ERCOT’s Board of Directors gathered briefly in a conference call April 14 to discuss the grid operator’s response to the COVID-19 pandemic.
CEO Bill Magness, acknowledging the “unusual meeting format,” detailed ERCOT’s plans and actions taken since March 3, when the Texas grid operator first limited employee travel and directed that all meetings be conducted via webinars or teleconferences. Staff were directed to work from home on March 18 if they did not have on-site responsibilities, an order that extends through May 3.
He thanked employees and contractors for staying in regular contact with ERCOT stakeholders and “working to ensure our response is coordinated with theirs.”
“In the best of times, ERCOT employees are good problem solvers and devoted to their mission,” Magness said. “Those characteristics have proven extremely important during these difficult times.”
ERCOT will continue to develop contingency plans to protect the health of on-site workers “before conditions become closer to normal,” Magness said. He said it continues to solicit advice and guidance from public health and regulatory authorities, its U.S. and Canadian grid operator counterparts and the Texas electric industry.
“There is great uncertainty about many things in today’s world, but I feel confident the Texas summer will still be hot,” he said.
ERCOT said in March that it foresees record electric usage and tight reserves this summer, but that it has sufficient capacity on hand. It plans to release a final summer resource adequacy report and a capacity report in May. (See ERCOT Sees Summer Repeat: Record Peak, Tight Reserves.)
COVID-19 has begun to have a larger effect on the grid operator’s load patterns, according to its most recent analysis. Daily peaks were consistently lower during the week beginning April 5, dropping about 2% despite several hot days. Energy usage was down 4 to 5% during the week.
Virus’ Effects Begin to Affect Load Patterns
ERCOT on Thursday told the Texas Public Utility Commission that it has entered into loan agreements with Texas’ transmission and distribution utilities — Oncor, CenterPoint Energy, AEP Texas and Texas-New Mexico Power — to fully fund a $15 million COVID-19 relief program for residential customers having difficulty paying their bills (50664).
The PUC in March ordered the fund’s creation. It applies to customers within ERCOT’s footprint.
Board Approves 4 Change Requests
The board unanimously approved three Nodal Protocol revision requests (NPRR) and a single change to the Planning Guide (PGRR):
NPRR953: defines “relay loadability rating” to align with NERC’s definition changes, which adds a requirement to include protection system limitations for operational planning analysis and real-time assessments. The changes also support ERCOT housing and monitoring the relay loadability rating in Energy Management System applications.
NPRR997: requires an entity controlling a primarily natural gas-fired generation resource to supply ERCOT with a declaration contained in the summer weather preparedness form. The declaration should state that the resource entity or the resource entity’s qualified scheduling entity has made a written effort to communicate with the operator of each gas pipeline directly connected to the entity’s generation resource to coordinate any planned pipeline outages to maximize the resource’s availability during the summer peak load season.
NPRR998: establishes a requirement that ERCOT post all emergency response service deployments and recalls to the Market Information System’s public area.
PGRR075: requires resource entities and interconnecting entities to provide model-quality test results that demonstrate appropriate performance for submitted dynamic models. Also clarifies that dynamic model data shall be provided using the appropriate dynamic model template; raises awareness of requirements associated with user-written dynamic models; and makes various miscellaneous language updates and corrections, including the elimination of a section superseded by NERC Reliability Standard PRC-002-2 and a Nodal Operating Guide section on phasor measurement recording equipment.
FERC on Thursday granted NYISO a waiver of the Tariff language defining a public power entity, extending the definition to cover any government entity, regardless of whether it owns or controls distribution facilities and provides electric service (ER20-922).
The ISO in January requested the waiver of Section 26.5.3.6 of its Market Administration and Control Area Services Tariff in order to allow it to continue granting unsecured credit, up to $1 million annually each, to government entities that do not meet the definition of public power entity.
NYISO also said it is working with stakeholders to revise the relevant definition and seek approval from the commission.
“NYISO acted in good faith because it did not intentionally disregard the limitations set forth in the currently effective definition of public power entity and … took this self-correcting action promptly upon discovering the limitation in its current definition,” the commission said.
The ISO said it extended unsecured credit to government entities, regardless of whether they own or control distribution facilities and provide electric service, based on a good faith understanding of how Section 26.5.3.6 should be administered in light of the credit profiles of government entities.
Workers do maintenance on a turbine in a New York Power Authority project. | NYPA
The commission also found NYISO’s waiver request was limited in scope, being in place for nine months and only involving a subsection of a definition, noting that the ISO said that it may not need the waiver for the full nine months.
FERC said that granting the waiver will avoid needlessly creating practical business difficulties for certain municipal and government entities. It is also consistent with the underlying Tariff recognition that municipal entities generally do not present significant risk of nonpayment but are unable to demonstrate creditworthiness through conventional indicators, the commission said.
NYISO identified 10 municipalities or other government entities that would be affected by the requested waiver, resulting in an extension of up to $10 million in unsecured credit among them.
Finally, the commission found that the waiver request would not have undesirable consequences “because, as NYISO explains, there has not been any material increase to the financial risks of NYISO or other market participants, and denying the requested waiver could needlessly harm government entities that do not own or control distribution facilities and provide electric service.”
