Ohio regulators Wednesday rejected FirstEnergy’s request for an annual $558 million rider for eight years, voting instead to give the company $204 million annually for only three years.
FirstEnergy, whose request would have totaled $4.46 billion, will receive $612 million (nominal dollars) under the unanimous decision by the Public Utilities Commission of Ohio.
FirstEnergy has 1,360 employees at its Akron, Ohio, headquarters. The company says its total economic impact in the state is $568 million annually.
The company said the eight-year retail rate stability (RRS) rider was necessary to ensure the corporation’s financial health at a time in which its coal- and nuclear-fueled generation is challenged by low natural gas wholesale energy prices.
The staff’s proposal “will provide FirstEnergy with an infusion of capital so that it will be financially healthy enough to make future investments in grid modernization,” the commission said in a statement. The commission’s unanimous order limited the rider to three years, with the possibility of a two-year extension.
Chairman Asim Z. Haque said the rider is not meant to solve all of FirstEnergy’s financial problems.
“If FirstEnergy truly needs $4.5 billion to achieve full financial health, then the commission decision today falls well short of that expressed need,” he wrote in his concurring opinion. “The commission does not intend to be, nor will it be, nor should it be the entire solution for FirstEnergy’s current financial difficulty. … The commission is an economic regulator. It is not a bank. It is not a trust fund. We authorize rates and charges that come directly from the pockets of consumers and businesses in this state. We have no rainy day fund to dip into.
“I do, however, want our regulated utilities to be healthy so that they can invest in bettering the delivery of services to consumers and businesses in the state of Ohio,” he went on. The rider “is meant to assist FirstEnergy in deploying the grid of the future while simultaneously providing it with a boost to improve its credit rating and financial health.”
FirstEnergy Unhappy
FirstEnergy will collect $132.5 million a year, with the balance of the $204 million going to taxes, said company spokesman Doug Colafella. Haque concurred with that figure “assuming current tax rate.”
The charge will boost monthly bills $3 (about 3%) for a typical residential customer using 750 kWh, the company said.
The company was not pleased with the decision.
“Today’s decision is disappointing for our customers,” said CEO Charles E. Jones. “While we clearly demonstrated to the PUCO what is essential to ensure reliability for customers in the future, the amount granted is insufficient to cover the necessary and costly investments. The decision also fails to recognize the significant challenges that threaten Ohio utilities’ ability to effectively operate.”
FirstEnergy said it is evaluating the order and considering its next steps. It has 30 days to appeal.
The modified RRS was FirstEnergy’s latest attempt for a state bailout. Its first attempt, submitted as a power purchase agreement, was approved by PUCO but collapsed after FERC said it — and a similar deal involving American Electric Power — would be subject to stringent reviews. (See FERC Rescinds AEP, FirstEnergy Affiliate-Sales Waivers.)
FirstEnergy and AEP went back to the drawing board. While FirstEnergy went with the modified rider request, AEP has chosen to go a different route: It is currently working with Ohio legislators to reverse customer choice and reregulate the industry.
Opponents also Miffed
Environmental groups and consumer advocates argued that the FirstEnergy request was unreasonable.
“Today’s decision takes hundreds of millions of dollars out of customers’ pockets in order to create a massive slush fund for FirstEnergy Corp. and its shareholders,” said Shannon Fisk, attorney at the nonprofit environmental law firm Earthjustice.
“The fact that FirstEnergy asked for billions more does not make this decision any less unreasonable. Rather than forcing customers to prop up profits for a corporation that made a bad bet on aging coal plants, the commission should be looking after customers and ensuring investments in job-creating renewable energy, energy efficiency and smart grid initiatives.”
The Sierra Club said PUCO could have used the ruling to encourage FirstEnergy to make further efforts to move toward more renewable energy.
“In this long-awaited and complicated decision, PUCO missed a critical opportunity to seriously focus FirstEnergy on the more diversified, cleaner energy future that tens of thousands of customers wrote the commission asking for,” said Dan Sawmiller, senior representative for the Sierra Club’s Beyond Coal campaign in Ohio.
“A few months ago, FirstEnergy took an important step in moving beyond coal when it announced closure of four units at its Sammis coal plant. With PUCO’s decision now issued, we hope to be able to work with FirstEnergy to accelerate its path beyond coal and nuclear and toward new investments in clean energy, energy efficiency and other modern grid initiatives like infrastructure for electric vehicles.”
IPPs Weigh in
The Alliance for Energy Choice, an organization funded by independent power producers, said FirstEnergy is still getting a good deal at ratepayers’ expense.
“The PUCO once again granted the utility’s request for more money with no corresponding benefit to customers,” Alliance spokesman and former PUCO Chair Todd Snitchler said. “Businesses and families will again be required to pay more for the same service they already receive with only a hope that customers will gain an upgraded grid if and when the utility elects to do so.”
