Entergy last week reported a fourth-quarter loss of $66 million ($0.36/share), beating analysts’ expectations by 12 cents. That compared favorably with a $479 million loss for the fourth quarter in 2017 ($2.66/share).
Five analysts surveyed by Zacks Investment Research had projected a loss of 48 cents/share.
For the year, Entergy reported earnings of $849 million ($4.63/share), compared to $412 million ($2.28/share) in 2017.
In a Feb. 20 conference call with financial analysts, Entergy CEO Leo Denault said 2018 was “another successful year” and said the company is “on track” to achieve its long-term goals.
The company said its results reflected asset impairments and other expenses related to its decision to exit its Entergy Wholesale Commodities business and its four aging nuclear plants. The New Orleans-based company completed the sale of Vermont Yankee and announced agreements to sell Pilgrim and Palisades. (See Entergy Sees Quicker Exit from Pilgrim, Palisades Nukes.)
Denault said Entergy is making progress on Pilgrim’s sale to Holtec and is “actively working” toward a post shutdown sale of New York’s Indian Point plant. Pilgrim will be shut down no later than May 31.
“We executed on our strategy and met major milestones in our transition to a pure-play utility. We expect 2019 will be no different,” Denault said.
The company’s stock price gained $3.67 after opening at $89.10 on Feb. 20, closing the week at $92.77. Entergy’s stock price is up 7.8% this year through Feb. 22, slightly above the 7.3% gain by the S&P 500 Utilities index.
OGE Earnings Slip, but Beat Expectations
OGE’s quarterly performance nevertheless beat Zacks’ consensus estimate of 24 cents/share. The Oklahoma City-based company reported a fourth-quarter net income of $54.7 million, down from $295 million the year prior when it enjoyed a $198 million windfall, thanks to the 2017 Tax Cuts and Jobs Act.
OGE CEO Sean Trauschke told financial analysts during a Feb. 21 conference call that 2018 “may well be regarded as the best [operational] year in our company’s history.”
Trauschke pointed to strong safety numbers, the addition to its fleet of the 462-MW Mustang Energy Center and its seven gas-fired generators, the commissioning of a 10-MW solar farm, the addition of scrubbers at its two coal-fired Sooner Power Plant units, and the conversion to natural gas of two coal units at its Muskogee Power Plant.
Wall Street reacted favorably to OGE’s report. The company’s share price was up 2.2% following its open Feb. 21, gaining 94 cents to close the week at $42.78.
NEW ORLEANS — MISO is considering a fast-track process for “shovel-ready” generation projects in response to criticism that its rules don’t work for renewables, which now represent almost 90% of the RTO’s interconnection queue.
“It’s going to have to go through a lot of stakeholder discussion, but I’m optimistic we can come up with something to help out people that are really ready,” Vikram Godbole, MISO’s director of resource utilization, told the Gulf Coast Power Association’s MISO South Regional Conference last week.
Godbole made his remarks during a panel discussion on the RTO’s efforts to eliminate its interconnection backlog — a consequence, he said, of rising requests by solar and wind developers seeking to beat the phaseout of federal tax credits.
MISO has about 70 GW in its three-step definitive planning phase, up by more than 10 times the 5 GW in 2012. Wind projects account for 31.6 GW, with solar almost equal at 31 GW. Most of the remainder is gas (7.1 GW). Solar represents 83% of the 10.3 GW of interconnection requests in MISO South.
Godbole said the growth is been largely driven by the end of the wind production tax credit in 2020 and the reduction of the current 30% solar investment tax credit. In 2022, the solar credit will drop to 10% for commercial and utility projects and be eliminated for residences.
Wind and solar projects represent almost 90% of MISO’s interconnection queue. Solar projects are more than 80% of the nameplate capacity proposed in MISO South. | MISO
He said the RTO has been unable to accurately predict how much capacity developers will add to the queue. MISO’s high-end estimate for the 2018 cycle was about 25,000 MW. “And you know what happened? We got about [35,000 MW],” he said.
Betsy Beck, director of electricity markets and transmission policy for the American Wind Energy Association, told the conference that wind developers appreciate MISO’s efforts to address the queue problems.