Given that the ISO admitted to having been violating the Tariff definition since as early as 2004, the commission said it would “exercise our discretion in addressing such matters and, given the facts and the record before us in this matter, take no action with respect to the instances of NYISO’s past noncompliance.”
During a webinar Thursday discussing a recent white paper on fast frequency response (FFR), IRPTF members observed that the shift toward renewable resources such as wind and solar energy has made many parts of the grid less resilient overall. This effect is especially visible in the Texas interconnection, where the addition of new generators to a more limited existing base has a larger effect.
“We’re seeing changes in system inertia that are affecting ROCOF [rate of change of frequency]; we’re needing to ensure that we have sufficient reserves available; and more importantly than ever before, we’re needing to focus on the speed and the magnitude of those reserves to make sure we get a sufficient response that we need in a given time frame,” said Ryan Quint, NERC’s lead engineer for advanced system analytics and modeling.
New Generation Demands New Approach
The primary focus of the white paper and the webinar’s discussion was the fundamental difference between traditional synchronous generation and nonsynchronous resources, which require different responses to sudden changes in system frequency that can be caused by widespread outages or loss of generating capacity.
While traditional thermal generators can typically be spun up relatively quickly to restore the target frequency — serving as primary frequency response — this is much harder to do with solar and wind power that cannot be increased on demand. To handle those situations, utilities are encouraged to invest in FFR resources, which can quickly inject power into or absorb it from the grid as needed to prevent underfrequency load-shedding events.
Using renewable resources for this purpose is made more challenging by the fact that, for economic reasons, photovoltaic and wind turbines are normally run at the maximum capacity allowed by weather conditions.
“Because they’re operating at the maximum power … they can reduce power as the frequency increases, but they do not have any excess available to increase power when the frequency dips,” said Siddharth Pant, senior managing engineer at GE Power Conversion. “[But] if the economics were attractive or they were forced by regulation, or if FFR was made an auxiliary service, you could operate a PV plant in a curtailed mode … so it could provide increasing power at lower frequencies.”
The white paper also examined potential benefits from grid-connected battery storage solutions, as well as techniques for adjusting the frequency output of wind turbines without changing rotational speed, though IRPTF stressed that these studies are still at a preliminary stage.
Participants noted that FERC appeared to address some frequency response challenges by requiring newly interconnecting generators to have the capacity to respond automatically to frequency disturbances (Order 842, RM16-6). Quint described this requirement as a step in the right direction, but said more work needs to be done by balancing authorities to identify when new FFR capabilities are needed and ensure all facilities are operating to the same standards.
[NOTE: This article has been updated to include excerpts from the orders, which were not available at press time Thursday.]
By Rich Heidorn Jr.
FERC on Thursday clarified that voluntary renewable energy credits (RECs) and participation in the Regional Greenhouse Gas Initiative (RGGI) will not subject capacity resources to PJM’s expanded minimum offer price rule (MOPR).
The commission rejected rehearing of its June 2018 order declaring PJM’s capacity market unjust and unreasonable (EL16-49-001, et al.) and virtually all of its December 2019 ruling spelling out the expanded MOPR (EL16-49-002, et al.) but provided clarification on several points.
FERC directed PJM to make a compliance filing within 45 days to set the default offer price floor for new energy efficiency resources at the net cost of new entry (CONE) and existing energy efficiency resources at the net avoidable cost rate (ACR).
Changes on EE, Interconnection Agreements
Noting PJM’s concern with the difficulty of calculating price floors based on verifiable efficiency savings, and the fact that those savings cannot be verified until the resource is in operation, FERC said the default offer price floor for EE “must be based on the costs of installing and maintaining energy efficiency resources, similar to how the default offer price floors for most other resource types are determined.”
It clarified that EE may also request the unit-specific exemptions to verify a Net CONE or Net ACR value lower than the default.
The commission also ordered PJM to file Tariff revisions expanding eligibility for the categorical MOPR exemption to include new resources that had obtained interconnection service agreements, wholesale market participant agreements or interconnection construction service agreements — the final stages of interconnecting to the PJM system — prior to the December order.
“The categorical exemptions were designed so as to not unduly disrupt established investment decisions,” the commission said. “… Resources that have not reached this stage of the interconnection process are not sufficiently advanced in the development process to warrant one of the categorical exemptions.”
Chairman Neil Chatterjee announced the decisions at the commission’s monthly open meeting, which was held via teleconference because of the COVID-19 pandemic. Chatterjee reiterated that the commission’s directive was needed to respond to subsidized resources that he said are suppressing prices in PJM’s capacity market. The new rules, he said, will result in a “level playing field” for unsubsidized generation.
`Stunningly Awful’
Commissioner Richard Glick, who dissented on the two original orders, repeated his criticism Thursday, calling the rehearing orders “stunningly awful” and the majority’s logic “just plain garbage.”
“At his December press conference, Chairman Chatterjee made an astounding admission: The commission issued the MOPR order without even considering the impact of this order on consumers. Today the commission continues to blunder down that path without attempting to assess the billions of dollars it will impose on customers. And I believe that abdicates our regulatory duty.”
Glick rejected the majority’s contention that it needed to act to protect the competitiveness of the wholesale market. If that were the motivation, he said, the commission would not have exempted subsidies such as siting incentives, subsidies that previously went to conventional generation or federal subsidies.
He said the commission “twisted itself into a pretzel” on the issue of federal subsidies.