“FirstEnergy should simultaneously be required to file a distribution rate case to document the need for, and amount of, a true grid modernization program,” Snitchler said.
Consumer advocate Public Citizen on Tuesday protested Energy’s proposed sale of the James A. FitzPatrick nuclear plant to Exelon, saying the companies’ FERC application failed to include information about the state subsidy that makes the transaction possible (EC16-169).
Public Citizen says omission of the subsidy makes the application incomplete. It also said the subsidy itself distorts the New York market and violates the NYISO Tariff.
“Exelon’s application to acquire FitzPatrick must be considered incomplete because, inexplicably, it fails to incorporate any mention or analysis of New York’s proposed ZEC payment subsidy scheduled only for FitzPatrick and for both of Exelon’s two in-state nuclear facilities. This payment subsidy, estimated at a total of $8 billion in six two-year increments, will significantly distort the NYISO energy and capacity markets and fundamentally alter the economics of Exelon’s power generation operations in NYISO, including FitzPatrick,” Public Citizen wrote.
“We believe the structure of the ZEC may conflict with elements of the NYISO … Tariff, particularly FERC’s mandate for incentives through the NYISO installed capacity market,” the protest continued.
“While the … proponents claim the ZEC is designed to combat climate change, a realistic analysis shows that the primary purpose of the ZEC is to keep select economically uncompetitive nuclear power plants operating, regardless of the impact on greenhouse gas emissions. And the state’s decision to discriminate between different nuclear generating stations for reasons other than climate change or the environment further complicates the true purpose of this expensive ZEC subsidy,” Public Citizen says.
Entergy’s downstate Indian Point facility, which is not financially stressed, is not currently eligible to participate in the ZEC program.
Opponents of the subsidy say it will cost ratepayers up to $8 billion over its 12-year life. Supporters say the state will enjoy a net economic benefit when it is calculated using the federal social cost of carbon analysis.
Public Citizen wants FERC to declare the application incomplete, require a market analysis that incorporates the full impact of ZECs and determine if the subsidies conform with FERC rules.
Public Citizen was the only party to file responses to the application before the comment deadline expired Oct. 10, except for U.S. Rep. John Katko (R-N.Y.), who sent a letter to FERC urging action on the deal. Katko, whose district includes FitzPatrick, said the plant provides more than 600 jobs and is “a vital part of the region’s economy.”
SPP’s Exit Study Task Force, formed to provide technical support and advice regarding Lubbock Power & Light’s move to ERCOT, conducted its first meeting last week.
The Public Utility Commission of Texas asked SPP and ERCOT to work together to study the implications of LP&L’s plans to migrate 430 MW of its load from SPP to ERCOT in June 2019. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
One issue is who will pay for the studies. PUC Chair Donna Nelson has said the burden shouldn’t fall on ERCOT ratepayers, suggesting during a Sept. 22 meeting LP&L should either fund the work or that the issue should be open “pending the outcome of the studies.”
“‘Depending on the outcome’ … I don’t know what that means,” said LP&L legal counsel Chris Brewster during the task force’s first meeting Friday.
Oklahoma Gas & Electric’s Jake Langthorn, the group’s chair, told the group the study costs will become clear once the scope and schedule are developed. SPP staff will begin its assessment by using its normal base cases from its near-term and 10-year studies.
“We’ll evaluate the system with Lubbock in SPP and without. In each case, we’ll evaluate the system against SPP planning criteria and NERC criteria to see whether we’re outside the acceptable ranges,” said Antoine Lucas, SPP’s director of transmission planning. He said the study will seek to identify any new transmission projects needed — or planned projects that can be deferred — as a result of Lubbock’s move.
LP&L representatives pushed SPP, which has targeted an April completion date, to accelerate its timeline.
ERCOT has said it will complete its assessment by the end of the year.
SPP says its existing planning workload will keep it from completing its work by the end of the year as ERCOT has promised.
“Having said that, we’re expecting it’s more than 90% in place right now,” said Lanny Nickell, SPP’s engineering vice president. “Once we put the schedule together, we can identify when we need it 100% finalized.”
SPP staff said it is meeting with ERCOT staff next week to review all questions posed by LP&L.
The task force is composed of four members of the Strategic Planning Committee and two each from the Transmission and Economic Studies working groups.
Wind, Coal Generation Continue to Rise, Fall
| SPP Market Monitoring Unit
Wind energy continues to rise in the SPP footprint and coal-fired generation continues to drop, according to the Market Monitoring Unit’s State of the Market report for this past summer.
The MMU said wind generation accounted for more than 12% of all energy produced in 2016, compared with 10% in 2015 and 9% in 2014. At the same time, coal generation’s share dropped to 51%, down from 62% in 2014.