But she said the RTO’s “incremental” changes may be insufficient to address problems caused by the transition to renewable generators from large fossil fuel plants that take years to permit and build.
“We can build a wind or solar farm in a matter of months not years,” she said. “The process that we’ve built for one generation type just isn’t working anymore for generation that’s fundamentally very different. … I just wonder, going into the future, at what point we need to stop and take a step back and say — instead of incremental changes — do we need to kind of start over?”
The length of the interconnection process — now averaging 505 days — is forcing wind developers to file their interconnection requests before they have complete plans and understand all their vulnerabilities, she said. When projects fall out of the queue, they can force restudies that often increase costs for projects behind them.
Beck said renewable growth is being driven not just by the phaseout of subsidies but also by corporate buyers inking power purchase agreements based on low costs. “The problem is not going away,” she said.
Godbole said that while the RTO has made progress in reducing the backlog in its North and Central regions, it is still seeking ways to reduce that in the West. “We are making progress. We are getting through these cycles as quickly as possible. And our hope is at some point we’ll catch up. If it’s this year, that would be awesome.”
AUSTIN, Texas — Parks Associates’ annual Smart Energy Summit attracted more than 100 industry representatives to the state capital, home to Silicon Hills and a vibrant technology environment.
Attendees participated in workshops and panel discussions on new roles for utilities as U.S. households adopt smart technologies, creating new layers of competition and complexity for home services, grid operations and energy management.
It’s not just about “customer engagement” but making everything easier for the customer, agreed a panel discussing new ways utilities can expand their footprint beyond traditional energy services.
“If you send someone a switch that requires a screwdriver … well, the vast portion of our population doesn’t use a screwdriver. They hire someone who uses a screwdriver,” said Joel Miller, a principle supervisor with DTE Energy. “Can the utility now become the homeowner’s handyman? We don’t know that yet.”
“We have to think like Netflix; we have to think like Amazon and make the customer experience easier and easier,” Tendril CEO Adrian Tuck said.
“Everybody is selling something smart … consumers have all these options,” said Todd Rath, marketing services director for Alabama Power. The consumer “doesn’t want 12 different apps. The opportunity for utilities is to combine all these things.”
Case in point: Alabama Power’s Smart Neighborhood initiative, in which the utility partners with Alabama homebuilders to build energy-efficient, smart neighborhoods. Its first neighborhood in the Birmingham suburbs integrated “high-performance homes, energy-efficient systems and appliances, connected devices and a microgrid on a community-wide scale.”
“It was not an energy efficiency or microgrid project, but a living lab to understand how those things work together,” Rath said.
To do so, the 62 homeowners had to all agree to a 24-month research project in which all the data would be collected. Rath said Alabama Power learned “some things are good, some things are bad.”
“We think the future is going to be [distributed generation] and connecting to that DG to maximize the grid and customer experience … seamless integration,” he said. “That all sounds good when you talk about it, but when you try to implement it, things come up that you’re not aware of.
“I don’t think we’re going to out-Amazon Amazon. We’re looking to advance electrification, to find a way to help customers understand the next generation of the grid,” Rath said.
“We believe the utilities are in a great position to do so much for the customers. They just need the tools to reframe the relationship,” Simple Energy’s Judd Moritz said. “If you do it right, you make the utility central to every decision the customer makes. You will become one of the largest retailers of smartphone-enabled technologies in America.
“We have that trusted adviser role,” Miller said. “We want to ensure we’re continuing to do that.”
Gen Z a Growing Consumer Group
Aaron Berndt, the head of Central Region Energy Partnerships for Google and its Nest company, said utilities should be learning how to connect with Generation Z, so-called “digital natives” who were born in 1997 or later.
“They live and breathe technology. They’re really focused on customization and personalization,” Berndt said during his keynote address, noting Gen Z members represent $44 billion in buying power and are just now entering the job market.
By 2020, he said, Gen Z will be the largest consumer group in the U.S.
“There’s room to grow in this area. Utilities lag other industries in digital experience,” Berndt said.
He said the next great change is in artificial intelligence, “which shows up to consumers through voice and voice assistance.” Google has “made available” 1 billion voice-enabled devices — cars, phones, watches, TVs — over the last 18 months, Brendt said.