“The commission argues that it can’t subject federal subsidies to the MOPR because that would block Congress’ policy objectives,” he said. But when parties said in rehearing requests that the ruling was frustrating state policy in support of renewables, “the commission’s response is that the MOPR does no such thing. The commission cannot and should not have it both ways,” he said.
Glick said the real motivation for the order is to counter state efforts to address the externalities of greenhouse gas emissions from fossil fuel generators. “That appears to be bothering this commission,” he said.
In a press conference after the meeting, Chatterjee rejected Glick’s criticism. “These are well reasoned orders, and broad attacks like that mean very little,” he said.
Chatterjee also disputed Glick’s contention that the expanded MOPR will cost consumers billions — a prediction that some, including PJM’s Independent Market Monitor, have disputed.
The IMM released an analysis last month that concluded that expanding the MOPR will not have an impact on clearing prices or auction revenues for the next Base Residual Auction, for delivery year 2022/23. (See MOPR May Not be Death Knell for Renewables in PJM.)
Rehearing Rejected
The commission rejected arguments that it failed to cite evidence that state out-of-market support is causing price suppression.
“These rehearing arguments rest on the faulty assumption that, in order for the commission to sufficiently support its Section 206 finding that PJM’s existing Tariff is unjust and unreasonable, the commission is required to analyze the results of previous capacity auctions and demonstrate that that state subsidies have had a significant price suppressive effect,” FERC said. “Rather, to support its Section 206 finding, it was appropriate for the commission to rely on record evidence and basic economic theory to conclude that PJM’s existing Tariff does not account for and mitigate the price suppressive impact of state subsidies… While the June 2018 order does not find that any particular capacity auction has produced unjust and unreasonable results, the commission need not wait to address price distortions from subsidized resources until it finds that the capacity auction has produced unjust and unreasonable results.”
It also dismissed arguments that an efficient market would price environmental externalities as “not relevant.”
“The purpose of a capacity market is to ensure resource adequacy at just and reasonable rates, not to mitigate the negative externalities associated with the production of electricity,” it said.
FERC also rebuffed claims that it had failed to follow precedent because it previously found that renewable resources do not pose a threat of price suppression. “Circumstances have changed. Evolution of the commission’s policy is justified in response to the proliferation of out-of-market support to resources that permit these resources to offer non-competitively and suppress prices,” it said.
And it said its orders did not violate state sovereignty, saying out-of-market payments such as RECs and zero-emission credits for nuclear plants allow resources to make capacity market offers below costs. “Because these programs disrupt competitive price signals that PJM’s capacity auction is designed to produce, we are obligated to act to deter uneconomic participation,” it said.
Glick’s dissents on Thursday’s rehearing orders criticized the commission for “a degree of condescension that is unbecoming of an agency of the federal government.”
He said the majority was abusing the MOPR concept, transforming “a narrowly tailored anti-monopsony measure into a regime for blocking state efforts to shape the generation mix.”
Glick predicted the orders will result in the “fracture” of PJM, the largest RTO in the country.
“States throughout the region are already looking for ways to pull their utilities out of the capacity market rather than remain under rules designed to damage their interests. Today’s orders snuff out what little hope may have remained that the commission would again change course and adopt a more sensible market design.”
Next Steps
The commission on Thursday also dismissed as moot a complaint by CPV Power Holdings over PJM’s MOPR, saying the relief the company had sought was addressed by the June 2018 and December 2019 orders (EL18-169).
The commission also denied requests for rehearing of its April 2019 order approving PJM’s quadrennial revision of the variable resource requirement (VRR) — the demand curve for the capacity market — rejecting complaints that it results in over-procurement of capacity. The order affirms PJM’s selection of the CT H-class turbine as the reference resource (ER19-105-004). The Sierra Club and the Natural Resources Defense Council released a study in February alleging PJM’s over-procurement costs consumers billions annually.
By ruling on the rehearing orders, FERC started a 60-day clock for those who want to challenge the commission’s rulings before the D.C. Circuit Court of Appeals. Dozens of stakeholders filed requests for rehearing or clarification of the December order, with some observers predicting the issue will end up before the Supreme Court. (See PJM MOPR Rehearing Requests Pour into FERC.)
Reaction
The New Jersey Board of Public Utilities issued a statement saying it is “deeply disappointed that FERC has once again sided with the fossil fuel industry rather than allowing states to implement policies that best benefit their residents. The decision fails to recognize the important steps we must take to address the impacts of climate change on New Jersey. We will fight this decision as vigorously as possible at every opportunity, and we will not let FERC’s actions stand in the way of implementing Gov. [Phil] Murphy’s clean energy vision. The governor is committed to continuing the battle against the devastating impacts of climate change and creating a safer, healthier environment and economy for all New Jerseyans.” The BPU last month opened an investigation to consider alternatives to the PJM capacity market. (See N.J. Investigating Alternatives to PJM Capacity Market.)
Jeff Dennis, managing director and general counsel for Advanced Energy Economy, said, “FERC’s decision to deny rehearing will only increase the growing tension and costly misalignment between state clean energy policies and federally regulated wholesale markets.”
But Todd Snitchler, CEO of the Electric Power Supply Association, praised the rulings. “FERC and Chairman Chatterjee today put consumers first by clarifying a ruling with significant impacts for 65 million electricity customers in PJM and nationwide. This is a step toward resolving concerns surrounding state goals and regional power markets, and we are pleased to see the commission act swiftly in support of fair competition in PJM’s capacity market.”