Natural gas prices rose from this spring’s record low levels, the MMU said. The average price at the Panhandle Hub was $2.51/MMBtu this summer, compared with $2.60/MMBtu in 2015 and $4.00/MMBtu in 2014.
| SPP Market Monitoring Unit
The “wind alley” of the Texas panhandle, western Oklahoma and western Kansas continues to experience most of the SPP footprint’s congestion. However, the MMU said, congestion has increased in southeast Kansas and parts of Arkansas, which it attributed to higher summer loads and planned generation and transmission outages.
Staff will review the submittals and share them at their next Interregional Planning Stakeholder Advisory Committee meeting.
SPP staff said a joint model is being developed, but it will likely have differences with each RTO’s regional models, and that some of the identified regional needs may not show up in the model.
Separately, SPP and Associated Electric Cooperative Inc. have developed models and assessed the needs for the target areas, posting them to allow stakeholders to submit solutions. The two organizations requested input be submitted by Nov. 7.
SPP Interregional Coordinator Adam Bell told the committee the Northeast Oklahoma target area will no longer be evaluated in the SPP-AECI joint study because of a change of power suppliers in the region. He said the change “resulted in there no longer being potential needs observed on both sides of the SPP-AECI seam.”
VALLEY FORGE, Pa. — After months of debate on proposed definitions for operating parameters, PJM and the Independent Market Monitor rankled some Market Implementation Committee members last week by introducing an unexpected, last-minute compromise package that included one key change but largely maintained the status quo.
The proposal leaves many of the definitions untouched, except for minimum runtime and soak time. The endorsed definition of minimum runtime replaces a unit’s “breaker closure” with simply when a unit is “dispatchable” as the starting point. It also “un-nests” soak time from minimum runtime, differentiating it as its own parameter.
“We think it’s a big step forward,” Monitor Joe Bowring said.
Several stakeholders said they wouldn’t have enough time to give the proposal a reasonable review that day, but a seconded motion to vote on the issue forced them to act. The vote, which was planned for the morning session, was delayed until the afternoon to provide extra time.
| PJM
It was enough: The joint package received support from 75% of stakeholders — far exceeding competing proposals. It also won more than 60% support in a head-to-head vote against the status quo, meaning it will be forwarded to the Markets and Reliability Committee. (See “Members Hear First Read on Plan to ‘Un-Nest’ Operating Parameters,” PJM Market Implementation Committee Briefs.)
The last-minute proposal by PJM and the Monitor caused several stakeholders to question the functionality of the stakeholder process. “Do we just not care about the stakeholder process anymore?” Ed Tatum of American Municipal Power asked during the initial discussion. “What’s the idea of bringing something that no one’s been able to look at?”
After the vote, PJM’s Dave Anders thanked the members “for working through the issue.” He acknowledged their frustration, but he said this was an example of “the stakeholder process actually working.”
He invited members who have thoughts on reforming the process to attend the Stakeholder Process Forum Oct. 24.
Stakeholders Debate ARR Changes
In response to a problem statement approved earlier this year, PJM has begun revisiting its procedures for allocating residual auction revenue rights and hopes to file a solution with FERC on Dec. 31.
Exelon and Direct Energy issued a proposal last week for reducing potential revenue fluctuations under the current allocation. Their proposal would eliminate any residual ARR paths that could receive negative values based on monthly financial transmission rights clearing prices. PJM would then rerun the simultaneous feasibility test before allocating residual ARR megawatts for the month.
PJM’s proposal would give stakeholders the opportunity to opt out of allocations on a path-by-path basis. Sharon Midgley of Exelon said both proposals solve the issue but differ on the approach taken to address the current forced allocation of negative paths to customers. The Exelon/Direct Energy package puts an additional administrative requirement on PJM, while the RTO’s proposal places new analytical requirements on load-serving entities.
PJM’s Asanga Perera explained that the stakeholder proposal puts a heavy burden on PJM staff to process the data for negative pathways within a few days to have the results back to stakeholders in time for the next round of ARRs. He said it creates the potential for PJM to miss a deadline and leave stakeholders without the information necessary to identify negative pathways.
He pointed out that the process for stakeholders under PJM’s plan uses what they already do for the annual ARR process.
However, several stakeholders criticized PJM’s plan, saying their companies don’t have the staff to analyze the thousands of potential pathways each month. “I think PJM’s proposal with the burden placed on the stakeholders, that would be too overwhelming,” said a stakeholder who asked not to be identified. “It would give an advantage to the stakeholders that have the staff and the resources available to do that.”
PJM Looks to Revise Shortage Pricing Procedures
PJM’s Adam Keech presented a shortage pricing proposal to avoid potential volatility posed by implementation of FERC Order 825 (RM15-24).