“It’s simplifying and reshaping the way consumers engage with technology,” he said.
Energy-efficiency expert Ken Wacks suggested utilities embrace a new role as distribution service operators (DSOs).
“The distribution system has been static, but that is changing because distributed energy resources are proliferating at the edge of the grid,” Wacks said. “We think a [DSO] is an opportunity for utilities to make money from DERs by using the equipment that is already in place and letting the customer generate and sell energy via the distribution grid to the utility or to other customers.”
Wacks should know, having been appointed by the Department of Energy to four terms on the GridWise Architecture Council and contributing to its work to ensure reliable and efficient distribution of electricity while accommodating DERs.
“Utilities have to figure out how to let customers use the grid, how to price the grid and how to use equipment on the grid. Some of these equipment items today can’t handle the backflow or excess energy, so that requires active management of the distribution grid and possible equipment upgrades. Intelligence in homes and buildings will help customers manage DERs and power flows to the utility or to other customers via the distribution grid,” Wacks said.
The technologies to affect this change are emerging now, said Dane Christensen, National Renewable Energy Laboratory team lead for residential systems performance, ticking off thermostats, water heaters and batteries as examples.
“In five years, we’ll see the same transformation as we did from the flip phone to the smart phone. We’re trying to understand this potential of enabling other value streams,” he said. “When you look at a smart home, price is not the goal of a new product. The No. 1 goal isn’t to save money. It’s convenience and access to data.”
New York’s Consolidated Edison is on its way to becoming a DSO “the same way an RTO operates,” said Shira Horowitz, the utility’s demand response manager. She said the move is necessary to accommodate a high number of renewable DERs.
“We’re able to balance these renewables with demand response and batteries and other dispatchable distribution resources,” Horowitz said. “Demand response and some other dispatchable resources can prevent cascading failures. … Our demand response programs are used to manage the distribution system, as opposed to others using them for peak shaving or something else. We’re able to respond to distribution-level contingencies and events with distribution resources.”
Panels Discuss Value of Green Homes, Data
Several panels discussed energy-efficient, net-zero homes and their potential for storage, and what that means to grid operations.
“Don’t underestimate the power of the consumer,” warned Austin Energy’s Debbie Kimberly, the utility’s vice president of customer energy solutions and corporate communications. She said an average of 4,400 homes are built every year in Austin, “fully 30%” being Green Building homes that increase by $35,000 in value over non-green homes.
“That was really driven by consumer preferences,” Kimberly said. “It’s like, ‘I’d love to be able to remodel my home, if I could only get all those devices to talk to each other. I want an app to control my apps.’”
“There’s a true value proposition to having a home with a true energy experience,” Inspire CEO Patrick Maloney said. “You will find a set of consumers that highly value purchasing a home that feels like owning a Tesla, because no one [understands] kilowatts. If you want to have an impact on the greenhouse gas issue, zero-net homes are really a massive tool. We have to figure out how to create integrated service offerings. … I’ve never met a person who wanted to change their behavior willingly.”
Abhay Gupta, CEO of data consultant Bidgely, said AI may provide the key to the utilities’ challenge of optimizing their costs, adding revenue and “personalizing customer engagement.”
“Change will happen. It’s inevitable,” he said. “The question is, are we going to be ready for the future? Netflix and Amazon understood what they do, but do utilities? Something has to be done about massive aggregation. If you can unravel what’s happening in the home, you can get the same amount of information that Netflix gets.”
“For meter data to be valuable, we need it to become more granular,” said Matt Johnson, vice president of business development for EnergyHub. “One of the things that excites us about meter data is the potential — when marketing programs to customers — of being able to take advantage of that and get that data to impact the load-management side of the equation.”
Democrat Cheryl LaFleur joined with FERC’s two Republicans on Thursday to approve the Calcasieu Pass LNG export terminal, signaling a compromise on how to compute greenhouse gas emissions from it and other pending LNG projects (CP15-550).
Democrat Richard Glick, who has joined LaFleur to oppose some gas pipeline projects, dissented.