FERC’s exemption of RGGI and voluntary RECs from MOPR was consistent with the compliance filing PJM filed in March, which said capacity resources that generate RECs can use the MOPR’s competitive exemption if they certify that the credits will only be used and retired for voluntary obligations rather than state-mandated renewable portfolio standards. (See PJM Makes MOPR Compliance Filing.) Comments on PJM’s compliance filing are due May 15.
Chatterjee declined to comment on how quickly the commission will act on the compliance filing, but he did address concerns that some states might seek to pull their utilities out of the capacity market as a result of the ruling.
“Organized, competitive markets bring significant benefits to consumers, and I think state leaders will be really hard-pressed to ignore that,” he said. “From my view, I think that state leaders will wait to see how this plays out, wait and see how the auctions go and then reassess.”
Monitor: Maryland FRR Likely to Increase Capacity Costs
Also on Thursday, the Monitor released a report concluding that Maryland customers would likely pay higher capacity prices if the state’s utilities left PJM’s Reliability Pricing Model and acquired their capacity through a fixed resource requirement (FRR).
In five of six scenarios considered, Maryland ratepayers within the FRR would see capacity costs increase by 6 to almost 43%, while the state’s overall costs would be either unchanged or rise by as much as 23%. One scenario — the creation of an FRR for the Maryland portion of the Pepco locational deliverability area (LDA) — suggested costs within the LDA could drop by 5% and the rest of the state by 1%.
“Based on the analysis, the creation of a Maryland FRR, a BGE FRR or a Pepco/MD FRR, is likely to increase payments for capacity by customers in Maryland,” the Monitor said. “Creation of an FRR creates market power for the small number of local generation owners from whom generation must be purchased in order to meet the reliability requirements of the FRR entities. There is at least one single pivotal supplier in each of the Maryland, BGE and Pepco FRRs, which means that there is at least one generation owner, and in some cases more, that has monopoly power in each case.
“In the FRR approach, there is no PJM market monitoring of offer behavior by generation owners; there are no market rules governing offers; and there are no market rules requiring competitive behavior,” the Monitor continued. “As a result, even the higher estimates of the cost impact to the customers of Maryland from the creation of an FRR are likely to be conservatively low. If Maryland were to subsidize any generating units, the subsidy costs would be in addition to the direct FRR costs.”
The Monitor released a report in December that concluded that creation of an FRR in Commonwealth Edison’s LDA in Illinois was likely to increase capacity costs for ComEd customers while reducing capacity costs elsewhere in the RTO.
FERC rejected ISO-NE’s request to rehear its decision requiring the RTO to revise its energy storage rules to account for a resource’s state of charge in the day-ahead market (ER19-470-003).
The commission last November conditionally accepted ISO-NE’s Order 841 compliance filing, asking for additional changes to clarify the application of transmission charges to electric storage resources — an aspect of the ruling the RTO did not contest. (See Storage Plans Clear FERC with Conditions.)
But ISO-NE did seek rehearing of FERC’s determination that the proposal failed to show how the RTO would account for maximum run time and charge time, state of charge, and maximum and minimum state of charge in its day-ahead market, leaving storage resources open to infeasible schedules.
In its rehearing request, ISO-NE said that FERC erred in finding that the proposal failed to account for state of charge in the day-ahead market, contending that storage resources could account for their day-ahead state of charge by incorporating that state of charge into their maximum daily energy limit and maximum daily consumption limit parameters.
The 1,143-MW Northfield Mountain pumped storage hydro facility | FirstLight Power Resources
ISO-NE also argued that the commission’s requirement that the RTO “account for the resource’s state of charge at the start of each day-ahead market interval” would not prevent a storage resource from receiving an infeasible schedule.
In Thursday’s order, the commission emphasized that Order 841 defines state of charge (as a bidding parameter) as the level of energy that an electric storage resource is anticipated to have available at the start of the market interval rather than at the end.
FERC found the day-ahead market provisions in ISO-NE’s proposal do not comply with Order 841, which requires RTOs to account for state of charge so that electric storage resources can participate in the energy market without receiving dispatch points that violate their physical and operational limits.
“ISO-NE fails to recognize that its maximum daily energy limit and maximum daily consumption limit parameters only account for the cumulative amount of energy an electric storage resource can charge or discharge over the entire operating day, as opposed to at the start of each market interval,” the commission said.
The RTO had also contended that the commission had not given due weight to its efforts to integrate co-located storage resources into its markets. But FERC found that the fact that ISO-NE’s failure to account for state of charge and duration characteristics in the day-ahead market might better accommodate co-located facilities had no bearing on whether its electric storage resource participation model complies with Order 841.
The commission also found that issues regarding “the participation of electric storage resources co-located with other resources in ISO-NE markets are beyond the scope of this proceeding because Order No. 841 did not address co-location of electric storage resources with other resources.”
“We note, however, that nothing in the commission’s directives precludes ISO-NE from developing market rules tailored to electric storage resources that are co-located with generation,” the order said.