Under the order’s transient shortage pricing rules, even brief shortages will trigger the maximum penalty factor, which could cause volatility as market participants attempt to respond. (See FERC Issues 1st RTO Price Formation Reforms.)
PJM’s proposal would create steps below the maximum penalty factor based on historical performance so that the maximum penalty does not apply until the reserve is down to the largest single resource’s actual output as opposed to its economic maximum. The measurement would change every five minutes.
Keech noted that in the past 21 months, PJM has observed 845 instances where, under the rules in Order 825, reserve prices would have hit the maximum $850/MWh penalty factor in the Mid-Atlantic and Dominion regions. He hadn’t analyzed the data enough to explain why 759 of them were in 2015 compared with 86 in 2016.
Stakeholders endorsed by acclamation changes to PJM’s credit policy. The revisions to Attachment Q of the Tariff reorganize provisions and make five minor changes to them, none of which affect credit requirements, according to PJM’s Harold Loomis.
The changes also specify that collateral may not be encumbered or restricted and provide PJM “reasonable time” to investigate breaches of credit requirements before implementing remedies, ensuring the RTO’s action is not foreclosed if it does not act immediately.
The revised attachment also replaces a section on peak market activity (PMA) collateral requirements with one specifying PMA credit requirements.
‘Working Groups’ Removed from MIC Charter
Stakeholders endorsed edits to the MIC charter that removed references to “working groups,” as they no longer exist. Working groups were eliminated as part of a larger reorganization of the stakeholder process starting in 2009 that standardized the purposes for and creation of task forces and subcommittees.
Stakeholders Develop Interest List for Black Start Requirements
PJM is soliciting stakeholder feedback on the priorities that should be considered in developing annual revenue requirements for new black start units. The current interest identification includes 13 concerns, including that the Monitor calculate revenue within six months of units entering black start service.
Bowring said the calculations can’t be made without explicit documentation to support “every penny of requested revenue changes” and that documentation must be submitted in a timely fashion. Members asked Bowring to specify what documentation is required.
Massachusetts regulators have rejected fees National Grid sought to impose on small commercial and industrial customers that own distributed energy resources (15-155).
In an order approved Sept. 30 that granted the utility a $101 million rate increase, the Department of Public Utilities rejected proposed monthly charges for new stand-alone DER, including solar and wind. The customers who are most likely to be affected by the proposal include local governments and community-aggregated solar projects, which are intended to benefit low-income ratepayers and those otherwise unable to install solar panels on their own homes.
Solar Cell Panels on Gillette Stadium Roof | Wikipedia
National Grid had sought to impose the fees to help cover the fixed costs of the distribution grid and avoid shifting them to other ratepayers.
Regulators agreed with opponents who said the company failed to justify the charge or demonstrate cost-shifting. “With the exception of interval meters, the company has not quantified the costs that it contends stand-alone DG facilities impose on its distribution system,” the DPU wrote.
It did approve a $1 increase from the $4 minimum monthly charge for residential customers and a one-time interconnection charge of $28 for distributed resources to cover the application process.
National Grid had proposed a fixed fee of up to $20 for residential customers based on usage and $30 for small commercial customers.
A law passed in the spring by the Massachusetts legislature opened the door for the company to collect a “monthly minimum reliability contribution” (MMRC) for customers who receive net metering credits. (See Massachusetts Raises Net Metering Cap, Cuts Payments.)
The law also allows for the consideration of an access fee once solar capacity reaches 1,600 MW statewide, a threshold expected next year. National Grid has met its share of that total.
The DPU agreed with opponents of the proposal that the fees did not qualify as MMRCs because the rate case was filed before the law’s enactment. It also said that once the 1,600-MW threshold is passed, a fee could be considered in a separate proceeding.
The company had proposed a monthly access fee of $7/kW, reduced by an assigned capacity factor (40% for solar and 30% for wind). National Grid said the fee was necessary to recover its costs for the operation and maintenance of the transmission and distribution grids and the increase in costs it says will result from further penetration of distributed resources.
Several intervenors contended that the proposal ran contrary to Massachusetts’ efforts to have its rate design more accurately reflect market conditions.
“Reforms to electricity rate design must strike a careful balance between economic efficiency, equity for all customers, protection of low-income ratepayers and access to community distributed generation,” Mark LeBel, staff attorney at Acadia Center, said in a statement.
AUSTIN, Texas — Industry insiders last week gathered here for the Gulf Coast Power Association’s 31st Annual Fall Conference, which featured presentations on ERCOT pricing and the effect of market forces, as well as discussions on distributed generation, Mexico’s reformed energy market, wholesale market design and efficiency improvements, new developments on ERCOT’s seams, current cyber threats and cross-border transmission issues with Mexico.