In a press release, FERC hailed the approval of Venture Global LNG’s terminal, related pipelines and a 720-MW generation facility in Cameron Parish, La., as a “breakthrough … agreement that may provide a path forward” for the commission’s review of 12 other proposed LNG export facilities.
Artist’s rendering of the Calcasieu Pass LNG export terminal, which will include two trains of natural gas liquefaction | Venture Global LNG
Chairman Neil Chatterjee, who joined with Commissioner Bernard McNamee in the 3-1 vote last week, said expediting the commission’s review process has been one of his priorities.
“I really appreciate the efforts of my colleagues to work together to come to an agreement on this facility. This is significant, as I anticipate we’ll be able to use the framework developed in this order to evaluate the other LNG certificates that the commission is considering.
“Commissioner McNamee showed just how he got his reputation as being a ‘lawyer’s lawyer’ through his attention to the law and work to find common ground,” Chatterjee continued. “And Commissioner LaFleur was supportive of this project and constructive in working to reach our agreement.”
By refusing to address pipelines’ impact on GHG emissions, Glick contends, the Republicans are ignoring a 2017 D.C. Circuit Court of Appeals order that remanded FERC’s approval of an environmental impact statement (EIS) for the Southeast Market Pipelines Project. (See Glick Shines Light on FERC Dispute over GHG.)
Until someone is appointed to replace late Commissioner Kevin McIntyre, LaFleur and Glick can block gas projects with 2-2 deadlocks. That has led Chatterjee to pull gas items from the consent agenda at open meetings.
Environmental Impact
Calcasieu Pass will be able to process up to 12 million metric tons of natural gas a year. Under its 1999 Certificate Policy Statement, the commission balances the public benefits of such projects against the potential harms.
FERC said its final EIS concluded the project “will result in some adverse environmental impacts, but impacts will be reduced to less-than-significant levels with the implementation of applicants’ proposed, and commission staff’s recommended, mitigation measures.”
The EIS found that operation of the terminal and its generating facility may result in emissions of up to 3.9 million metric tons per year of CO2 equivalent, potentially increasing U.S. emissions by 0.07%. “Currently, there are no national targets to use as benchmarks for comparison,” FERC said.
Block flow diagram of the Calcasieu Pass LNG export terminal | Venture Global LNG
‘Kafkaesque Approach’
In his dissent, Glick said the commission’s analysis did not meet the requirements of the National Environmental Policy Act or Natural Gas Act and “effectively writes climate change out of the public interest determination entirely.”
“The commission is finding that its choice not to evaluate the significance of the environmental harm caused by the project’s GHG emissions supports the conclusion that the project will not cause significant environmental harm. That Kafkaesque approach is not the ‘hard look’ that NEPA requires,” he said. “The commission’s rigid refusal to monetize the harms of climate change using the social cost of carbon while simultaneously monetizing the project’s long-term socioeconomic benefits — including direct, indirect and induced benefits from employment, investments and local taxes — is arbitrary and capricious.”
In a concurring statement, LaFleur said, “I appreciate the work done in the final EIS to address a range of resources impacted within the identified geographic scope of the Calcasieu Pass project. However, I disagree with the commission’s failure to disclose and discuss cumulative potential direct GHG emissions associated with Calcasieu Pass project, as well as the other projects identified in the final EIS within the 50-km air region.”
LaFleur said she also disagreed with the exclusion of the emissions from the cumulative impacts analysis.
“I believe it would take minimal effort to disclose the direct GHG emissions for the other projects identified in … the final EIS, and include an estimate of the total annual potential GHG emissions associated with the Calcasieu Pass project and those other projects as part of our environmental review.”
LaFleur’s statement included a table estimating that Calcasieu Pass and 10 other LNG or gas projects within 50 km would increase national GHG emissions by almost 0.8%.
“It is clear that the liquefaction of natural gas for export has meaningful GHG consequences,” she said. “I believe, at a minimum, direct GHG emissions must be disclosed and considered, both cumulatively and with respect to individual facilities.”
New Mexico’s Public Regulation Commission vacated an order earlier this month that had paved the way for Public Service Company of New Mexico (PNM) to join CAISO’s Western Energy Imbalance Market by the spring of 2021.