Finally, ISO-NE had argued that investing time and resources to change the day-ahead market on the current software platform would not be cost-effective while it is in the process of building a new platform. It requested that if rehearing was denied, the commission allow for an effective date of Jan. 1, 2026. FERC said it would address the effective date separately (ER19-470-004).
MISO is mounting a third attempt to gain FERC approval of a plan to overhaul the cost allocation design for economic transmission projects after two previous rejections.
This time the RTO will eliminate the local economic transmission project category from its proposal, a sticking point in the earlier filings.
FERC rejected MISO’s proposed cost allocation a second time on March 20, raising the same cost-causation issues that dogged the first filing (ER20-857). The commission took issue with MISO’s proposal to measure the value of a local economic project on a regional basis but cost-share only locally. The local economic project category was intended for smaller, economically driven transmission projects between 100 and 230 kV, where 100% of costs would be allocated to the local transmission pricing zone containing the line. (See Another Rejection for MISO Cost Allocation Plan.)
MISO said it will follow FERC’s recommendation to refile the regional allocation without including the local economic project category.
MISO Senior Manager of System Planning Jarred Miland said it would likely take months for stakeholders to reach consensus on how to treat 100- to 230-kV economically beneficial projects.
“We want to get this thing done, get this thing out. We feel we have support right now on the other parts,” Miland said during a Thursday conference call of the Regional Expansion Criteria and Benefits Working Group.
As in the first two filings, MISO’s newest proposal would lower the voltage threshold for market efficiency projects (MEPs) from 345 kV to 230 kV, eliminate the current 20% postage stamp allocation and add new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path. The proposal will also provide limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability.
“Everything will be pretty much like it was in the January filing. It’ll look pretty much the same; it just won’t have the local economic project component to it,” Miland said.
Clean Grid Alliance’s Natalie McIntire asked how economically beneficial projects between 100 and 230 kV will be treated going forward.
Miland said such projects would again be relegated to MISO’s “economic other” project category, which has no regional benefits test and dictates that smaller economically beneficial projects be allocated to the transmission pricing zone in which they are located.
However, he pointed out that the new lower voltage threshold for MEPs will most likely result in MISO approving more economic projects for cost-sharing.
Miland also said regional economic projects between 100 and 230 kV are rare in MISO.
“We haven’t seen much below 230 kV in the past, so I doubt we’ll see more in the future,” he said.
MISO said it will resubmit its regional cost allocation filing by the end of the month or in early May.
Miland said MISO will not collect stakeholder feedback on the refiling, added that FERC’s direction was specific enough and the RTO’s previous efforts have “already been a really, really long journey.”
As with the first two filings, MISO will again include a promise to review the effectiveness of the cost allocation approach after three years.
SATOA Tech Conference Set
MISO faces another obstacle related to the allocation of transmission project costs: the lack of an approved cost recovery mechanism for its first storage-as-only-transmission-asset (SATOA) project.
FERC scheduled a May 4 technical conference to discuss possible shortcomings with MISO’s SATOA proposal. (See MISO SATOA Proposal Set for Technical Conference.) The commission said MISO officials should come prepared to answer several questions, including those regarding:
the proposed evaluation and selection of SATOA as transmission-specific solutions;
why SATOA shouldn’t be allowed access to energy markets;
how the existing formula rate provides a cost recovery process for SATOA;
the possible impact of SATOA on the generator interconnection queue; and
state-of-charge responsibility.
MISO’s 2019 Transmission Expansion Plan (MTEP 19) contains the RTO’s first-ever SATOA project — American Transmission Co.’s Waupaca-area energy storage project, intended to ease transmission reliability issues in central Wisconsin — which was withheld from final MTEP 19 approval as the RTO waited on approval for its proposed SATOA rules. MISO had planned to have its Board of Directors hold a special March vote on the project once it had FERC’s go-ahead for its rules and cost-recovery method. (See MTEP 19 Could Yield First MISO SATA Project.)
The American Wind Energy Association on Thursday reported a “banner year” for the wind industry in 2019 but also acknowledged the storm clouds gathering on the horizon.
John Hensley, AWEA’s vice president of research and analytics, said 25 GW of projects — representing $35 billion in investment capital and tens of thousands of jobs — are at risk because of the COVID-19 pandemic. He pointed to national lockdowns in India and Spain and a slowdown in China as disrupting the industry’s supply chain and delaying some projects.
“The U.S wind industry is not immune to COVID-19 yet,” Hensley said. “We’re being impacted like any other industry.”
Indeed, General Electric’s LM Wind Power plant in Grand Forks, N.D., announced it will close for at least 14 days as state officials linked 128 positive cases of the coronavirus to the factory, which makes turbine blades.
Repowering activities at Pacificorp’s Goodnoe Hills Wind Farm in Washington | AWEA
The industry faces several challenges. It and other clean-energy sectors lost more than 106,000 jobs in March, according to a report by BW Research Partnership prepared for climate advocacy group E2. And those sectors will have a tough time arguing to the Republican-controlled Senate for inclusion in any further stimulus legislation that Congress may — or may not — pass. (See Renewable Tax Credit Extensions Not in Stimulus Bill.)
Hensley said AWEA is working with Congress to gain some “immediate flexibility” and stave off further losses. He said an extension of the safe harbor continuity window for wind projects begun in 2016 and 2017 “will address the immediate impact the developers are experiencing.”