Taking a look at current market conditions, the opening panel discussed what the future will hold. Sam Newell, a principal with The Brattle Group, said should solar costs continue to drop, it could replicate what ERCOT saw in the early years of the 21st century.
“At the beginning of the market, we built out [gas-fired combined cycle plants] in spades, and that’s why prices were so low,” he said. “I think that could happen with solar. [If I] were thinking about investing in traditional power gen in this market, I’d be worried because of that prospect. If we get 25-MWh, all-in solar, that will just kill prices for everybody else.”
“I think [pricing] is as big an issue for the coal,” said Bob Helton, director of market design and policy for ENGIE. “If you look at capacity factors, a baseload coal plant runs at 88, 89%. They’re running today down in the 30s. I think you will potentially see some changes in operations. It’s like my car is not running, but I’m not about to put new tires on it. You’re going to see some of those issues in maintenance that are going to change for coal plants with large capital expenditures.”
“Many generators [in ERCOT] have another revenue stream from their integrated retail side,” pointed out Charles Griffey, president of Peregrine Consultants. “Retail margins are very, very high right now in certain sectors of the market.”
“It’s in the best interest of the ERCOT market for us to be constantly moving forward, whether it’s real-time co-optimization, which is brought up by the [Independent Market Monitor] from time to time, or something else,” said ERCOT COO Cheryl Mele during her panel’s discussion on balancing efficient markets with economics. “We need efficiency, we need reliability and we need people to get behind us and support us when we have reliability issues.”
“We all put ERCOT in a tough spot,” Market Monitor Beth Garza said. “We want the highest and best and most impartial decisions out of that organization, but they’re also responsible to their members. Sometimes those interests aren’t always advocated for. … We expect the highest and best, but that’s never good enough. There is a role for the [Public Utility Commission of Texas] in some of these decisions that is even higher and broader than ERCOT and its stakeholder organization. It seems like that’s at a level at which disparate interests can be effectively adjudicated.”
“If ERCOT is a democracy, then the PUC is a benevolent dictator,” responded Barbara Clemenhagen, vice president of market intelligence for Customized Energy Solutions. “If the recommendations are coming from ERCOT and IMM, they should be based on perfect information. It may not always be correct, but the stakeholders have the right and the opportunity to weigh in on those things.”
Randa Stephenson, vice president of wholesale markets for the Lower Colorado River Authority, also defended ERCOT’s stakeholder process. “Even though there are different advocates, the voting structure is very balanced within ERCOT. Our communications and structure ensures there’s equal weighting of all the market participants,” she said. “We have to find ways to work together to find the best solution. When you have the pull and tug, we’re going to come out with very different compromise solutions.”
Mexican market participants can buy and sell power, ancillary services, financial transmission rights and clean energy certificates (CELs). The first auction of energy and CELs last year saw an average price of $48/MWh, which decreased to $33/MWh in this year’s second auction. Regulo Salinas, vice president of Ternium Mexico, said he is optimistic about the third auction.
“That is where the private sector will come in,” he said, welcoming their expertise. “We need more specialized people that understand the markets. We have hardly any of them in Mexico … traders, meteorologists, pricing, financial and accounting specialists. … It’s an opportunity for intelligent communication types to come into Mexico.”
“I’m confident we are on the right path. There’s plenty to be done, but plenty has already been achieved,” said Eduardo Andrade, a member of the advisory board for Mexico’s Energy Regulatory Commission. “We have a framework based on competition. As a country, we’re moving away from having the government looking over your shoulder and determining who should generate the electricity and at what price.”
Panelists credited Jeff Pavlovic, managing director of electric industry coordination for Mexico’s Ministry of Energy, with much of the market’s success, though he politely declined to accept their praise. “Our guiding principle has been to make as many decisions as possible and not give any more control to the government than is absolutely necessary,” said Pavlovic, who left Xcel Energy eight years ago to work on the Mexican market.
“We know a lot of companies are interested in the market,” he said. “We’re asking them to make big investments, and that takes information. We’ve been doing this one step at a time, but until all rates are public, it will be hard to get that investment.”
Enrique Giménez Sainz de la Maza, managing director of The Blackstone Group affiliate Fisterra Energy, said the “next challenge” is developing a retail market. “Without a robust retail market, I have my doubts about the wholesale market.”
ERCOT Frontera Tie to Mexico | Fisterra Energy
Fisterra owns the 524-MW combined cycle Frontera plant in Mission, Texas, just 2 miles from the Mexican border. Frontera only recently withdrew from the ERCOT system and dispatches power into Mexico through a DC tie and a 400-kV line. “We now have something very interesting. We have a market on both sides … one is an energy market, the other is an energy capacity market. At the end of the day, we have managed to develop the reality of a market in Mexico thanks to this interconnection.”