The move surprised many. The effort for PNM to join the EIM was largely uncontroversial and received unanimous support from the PRC’s five elected commissioners on Dec. 20. But the commission decided to revisit its decision after Albuquerque’s water agency protested the December ruling and after two new commissioners were sworn in this year.
PNM doesn’t need the commission’s approval to join the EIM because it does not involve the transfer of any of the company’s assets and market participation is strictly voluntary.
Proponents say New Mexico’s ample wind and solar power would be a valuable addition to the Western Energy Imbalance Market. | U.S. Department of Energy
The case (18-00261-UT) instead dealt with PNM’s request for an order governing the accounting treatment of costs related to joining the EIM. The commission’s December order authorized PNM to recover its expenses in a future rate case.
Now, however, PNM and some environmental groups worry the PRC’s latest move could delay PNM’s membership in the EIM for another year and cost ratepayers $10 million in projected annual benefits.
“Until a new order is issued, PNM will not undertake efforts to join the Energy Imbalance Market,” Western Resource Advocates argued in an emergency motion to the PRC. “Likewise, because it takes two years of preparation to join the EIM, there is a queue to join and a deadline of April 1 in each year, unless the commission issues an order quickly. … New Mexico will lose one year of substantial economic and environmental benefits.”
The Coalition for Clean Affordable Energy joined WRA in its motion, and the Natural Resources Defense Council said in a news release that the commission’s action was a “step backwards” in state efforts to use more renewable energy.
PNM said in it was disappointed by the commission’s move.
“PNM’s decision to join the EIM was dependent on the commission’s December 2018 approval,” Thomas Fallgren, vice president of generation, said in a statement emailed to RTO Insider. “PNM has suspended all work on the Energy Imbalance Market due to today’s actions. Any further delays or changes of the December order may jeopardize our ability to reap the customer benefits.”
In a brief order Feb. 6 vacating its December ruling, the PRC did not explain the reasons for its action. It merely said it had the legal authority to rehear the case at the request of the Albuquerque Bernalillo County Water Utility Authority.
The water utility had argued that the cost-recovery decision was made too hastily by a commission that included members near the end of their terms.
“The procedural record in this case establishes that the commission only had hours to review the hearing transcript, evidence introduced into the record during the hearing, briefs filed by the [water authority], PNM and staff, and the proposed order on accounting treatment,” the water utility’s lawyers wrote in their brief.
“Given the time for this review and the voluminous record to review, a thorough review by commissioners of this material was impossible as a practical matter,” it said. “Such a rush to judgment by departing commissioners is problematic and should not bind the present commission to an ill-advised course of action.”
The water utility contended PNM should be required to file quarterly reports on its EIM benefits and shouldn’t be guaranteed a return on investment, with ratepayers bearing the risk.
“It is axiomatic that the commission is the surrogate for the marketplace, and if PNM were operating in the marketplace, rather than as a regulated monopoly, it would not be guaranteed recovery of its investments,” the water utility’s lawyers wrote in a Jan. 17 application to reopen the case.
Further action by the PRC is pending. It remained unclear if the commission will hold another hearing or, as Western Resource Advocates urged, decide the case on the record before it to expedite a decision.
CAISO, which did not comment on the PRC’s action, says the EIM has generated $565 million in benefits for its members since its founding in November 2014.
The EIM’s membership consists of CAISO, PacifiCorp, Arizona Public Service, Idaho Power, NV Energy, Portland General Electric, Puget Sound Energy and Powerex. The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District and four other entities, including PNM, are scheduled to join between 2019 and 2021.
FERC on Thursday again denied Vermont Transco permission to embed transmission acquisition costs in its rate recovery through the ISO-NE Tariff.
In rejecting a rehearing request on the issue, the commission affirmed its decision last year rejecting the company’s attempt to recover $639,780 from Vermont ratepayers to cover property transfer taxes, closing fees and advisory fees related to its acquisition of shares in the Highgate Transmission Facility near Quebec (ER18-1259-001).