Having learned that tax equity is becoming a concern, AWEA is also pursuing additional relief in the form of direct tax payments.
“Congress has been supportive,” Hensley said. “We do hope to have their continued support, so that clean energy can continue creating jobs.”
Wind power capacity grew 9.6% in 2019, with an additional 9.1 GW pushing total capacity to 105.6 GW. | AWEA
Otherwise, AWEA had nothing but good news to report. According to its “Wind Powers America 2019 Annual Report,” wind turbines are now the single largest provider of renewable energy in the U.S., surpassing hydro power to account for 7.2% of the nation’s electricity production.
Wind capacity cracked the 100-GW barrier in 2019, reaching 105.6 GW with 9.1 GW of new capacity and $14 billion in new projects. AWEA said the industry employed 120,000 people and provided $1.6 billion in local payments to communities and landowners last year.
Developers delivered 55 projects in 19 states during 2019, with Texas and Iowa both adding more than 1 GW of wind capacity. Texas has 3.9 GW of wind capacity and Iowa 1.7 GW. Wind energy provided more than 20% of generation in Iowa, Kansas, Maine, North Dakota, Oklahoma and South Dakota.
All seven U.S. grid operators set records last year for wind output and, with the exception of ISO-NE, for wind penetration. ERCOT produced a record 19,672 MW of wind energy last year, and SPP established a top mark for wind penetration at 68.8% (since raised to 72.4% on April 2).
ISOs and RTOs set wind output and penetration records in 2019. | AWEA
Utility and corporate buyers, taking advantage of wind costs that have fallen more than 70% during the last decade, also set records in 2019 with more than 8.7 GW of new power purchase agreements. Berkshire Hathaway Energy and Xcel Energy dominate the market with more than 16 GW of capacity between them; Google Energy is the only corporate buyer among the top 10, with 1.4 GW of capacity.
AWEA said the industry began 2020 with a near-record project pipeline of 44 GW of capacity either under construction or in advanced stages of development. Hensley said that while the organization continues to see projects moving forward, “It’s too early to know the full extent of those delays on construction plans.”
“Affordable, reliable energy is not a luxury — it’s a necessity,” AWEA CEO Tom Kiernan said in a statement. “While we are now working to mitigate the significant disruptions from COVID-19, we know that we will meet these challenges with strong industry momentum.”
James Danly attended his first FERC open meeting as a commissioner Thursday, albeit virtually, as the proceeding was held by teleconference because of the COVID-19 pandemic.
Danly, who served as general counsel for the commission from September 2017 until March 31, did not issue any concurrences or dissents during the meeting, joining Chairman Neil Chatterjee in voting “aye” on the consent agenda. But he did give some insight into his priorities and regulatory philosophy during his opening remarks.
He listed “correctly incentivizing needed transmission,” ensuring electric reliability and “the efficient and thorough review of our certificate applications” as his top issues.
FERC’s approvals of gas infrastructure “have been challenged repeatedly with ever greater frequency in the courts, and we have a nearly unblemished affirmance rate for the last two and a half years,” he said. “That is a testament to the reasoned decision-making of the commission in issuing these orders and to the legal durability of the commission’s orders. … I am adamant that we continue to maintain those high standards in our certificate issuances.”
He also said he was “committed to further refining the pricings in our markets,” asserting that the commission’s rejection Thursday of rehearing requests on its order expanding the minimum offer price rule in PJM “marks an important step in ensuring accurate price signals in the capacity market. But I think there’s more to be done.” He said he was interested in looking at pricing in the energy markets, as well as “the price effects of the participation of non-energy-producing resources in the capacity market.” (See related story, FERC: RGGI, Voluntary RECs Exempt from MOPR.)
Danly concluded with his ideology. “We have to respect the federalist principles that are enshrined both in our authorizing statutes and the Constitution. You know, the commission is not in the business of — typically not in the business of pre-empting state actions. What we do is administer the matters in our jurisdiction, specifically the wholesale rates in interstate commerce. …
“We need to observe those lines of authority that Congress has laid out for us. And on that subject, I don’t think the commission should be quick to expand its jurisdiction. As tempting as it can be sometimes, Congress has laid those lines very scrupulously, and we should follow them scrupulously. …
“Reasoned decision-making is not simply a sine qua non. … It is what the entities who we regulate deserve. … I would like to see us dispense with as much case-by-case analysis as possible when unambiguous, bright-line rules are feasible.”
In his own opening remarks, Commissioner Richard Glick welcomed Danly and remarked on his impressive vocabulary, including his frequent usage of Latin terms. Because of that, he said, he had a Black’s Law dictionary on hand. At the end of the meeting, Glick explained that sine qua non meant “an indispensable requisite.”
Danly also announced the first two members of his staff, who followed him from the Office of General Counsel: Matthew Estes, a former colleague of his at Skadden, Arps, Slate, Meagher & Flom; and Kyrstin Wallach, a 2017 graduate of the George Washington University Law School.
Longview Power, a 710-MW supercritical coal-fired generator that claims to be the most efficient coal facility in North America, filed for bankruptcy Wednesday — for the second time.
Its first bankruptcy in 2013 — when it said malfunctioning equipment hampered its operations — resulted in lenders taking all the equity in the company.
This time, the company says it was done in by liquidity problems resulting from rock-bottom natural gas prices, the loss of a nearby mine, and warm winters and energy efficiency that suppressed demand.
