-N E’s controversial proposal to compensate resources for maintaining inventoried energy during the winter months is now effective “by operation of law” because of inaction by FER C stemming from a lack of quorum (ER19-1428-0 0 1).

The commission issued an unusual Chapter 2B notice Tuesday, saying, “Pursuant to Section 205 of the Federal Power Act, in the absence of commission action on or before Aug. 5, 2019, ISO-NE’s proposal, as amended, became effective … May 28, 2019. The commission did not act on ISO-NE’s filing because of a lack of quorum at this time.”

“Since we know Commissioner LaFleur has been recused from ISO-NE matters, that means one of the other three is either (1) recused or (2) choosing not to participate for some reason. If (2) is what’s happened, that strikes me as very rare,” tweeted former FERC attorney Jeff Dennis, now general counsel for Advanced Energy Economy.

Sierra Club spokesman Brian Willis issued a statement calling FERC’s action “odd and infuriating.”

“Back in May, FERC gave ISO-NE a laundry list of what was wrong with its controversial market proposal that would have forced New England ratepayers to shell out about $150 million a year for several years to uneconomic fossil fuel plants through a ‘inventoried energy program.’ The inventoried energy program was broadly opposed by New England stakeholders, who presented evidence that ISO-NE’s program was discriminatory and unnecessary. ISO-NE refused to provide any of the additional information requested by FERC. In light of this, it appeared likely FERC would reject the inventoried energy program outright or order ISO-NE to rewrite its rules based on new principles, legal precedent or with greater consideration for costs to ratepayers.”

Dennis, however, had a different perspective. “Some version of the inventoried energy program has been approved every winter for MANY years now. No one likes it, FERC always wrings its hands when it approves it, but it always does.”

“The ISO will move forward with implementation of the short-term program as we continue working on the long-term, market-based solutions to the region’s energy security challenges,” ISO-NE spokeswoman Marcia Blomberg said in a statement. (See “Assessing ESI Risk Premiums,” NEPOOL Markets Committee Briefs: July 30, 2019.) She pointed to the RTO’s June 6 response to FERC’s request for additional information.

Chatterjee, Glick Split

Section 205 of the FPA requires each commissioner to explain his or her views with respect to the Chapter 2B changes. On Thursday, the commissioners filed their comments, with LaFleur and Commissioner Bernard McNamee indicating they had not participated.

Chairman Neil Chatterjee said he would have approved ISO-NE’s filing, saying it “provides reasonable interim compensation, which can serve as a bridge to development of the longer-term market solution.”

“It is well settled that the entity filing a proposal need only demonstrate that the proposed revisions are just and reasonable, not that the proposal is the most just and reasonable proposal,” he said. “While some parties argue that ISO New England’s previous winter reliability programs are less expensive and may be more effective than the proposal in this proceeding, those programs are not the subject of this proceeding and are not before the commission.”

Chatterjee said the program “also aims to ameliorate the misaligned incentives issue” that prior programs did not address.

But Commissioner Richard Glick said he would have opposed the program as “patently unjust and unreasonable.”

“The program will cost New England consumers as much as $300 million without any evidence to suggest that it will actually improve the region’s fuel security or that any improvement is likely to be worth the cost. Indeed, the program goes so far as to hand out substantial payments to nuclear, coal and hydropower generators with no indication that these payments will change their behavior in the slightest,” Glick wrote. “That is a windfall, not a just and reasonable rate.”

FCAs 14 & 15

The RTO’s fuel security program is an interim plan for its 14th and 15th Forward Capacity Auctions, covering the capacity commitment periods of 2023/24 and 2024/25. In March, it filed Tariff revisions; the commission on May 8 said the filing was deficient; and the RTO submitted its response on June 6.

At a July 15 technical conference, New England regulators and stakeholders told FERC that ISO-NE’s fuel security proposal could increase costs without solving the region’s winter supply concerns and urged the commission to postpone the RTO’s Oct. 15 filing deadline and require it to provide more analysis before drafting Tariff changes. (See FERC Staff Hear Doubts on ISO-NE Fuel Security Plan.)

Jeff Bentz, the New England States Committee on Electricity’s director of analysis, testified the schedule could be delayed by six months without impacting the proposed implementation.

New England Power Pool Chair Nancy Chafetz, of Customized Energy Solutions, asked the commission to “keep an open mind” on the proposals. Although NEPOOL has the “jump ball” right to propose an alternative to the RTO’s proposal, Chafetz said the stakeholder body wouldn’t have an official position until it votes in October.

According to an email from Day Pitney attorney Pat Gerity, “while NEPOOL intervened in the Chapter 2B proceeding, it took no substantive position, and absent express direction from the [Participants] Committee, will not challenge the Chapter 2B Notice.”