Gerardo Serrato, InterGen Mexico’s commercial director, said future interconnections will only help the price convergence between the two markets. “Theoretically, those prices have to converge, but reliability issues might stop that convergence. Not all the Mexican systems are interconnected. If they can interconnect the whole system, we can see convergence between the Mexican and U.S. system.”
Genscape’s Rick Margolin said strengthening the energy infrastructure between Mexico and the U.S. will only feed further economic development. The senior natural gas analyst pointed to the NET Mexico Pipeline that connects the Agua Dulce Hub in South Texas with Monterrey in northern Mexico as an example.
“Gas prices aren’t what Mexican consumers can get by tapping into the U.S. market, so there’s a major push to gain access to the international markets, which means primarily the U.S.,” Margolin said. “Consumers are insanely frustrated by the level of service they get from [Mexico’s national gas supplier] Pemex. Global manufacturers are very interested in expanding operations into the Mexican market. Mexico has more trading partnerships than the U.S., but they’re hesitant … because of the lack of service or reliable service. We’re seeing a massive buildout of both gas and power infrastructure to the border.”
Dynegy CEO Shares Thoughts
Dynegy CEO Robert Flexon celebrated his company’s emergence from bankruptcy in 2012 and its entry into ERCOT earlier this year with the acquisition of almost 4,000 MW of ENGIE combined cycle gas turbines. Fifteen percent of Dynegy’s capacity is part of the Texas ISO.
“ERCOT’s view around generating assets tends to be fuel neutral. They’re not trying to create winners and losers; they’re trying to create a competitive market,” Flexon said. “We like our position, we like the assets we have. The market is going to continue to have need for flexible resources. The way wind affects price formation and with solar shaving peak pricing, it’s just going to be a really difficult environment for non-flexible resources to survive that.
“Is the price signal going to be there to change the resources?” he asked. “Will it force Texas into a situation where we’re doing out-of-market things? We hope Texas doesn’t do that.”
Anil Kumar, a senior research economist and adviser for the Federal Reserve Bank of Dallas, said the regional economy is expanding at a moderate pace, thanks to “robust” job growth in services and goods-producing sectors overcoming oil prices in the $40s. “Sharp drops in oil prices used to drop us into a recession, but that’s no longer the case,” he said, pointing to an unemployment rate of 4.7%, slightly below the national average. “We are probably looking at the worst of the energy bust being over.”
October being National Cyber Security Awareness Month, it was only appropriate one of the GCPA panels examine the growing cyber threats to electric utilities and how to fend them off. Renee Tarun, deputy director of the National Security Agency’s Cyber Task Force, warned attendees that external cyberattacks are growing increasingly sophisticated.
But she also said not to ignore the dangers from inside.
“We’re seeing these attacks surface as more and more technologies are connected to the Internet. We’ve seen ransomware becoming more prevalent. We’re seeing nation actors develop specific harmful code. These different types of malicious actions can range from hackers in their basement to sophisticated nation actors,” Tarun said.
“But there’s also the uniformed user, someone accidentally clicking on a phishing link that introduces malware to the network. It’s important we leverage our technologies to be more automated in our defenses, but also the user being educated in the system as well. Security needs to be built in at the beginning, not as an afterthought.”
“I would say 50% [of cyberattacks] are pure human negligence,” said Boris Segalis, a partner with Norton Rose Fulbright. “Vendors can lose track of hard drives that include critical customer data … small companies may not vet the vendor … not having your anti-virus up to date … you can’t really prevent hackers, but humans can take measures to mitigate the effects of these incidents.”
Asked by an audience member whether cybersecurity insurance is available, moderator Doug Henkin, a partner with Baker Botts, said insurance brokers do specialize in the product, but “it’s a growing market that essentially didn’t exist. It’s not a simple insurance to buy, it’s not a simple insurance to be underwriting. With respect to anti-virus software, you might be underwriting 15,000 different companies, but those companies are using five to 10 subsets of the software.”
Developers Look Beyond ERCOT’s Seams
Bill Bojorquez, vice president of planning for Hunt Transmission Services, suggested ERCOT’s DC ties with Mexico — which include a connection through Hunt subsidiary Sharyland Utilities — could provide an alternative to building more transmission in the Rio Grande Valley.
“We believe these ties … give ERCOT the ability to say, ‘Wait a minute, we have an extra tool’ and call their neighbor when there are unplanned outages,” said Bojorquez, who helped develop the ERCOT market while at the ISO in the early 2000s. “One of the things I’m most proud of is establishing relationships with Mexican utilities. They have the ability to respond in emergency situations, and they are highly motivated because it helps with trade.”