Vermont Transco first filed the request for recovery in March 2018, and FERC rejected it in May.
| Vermont Transco
In a 2017 filing seeking FERC approval to acquire Green Mountain Power’s stake in Highgate — which was eventually granted — Vermont Transco acknowledged that “there is no mechanism in [ISO-NE’s] cost-based transmission formula rate that allows the automatic pass-through” of transaction-related costs. The company promised to make a separate filing if it intended to seek any transaction-related costs that would also demonstrate “specific, measurable and substantial benefits to ratepayers.”
But the company’s 2018 cost-recovery request contended that the requirement to show ratepayer benefits didn’t apply because the company was not seeking to recover an acquisition premium. The company also contended it could recover the expenses from customers because service over Highgate is provided under ISO-NE’s Regional Network Service rate, which relies on cost causation and beneficiary pays principles. It also noted that it never made a hold-harmless commitment on such recovery.
In denying the request, FERC pointed to Vermont Transco’s previous commitment — set out in the transfer application — to demonstrate ratepayer benefits. The commission also said the company couldn’t simply bypass ISO-NE’s restriction on an automatic pass-through of the transaction-related costs and reminded it of its earlier promise that the transaction would not have an adverse effect on rates.
The commission added that Vermont Transco was free to file again for cost recovery provided it detailed how the recovery would benefit ratepayers.
FERC said last week that PJM’s proposal for reimbursing generators for fuel-switching costs and for penalties incurred when gas pipelines fail lacked specificity and clarity.
In a ruling issued Feb. 19, FERC rejected the stakeholder-approved mechanism submitted for inclusion in PJM’s Operating Agreement and Tariff that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with fuel-switching instructions from the RTO (ER19-664.)
FERC rejected PJM’s proposal for compensating generators for costs associated with fuel-switching orders. | Entergy
PJM’s filing would have become effective Dec. 21 and allowed generators to request cost recovery from FERC across nine different categories: park-and-loan service charges; overrun charges; exceeding maximum daily quantity; exceeding minimum/maximum storage balance; imbalance cash-out charges; disposal of gas and related products costs; other gas balancing costs; start-up costs; and alternate fuel costs.
FERC described PJM’s definition of “penalty” — costs that are designated as such in the pipeline or local distribution gas company tariff and imposed by the applicable pipeline or company — as “unreasonably narrow and unsupported.” The commission said pipeline tariffs delineate between penalties and the RTO’s proposed categories in different ways, meaning what appears to be relevant fuel-switching costs for one pipeline could be considered a penalty for another. The commission also faulted PJM for not including events that might trigger fuel-switching directives in its Tariff and for lacking established procedures for dealing with such contingencies through existing market design.
“Continuous communication and coordination between the RTO, the gas pipeline operator and the relevant generation owners can be critical to ensure the reliable operation of both systems,” FERC concluded in its ruling. “Given this lack of clarity, PJM’s proposal does not reasonably ensure that coordination occurs prior to a generator’s switching to an alternate pipeline.”
The D.C. Office of the People’s Counsel crafted the rules and compensation plan detailed in the filing after earning a majority of stakeholder support at the December meeting of the Markets and Reliability Committee. (See “Gas Pipeline Contingencies,” PJM MRC/MC Briefs: Dec. 6, 2018.)
The supermajority vote signaled a major victory for load interests who were opposed to the Calpine-authored plan endorsed at the Market Implementation Committee in November. That proposal would have developed a formula for cost recovery to be filed with FERC that did not include pipeline penalties. (See “Gas Pipeline Contingencies,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)
Jeff Shields, a PJM spokesperson, said Friday that staff are still considering next steps.
“We continue to believe that this is an important issue to resolve and is another step in improving gas-electric coordination,” he said. “We are evaluating the order and our options for working with stakeholders to rectify the issues FERC found with our filing.”
MISO’s Steering Committee is looking for ideas on how leaders of stakeholder groups can best oversee spirited discussions while sticking to schedules listed on meeting agendas.
Speaking during a Feb. 20 conference call, Chair Tia Elliott said the committee is seeking near-term solutions for managing conversations during heavily attended public meetings.
More participants are asking more questions following stakeholder meeting presentations, the RTO has found. Among the subjects sparking the interest: proposed new rules to address a growing gap in resource availability and need; a new load forecasting method; studies to determine when renewable integration will become unmanageable; and plans to incorporate storage separately into energy markets and the transmission planning process.