Gerity noted FERC had previously been unable to act on an ISO-NE filing, but Congress has since stepped in to allow such non-action by the commission to be challenged on rehearing and appeal. “Specifically, the ‘Fair Ratepayer Accountability, Transparency, and Efficiency Standards Act’ was included as part of ‘America’s Water Infrastructure Act of 2018’ (Oct. 23, 2018), the result of which will be to treat the Chapter 2B notice for purposes of rehearing to be an order issued by the FERC accepting the changes,” Gerity said, adding that any request for rehearing of the Chapter 2B notice will be due on or before Sept. 4.

Section 205 of the FPA requires each commissioner to explain his or her views with respect to the Chapter 2B changes, though none has yet filed a written comment.

In a related matter, the New England Power Generators Association asked the commission Tuesday to reverse its decision to require generators needed for fuel security to offer at zero in FCA 14. It asked the commission to issue a rehearing order by Sept. 26, “before key deadlines lapse” for the auction (ER18-2364-001 and E L 18-182-002).

August 8, 2019

NYISO Manual Changes for New SRE Penalty OK’d

In a brief teleconference meeting Wednesday, the NYISO Business Issues Committee approved manual changes to accommodate a new penalty scheme to improve the ISO’s ability to call on external capacity resources.

The revisions to the Installed Capacity Manual and Transmission and Dispatch Operations Manual, aligning them with the external supplemental resource evaluation (SRE), passed without opposition.

Under the new scheme, 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.

LBMP import transactions use an external proxy bus as the source and the NYISO reference bus as the sink. | *NYISO*

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.

The market operations report was not included in the BIC meeting materials because the data had not yet been compiled. It will be added to the meeting materials once completed, said Robb Pike, director of market design and product management.

— Michael Kuser

August 8, 2019

Earnings Soaring, NRG Prepares for Tight ERCOT Supply

By Michael Kuser

NRG Energy’s profits jumped sharply in the second quarter, boosted by a surge in earnings for the company’s power generation division.

The rise was “driven primarily by higher wholesale power prices, offset by higher retail supply costs and mild weather,” NRG CEO Mauricio Gutierrez said in a call with analysts on Wednesday.

The company repor t ed second-quarter earnings of $189 million ($0.75/share), compared to $27 million in the same period last year.

NRG’s generating arm earned $618 million for the quarter, up 145% from a year earlier, while losses from the retail division grew from $84 million to $280 million.

The company said that generation gains on hedge positions this year were partially offset by losses on retails hedges, “both driven by large movements in gas prices and ERCOT heat rates.”

During the quarter, NRG launched its “capital-light” strategy by signing approximately 1.3 GW of solar power purchase agreements at an average length of 10 years, complementing its generation portfolio. The company also highlighted that its 385-MW combined cycle Gregory plant in Corpus Christi returned to service in June.

NRG’s ERCOT data show mild weather impacting power prices. | *NRG*

Gutierrez noted NRG has spent $1.25 billion so far this year on a share buyback program and announced plans to spend $250 million more by year-end.

“We will address our plans for the remaining $259 million of 2019 excess cash, as we usually do, on the third-quarter earnings call,” Gutierrez said, noting that the company is reserving up to a $124 million in capital for the Petr a Nova project. The coal-fired power plant captures carbon dioxide from one of the eight units at the 3.65-GW WA Parish Generating Station southwest of Houston, which is then injected into mature oilfields to release more oil.

In May, NRG agreed to spend $325 million for Stream Energy’s retail electricity and natural gas business, increasing its retail portfolio by approximately 450,000 customers. The acquisition closed on Aug. 1.

Markets Update

Gutierrez said NRG expects ERCOT’s supply-demand balance to remain tight, given strong load growth, previous generator retirements and a lack of new builds. He pointed out that ERCOT’s own projections for its future supply margins rely on its semi-annual Capacity, Demand and Reserves report, which has typically been a “poor indicator of what actually gets built in the current year.”

He noted the report includes 1.7 GW of natural gas-fired generation that has been delayed an average of five years “with no signs of moving forward” and 1.4 GW of thermal generation already set to retire, while little more than half the 7 GW of solar projects listed have posted the financial security needed to interconnect to the grid.

“ERCOT needs a lot of generation … needs a lot of investment,” Gutierrez said. “And even the numbers that we’re providing you are only sufficient to maintain the current load reserve margin that we have.

“Obviously, the implication of that is we expect the ERCOT market to continue to be robust over the foreseeable future but, more importantly, to be pretty volatile,” he said. “This price environment should prove difficult for pure retailers or generators that will be exposed to swings in the market.”

Gutierrez also referred to a recent FERC Halts PJM Capacity Auction.)

“While we’re hopeful a final order will be issued by the end of the year, the timeline for FERC action remains uncertain,” Gutierrez said. “We continue to view a strong [minimum offer price rule] as the simplest and most cost-effective way to reduce the harmful impact of subsidies on the capacity market.”

Call transcript courtesy of Seeking Alpha.