The COVID-19 pandemic didn’t help either, CEO Jeffery L. Keffer said in a 21-page affidavit that accompanied the company’s Chapter 11 filing in U.S. Bankruptcy Court in Wilmington, Del. The company, which said the plant generated $28.1 million of adjusted EBITDA in 2019, has $355 million in debt.
Longview Power plant near Morgantown, W.Va. | Longview Power
But the company said it has a prepackaged agreement that will allow it to emerge with lower debt. The company has been approved for a Payroll Protection Program loan to cover the wages of its 140 employees and says it plans to continue operations uninterrupted — and even expand with a 1,210-MW combined cycle gas turbine (CCGT) plant and a 70-MW solar farm. Keffer noted, without apparent irony, that the additional generation would increase revenues “at lower fixed costs per kilowatt” than the coal plant.
But Keffer insists that the coal plant isn’t a white elephant. “Despite recent trends, the PJM region requires a dependable coal-fired option in place for when energy demands inevitably increase. At times of national crisis, dependable utilities are at their most essential, and one key feature distinguishes coal from other existing energy sources — it can be stored.”
The $2 billion plant in Maidsville, W.Va., was “the first clean coal facility,” Keffer said, with equipment designed to be “one of the most environmentally compliant and cleanest coal plants globally.”
With an 8,750-Btu/kWh heat rate, 20% more efficient than older technology coal plants, “Longview is the future of coal,” the company’s website boasts. Indeed, Energy Secretary Rick Perry deemed it so in a 2017 visit.
But after two bankruptcies, does Longview have a future, or are the plant’s owners whistling past the graveyard? And what does its struggles say about the fate of the nation’s less efficient coal-fired generators?
Michelle Bloodworth, CEO of coal trade group America’s Power (formerly the American Coalition for Clean Coal Electricity), said wholesale markets are failing to compensate coal plants for their resilience and fuel security attributes.
“The exorbitant support in the form of subsidies, over $100 billion, that renewable sources of electricity have received over the past several decades has only further distorted the electricity markets,” she said. “We remain concerned that unless action is soon taken to address these flaws, more coal plant owners could be in the situation that Longview Power is in — which will mean we risk further loss of an important piece of a diverse electricity grid.”
Star-Crossed
Longview has had a star-crossed history.
The plant was designed with infrastructure to allow for development of a second “clean coal” generator, including a 4-mile-long conveyer belt to carry coal to the plant from a nearby mine owned by a Longview subsidiary, Mepco Holdings.
But when the plant went into operation in 2011 following construction delays, unscheduled outages and extended planned outages left the plant running at a capacity factor of only 68%, well below its design level of 90%.
Longview began a multiyear arbitration with its building contractors; unable to repay a $1 billion loan that helped fund construction, it filed for Chapter 11 protection in August 2013.
It emerged from bankruptcy in April 2015, with the company winning repairs to the plant and a $325 million loan as the original lenders took all the equity in the reorganized company.
Where Longview Power says it resides on PJM’s supply curve | Longview Power
Since the repairs, the plant has generally operated at its design levels, Keffer said.
But it was saddled with high financing costs, including a $30 million senior note at 12%. Then, in 2018, Mepco discontinued operations at all of its mines, including the one supplying Longview, citing “the aging of the mine and adverse geological conditions” that reduced its productivity and made it uncompetitive.
With the 4-mile conveyor belt no longer of any use, the company spent $8.3 million on a dock on the Monongahela River to receive coal deliveries from other mines.
“Under normal operating conditions, the debtors’ steady cash flows enable them to reliably service their funded debt obligations and weather ordinary variations in customer demands, but recent extraordinary fluctuations in the energy market have presented the debtors with new balance sheet challenges,” the company said in its filing.
In addition to the “demand destruction” resulting from energy efficiency and warm winters in PJM, “the coronavirus pandemic has resulted in significant reductions in demand as industrial and commercial users are shut down throughout the region and country,” it added.
Although they designed the site to accommodate a second coal generator, company officials now say they will add a 1,210-MW CCGT and a 70-MW solar farm. “Realization of these development plans would provide operational and fuel diversity to help shelter Longview from the volatility of energy industry trends in the long term,” Keffer said.
Will the company get there?
Despite its efforts to reduce operating costs, renegotiate fuel contracts and seek cheaper financing, the company began “reviewing strategic alternatives” in January 2020. On March 31, the company and lenders reached a forbearance agreement on a $750,000 amortization payment due that day.
With that breathing room — and facing the inability to pay off a $25 million revolving debt that matured on April 13 — the company reached the prepackaged reorganization with its lenders. Twelve investment funds currently own almost 96% of Longview Intermediate Holdings, the plant’s parent company, led by KKR Credit Advisors with 42%. The Wall Street Journal reported that KKR will lose nearly all of its ownership in the deal.
Keffer said the plan will allow “a comprehensive balance sheet restructuring that will reduce Longview’s debt burden, increase liquidity and send a strong message to Longview’s employees, vendors and other business partners that Longview is well positioned for future success.”
Proportion of units recovering avoidable costs: 2011-19 | Monitoring Analytics
The deal will eliminate $350 million of first lien and subordinated debt and provide the company a $40 million
“exit facility” loan from secured term lenders that will take a 90% stake in the reorganized company. It also allows “unimpaired” payments to unsecured creditors to ensure “minimal impact on the debtors’ operations and their key business partners.”