The committee has discussed using the “raised hand” function on the online meeting platform WebEx, as well as having participants send emails directly to the Client Relations Department during the discussions.
Reliability Subcommittee Chair Bill SeDoris said at a recent heavily attended RSC meeting, leaders gave in-person attendees priority to make comments and ask questions while compiling emails of questions to take from phone participants.
“Emails did work, but it was a little clunky,” SeDoris said, noting that the RSC had two stakeholder specialists on hand to handle the high-traffic discussion.
But MISO Stakeholder Relations Specialist Alison Lane said it’s unlikely the RTO can provide two specialists for every meeting.
Lane suggested stakeholders develop a “comment queue” following a presentation, where committee chairs ask those in the room to raise their hands and those over the phone to signal, allowing a specialist to compile an ordered list of stakeholders to call on.
She also said chairs might have to limit stakeholders to “one really good question” apiece instead of allowing a single stakeholder to ask multiple questions. She added that MISO and chairs must anticipate which topics on the agenda will elicit a lengthy discussion and plan accordingly.
Resource Adequacy Subcommittee Chair Chris Plante said stakeholders attending by phone are sometimes forced to interrupt conversations to ask long-awaited questions.
Elliott said the Steering Committee will consider the comment queue suggestion and noted that any process changes wouldn’t likely be memorialized as a rule in the RTO’s Stakeholder Governance Guide.
MISO will also host a March 18 stakeholder training on managing meetings as part of Board of Directors Week in New Orleans. Lane said the session will focus on governance rules and tips on how to successfully facilitate a meeting.
MISO Rebrands Market Roadmap
MISO also told the Steering Committee on Wednesday that it will rebrand its Market Roadmap list of future market improvements as the “Integrated Roadmap,” which will include more research and reporting on industry trends to provide support for the RTO’s reasoning behind and prioritization of proposed changes.
The roadmap will now include research focus areas and an emphasis on changes to accommodate what MISO dubs the “3Ds”: demarginalization, decentralization and digitization of the electric grid. It will also include the annual publication of an insights and strategy report to explain how major trends might affect RTO operations. The first such report will be published in early March, and MISO has also tentatively planned an April 9 stakeholder workshop to discuss the report.
MISO Director of Stakeholder Affairs Joan Soller told the Steering Committee that the new design is meant to be “more inclusive” of topics that span multiple committees.
The fallout from GreenHat Energy’s record default in PJM’s financial transmission rights market prompted MISO officials on Wednesday to reassure members that such failures are unlikely to happen there.
“MISO doesn’t believe there’s as much of a risk in our market versus PJM’s,” Director of Finance and Accounting Ross Baker said during a Feb. 20 Advisory Committee conference call.
However, Baker acknowledged that MISO’s ongoing investigation of its own practices could identify some improvements to its FTR credit calculation later this year.
In September, MISO officials said they were giving increased scrutiny to an already in-progress review of the RTO’s own FTR market. At the time, the executives said MISO’s FTR market was less susceptible to a default than PJM’s because MISO relies on a more conservative credit calculation and requires higher collateral, preventing “thinly capitalized” parties from buying large portfolios. The grid operator also said it limits FTR terms to one year, while PJM allows rights for up to four years. The RTO pointed out it estimates the value of transmission congestion more frequently than PJM, updating congestion estimates monthly rather than annually. (See “MISO Reviewing FTR Process” in MISO Board of Directors Briefs: Sept. 20, 2018.)
Baker reiterated MISO’s stance to the Advisory Committee on Wednesday. He said the RTO’s practice of not netting net auction bid prices with estimated congestion credit value for collateral requirements is a “key component for minimizing the magnitude of a default.”
“We haven’t identified any significant issues … We expect we’ll be able to provide an update sometime in May,” Baker said of the ongoing review. “We don’t believe our calculations are perfect; we believe there will be some potential improvements.”
As of December, PJM’s total FTR default was estimated at about $187 million; however, if FERC’s rejection of PJM’s requested waiver of liquidation methods is upheld, the default could climb to more than $430 million, according to PJM. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)
“We don’t have any means of verifying [PJM’s estimate],” Baker told the Advisory Committee.