David Parquet, senior vice president of special projects for Pattern Energy, is looking eastward instead. His company’s HVDC Southern Cross Transmission Project, a project six years in development, is scheduled to connect ERCOT with the Southeast in 2021.
“If you think back 10, 15 years ago when the whole renewable business started, there was a lot of low-hanging fruit where you could find wind relatively close to load,” he said. “Those days are gone. Today’s big efficient renewable projects are a long way from load so therefore, you have to think about transmission. Sometimes, you can hook up to the local grid through a wheel, or you can put together your own project.”
But Parquet reminded his audience that transmission projects across the seam must “ensure no change in FERC jurisdiction over flows into ERCOT. [Maintaining ERCOT’s independence] is the Holy Grail. You will not change that. Period. Full stop.”
“In planning the future of the grid, we’re very much looking at distributed generation resources,” said Oncor’s Don Clevenger, senior vice president of strategic planning. “The numbers are still small, but they really don’t tell the whole story as far as looking ahead into the future. … Last year, only one-third of our feeds had any DG; today, it’s half. In four to five years, that [growth] is going to be astronomical.”
“If you look at overall capacity, 80% of the DG installed throughout the [ERCOT] system by the end of 2016 will be dispatchable. We’ll have close to a gigawatt by the end of the year,” said Greg Thurnher, general manager for regulatory policy with Shell Energy North America. “We’re very interested in that gigawatt as it becomes very intelligent as far as price. You will have a comparable playing field for wholesale resources when they act as true resources … and have the ability to influence the price.”
Austin’s Pecan Street Project, a collaboration between the University of Texas at Austin, Austin Energy, city officials and industry and environmental representatives, has been testing DG’s “intelligence.”
“We can manage every single circuit in the house,” said the project’s engineering director, Scott Hinson. “It’s a rather granular management … air conditioning controls, creating an electric vehicle charging control, looking at solar controls … things as simple as pointing the solar panels west, so their peaking output is available later in the day.”
Renewables Key to Texas’ CPP Compliance
Participating in a panel discussing the Clean Power Plan’s potent effects on the Texas market, the Environmental Defense Fund’s John Hall said the state is already “90% closer” to compliance, thanks primarily to its abundant renewable resources. “We currently produce more wind power than any other state. We have more potential for solar, energy efficiency and demand response than any other state,” he said.
“From our perspective, the market in Texas and our vast, clean-energy assets are putting us in a position where the market is driving us to the use of clean-energy resources,” Hall continued. “We have an opportunity to take the massive clean-energy resources we have and we can significantly rebuild this economy.”
“There may be permanent coal-plant reductions that occur as a part of the Clean Power Plan, but fuel diversity is going to suffer,” said a more cautious Susana Hildebrand, Energy Future Holdings’ director of environmental policy. “It affects our power prices, because there may be a day where for whatever reason, you need coal or baseload plants to be available. Betting on the future of natural gas prices doesn’t always work out.”
Greg Sopkin, a partner with Wilkinson Barker Knauer, warned about increased costs to rural customers. “Urban areas have a lot more customers to spread around the costs,” he said. “If you’re talking about forcing a change on rural areas in a very short period of time by shutting down baseload plants, you’re looking at real, very significant costs.”
WASHINGTON — The Supreme Court’s stay of the Clean Power Plan has largely ended the progress states were making toward creating regional frameworks for compliance, says Alexandra Dapolito Dunn, executive director of The Environmental Council of States (ECOS).
But even the most coal-dependent states are pondering ways to reduce their carbon footprints, she told a panel discussion at the Energy Bar Association’s Mid-Year Energy Forum last week.
“‘Carbon-considered’ is [the term used by] states that might have at one time been questioning whether or not there was climate change,” said Dunn, whose organization represents state environmental officials. “They’ve come around now.
“I think states will be more open to bringing renewables into their [generation] mix than they may have been before,” she explained. “There are companies that are located in very coal-oriented states that are already projecting ahead with their boards of directors and their shareholders to bring in a little bit of renewables, a little wind, a little solar, do some research and development in battery technology. You might not have seen that before.”
Two CPP opponents told the EBA forum that even if the EPA rule withstands legal challenges by states and utilities, its implementation will likely be delayed. The D.C. Circuit Court heard arguments on challenges to the rule on Sept. 27. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
“The likelihood of this rule being implemented the way it was finalized in August of last year is getting lower all the time,” said former EPA General Counsel Roger Martella Jr., of Sidley Austin. If the rule is upheld, he said, its 2030 deadlines could be pushed back to 2032 if the court also “tolls” the deadlines to account for inaction during the stay.
Allison Wood of Hunton & Williams, who argued before the D.C. Circuit on behalf of non-state challengers, agreed. Wood said the postponement of the D.C. Circuit arguments, which had originally been scheduled for June, means no Supreme Court review is likely until its next term, starting October 2017.