The company asked the court to have creditors vote on the plan by May 1 and schedule a confirmation hearing on May 22.
But even if all goes as planned, Longview faces a difficult future.
The Independent Market Monitor’s 2019 State of the Market report said only 26% of PJM’s existing coal fleet was able to recover its avoidable costs from energy, capacity and ancillary services revenue in 2019, down from 68% the year before. New coal plants have not received enough net revenue to cover their costs in any zone in the RTO since 2009, two years before Longview began operation.
Conditions have worsened this year with day-ahead electricity prices at the PJM West hub averaging $19.83/MWh, a 47% drop from the $37.48/MWh average in 2018 and 2019, the company said.
Keffer had expressed confidence during Secretary Perry’s 2017 visit that natural gas prices would rise once more pipelines are built to take it from Pennsylvania and West Virginia. “The world is clamoring for our natural gas,” he said. “Once they start consuming that gas, your supply is going to start matching that demand. So the price is going to go back up.”
Natural gas is currently selling at about $1.40/MMBtu at the Dominion South hub, down from the $2.65/MMBtu average in 2018/19, Keffer said. “The price of natural gas is even lower in the immediate area where Longview operates due to the presence of shale gas,” he added.
His filing includes a 13-week pro forma projecting the plant will generate $20.3 million in revenue through July 10. Operating expenses of almost $25 million will leave it with a negative cash flow of $4.6 million for the period.
Expansion Plan
On the positive side, Longview said it will be able to add the combined cycle plant at $200 million less than the cost competitors would have to pay for a comparable new build in PJM, thanks in part to the Dunkard Creek water treatment facility, which can serve both Longview and the CCGT project.
Permitting for the CCGT project is expected to be completed during the first quarter of 2021.
Planned solar and combined cycle expansion at Longview Power plant | Longview Power
The solar project would involve 188,000 370-watt panels over 300 acres in Maidsville and Greene County, Pa. The solar project will include the laydown areas for the CCGT project — the areas used for receipt, storage and assembly — after the gas plant is completed, the company said.
The math for new gas and solar plants is more encouraging than that of coal. In 2019, a new CCGT would have received sufficient net revenue to cover levelized total costs in half of PJM’s 20 zones, the Monitor reported. Recovery was 98% in 2019 in the APS zone, where Longview is located.
New solar projects would have sufficient net revenue to cover levelized total costs in AECO, JCPL and PSEG, where renewable energy credit revenues are high, but not enough to cover costs in Dominion or DPL, the Monitor said.
NYISO on Tuesday floated a plan that would provide hybrid storage resources (HSRs) three options for participating in its energy and capacity markets.
Kanchan Upadhyay and Amanda Myott, NYISO energy and capacity market design specialists, respectively, presented an overview of the plan.
“The project seeks to explore participation options for co-located, front-of-the-meter generators and energy storage resources,” Upadhyay told the ISO’s Installed Capacity/Market Issues Working Group during a teleconference. “And we have seen that some of the incentives, along with improvements in flexibility and availability, are motivating developers to couple generation resources with storage resources, so we expect more and more of these kind of resources in future.”
NYISO wants to see HSRs participate under existing market models as much as possible. While that may necessitate minor modifications to existing market rules, it would allow for quicker implementation of changes. If existing market rules need to be modified, such changes will be developed for a potential vote at the Business Issues Committee by the end of 2020, Upadhyay said.
HSR participation options under consideration by NYISO | NYISO
The ISO is proposing that HSRs participate as distinct generators (Option 1); through an aggregation model to allow resource components within the HSR to share a point of interconnection (2); or as a self-managed energy storage resource (ESR) (3).
Installed capacity (ICAP) and unforced capacity (UCAP) for each resource component under Option 1 would be calculated based on the existing method applicable to that resource type, noting that UCAP is calculated using the availability-based method for ESRs and the performance-based method for intermittent resources.
The ISO would calculate ICAP and UCAP under Option 2 using the availability-based method, consistent with existing distributed energy resource rules, in which the upper operating limit of the entire HSR would be used to measure availability.
Under Option 3, ICAP and UCAP would also be calculated using the availability-based method, but using the upper operating limit of the ESR asset within the HSR to measure availability.
“There is no new option between deploying the ESR model and deploying the DER model,” said Michael DeSocio, NYISO director of market design. “Option 3 is an extension of the ESR participation model, which could be introduced before [new DER rules] because it’s really leveraging the ESR rules, procedures and modeling.”
“We think Option 2 is one that could be implemented along with or just after DER because it is leveraging the DER rules, procedures and modeling,” DeSocio said. “We are not prepared to change Option 2 today to allow these resources to provide operating reserves, mainly because the [Northeast Power Coordinating Council] rules that determine which resources can provide which reserves are pretty stringent.
“We would have to work with NPCC to see if changing these rules is even possible to do, and I also believe the rules in the Eastern Interconnect are very different from the rules in the Western Interconnect, which is mostly why you see large differences in reserve participation modeling between California and New York,” DeSocio said.
The ISO plans to continue discussing and developing market participation concepts for HSRs this quarter and present consumer impact analysis and a complete market design to stakeholders in the third quarter, Upadhyay said.