Responding to a stakeholder question, Baker said he couldn’t be sure whether MISO’s exposure to default is non-existent or greatly reduced compared with PJM. “There certainly is a potential for loss, but we believe it’s much less of an exposure in our market,” Baker said.
Baker said MISO may convene a stakeholder task team to examine possible improvements to the calculation.
MISO will continue its evaluation of FTR practices as planned, concluding sometime this year. Baker said the RTO will discuss any FTR collateral requirement changes with stakeholders in regularly scheduled Market Subcommittee meetings.
FERC on Tuesday approved a MISO proposal requiring owners of load-modifying resources to provide firmer and more clearly documented commitments regarding their availability before participating in the RTO’s capacity market.
The proposal represents the first piece of MISO’s three-part near-term resource availability and need initiative.
” … Recent maximum generation emergency events have frequently occurred outside the summer season as generator forced outages and high load conditions converge with planned generator outages that are typically scheduled in the spring and fall seasons. MISO contends that these spring and fall maximum generation emergency events do not align well with the obligations of LMRs, which currently are not required to serve MISO load in non-summer seasons,” the RTO said in making the case for the new rules.
MISO control room | MISO
The new rules require a load-modifying resource (LMR) to offer capacity in accordance with a seasonal availability report provided to MISO and commit to deploying based on the shortest notification time it “can consistently meet” but no longer than 12 hours (ER19-650). LMR owners must provide that information to MISO during registration.
In return, MISO will issue scheduling instructions before an emergency occurs based on an LMR’s unique notification times. The RTO has also promised to confirm or withdraw advanced scheduling instructions at least two hours prior to an expected emergency event. LMRs that acknowledge scheduling instructions will receive credit for one of the five times per year that LMRs are required to respond, regardless of whether the emergency declaration is made.
MISO said the rules will improve transparency around LMR capability and give it easier access to LMRs during emergency situations.
In approving the filing, FERC also granted a waiver of MISO’s usual deadlines for LMRs to register their availability for the April capacity auction. LMRs now have until March 1 to complete registration. (See “LMR Registration Confusion” in MISO Preliminary PRA Dataup Slightly from Early Prediction.)
A group of MISO industrial customers protested the filing, saying the RTO was vague and failed to outline how the “best physical capability” and “shortest notice requirements” of LMRs would be measured and verified. Those customers also said the new availability requirements could create an “incentive for LMRs to exit the market,” which could drive up capacity auction clearing prices.
But FERC said cut-and-dried availability rules wouldn’t work best for LMRs, which differ in operating characteristics and limitations: “Although a specific definition would provide certainty to some LMRs, it would likely be incompatible with the capabilities and circumstances of other LMRs. Therefore, we find reasonable MISO’s proposal to give flexibility to each LMR in determining its own capabilities and the type of supporting documentation it can provide for the purpose of demonstrating its capabilities.” The commission also dismissed as “speculative” the claim that the RTO’s proposal will force LMRs to exit the market.
MISO has two other near-term filings awaiting FERC action as part of the short-term resource availability and need project: one to subject demand response to annual capability testing and the other to impose new generator accreditation penalties for planned outages taken fewer than 120 days in advance and during what MISO deems “low-margin, high-risk periods.” The trio of filings is aimed at immediate relief in time for spring and to buy time for in-depth solutions. The Market Subcommittee and Resource Adequacy Subcommittee will work on the more involved solutions — yet unnamed — through 2020. (See Stakeholders Seek Slowdown on MISO RAN Project.)
Entergy last week reported a fourth-quarter loss of $66 million ($0.36/share), beating analysts’ expectations by 12 cents. That compared favorably with a $479 million loss for the fourth quarter in 2017 ($2.66/share).
OGE’s quarterly performance nevertheless beat Zacks’ consensus estimate of 24 cents/share. The Oklahoma City-based company reported a fourth-quarter net income of $54.7 million, down from $295 million the year prior when it enjoyed a $198 million windfall, thanks to the 2017 Tax Cuts and Jobs Act.