Dunn said the stay ended discussions among state officials on the technical issues concerning compliance, such as the development of emission trading programs.
“There were some really fantastic forums … where people were really putting their noses to the grindstone and trying to sort out these technical questions,” she said. “I almost wish we were still putting the same level of intensity into sorting out some of these questions that probably will be part of any future … carbon-managed environment.”
While some states are continuing their work and renewable generation is continuing to benefit from technological innovation, she said, “People are definitely following their own playbook at this point.”
The proposed protocol — which would continue on a smaller scale than the New York-PJM-New York flows of the wheel — has attracted criticism from stakeholders, which continued at last week’s PJM committee meetings. The influence and resiliency of phase angle regulators received some scrutiny from Citigroup Energy’s Barry Trayers at the Operating Committee meeting.
| PJM
“In a way you can kind of be picking winners and losers by adjusting [their] flows,” he said, asking how they had been factored into the grid operators’ guidelines for developing the replacement protocol.
“We consider PAR moves just like switching: a non-cost move that we’ll do prior to redispatching generation,” PJM’s Mike Bryson explained. “If we start running up against some of the either daily or monthly PAR adjustments, we’re going to have to take a step back and say, ‘Are we moving them too often? What’s the impact?’”
One challenge for the new protocol: One of the PARs on the 5018 line at Consolidated Edison’s Ramapo facility is not functional, which limits the ability to export power to NYISO. The grid operators have identified 1,800 MW as the maximum that needs to be available for export to NYISO, but the nonfunctional PAR limits PJM’s export capability to 1,400 MW.
While the future of Con Ed’s PAR has received a lot of discussion from other stakeholders, PJM has not received any details on when or if it will be fixed. One plan under review is to compensate by adjusting flows on the western interconnections across the Pennsylvania-New York border.
PJM and NYISO are currently working on updates to their joint operating agreement, which PJM will present upon completion for stakeholder review. NYISO plans to begin its stakeholder approval process at the end of October and complete it by January, which would allow the grid operators to make a joint filing to FERC later that month.
Stakeholders Urged to Submit Unit-Specific Parameter Adjustments
Generation unit operators have until Feb. 28 to submit adjustments to their unit-specific parameters, but PJM is urging them to begin the process as soon as possible because it can take several weeks.
PJM is aiming to have the status of delivery year 2017/18 adjustment requests posted by April 15. Parameters will be implemented in June. Any adjustments that are already approved remain valid, PJM’s Alpa Jani said, and don’t require resubmittal. Requests will receive a case identification number, with which requesters will be able to look up their current status through the RTO’s online member portal.
eDART Improvements Will Slow in Anticipation of Overhaul
PJM’s eDART system is getting an overhaul to incorporate new functionality, including single sign-on. To allow staff the time necessary to develop the new system, refreshes of the current system will be reduced to only those that are operationally necessary.
What won’t be changing are the business rules, the system interfaces or email notifications, said PJM’s Chidi Ike-Egbuonu. “One thing we can agree on is that it’s going to be a multiyear project; it’s not going to happen overnight,” she said.
PJM Moving Flat-File Data to Data-Management Tool
Raw data files are becoming too cumbersome and are being retired in favor of access through PJM’s Data Miner 2 tool, the RTO’s Thomas Zadlo explained. The tool will allow access to all data that is currently being stored on flat files, including five-minute settlements. Progress on the transition will be shared with stakeholders through PJM’s new Tech Change Forum.
WASHINGTON — “Pernicious subsidy” or “rough justice”?
Audience members got to decide for themselves how to characterize net metering for rooftop solar generation during a debate at the Energy Bar Association’s Mid-Year Energy Forum last week.
Richard L. Roberts, head of the electric group at Steptoe & Johnson, said it’s unfair that rooftop solar owners are paid retail prices as high as $0.13/kWh for the power they inject into the grid while central station generators are paid wholesale rates of about $0.04/kWh.
As a result, a customer whose solar panels generate energy equal to their consumption for the month “pays nothing for their electric service. They pay nothing for the reserves that they’ve been given. They pay nothing for transmission. They pay nothing for distribution. They pay nothing for public purpose programs, all of which go into retail service.”
Scott Hennessey, SolarCity’s regulatory counsel and vice president of policy and electricity markets, responded by citing a Sept. 30 ruling by the Massachusetts Department of Public Utilities last week that he said found rooftop solar provided more benefits than costs to the state’s grid. (See related story, Regulators Reject DER Surcharge in Rate Case.)
Glick | RTO Insider
He dismissed as a “common trope” the notion that rooftop solar is only for the “wealthy and well meaning.” The introduction of smart inverters allows rooftop solar to provide voltage support and other services to the grid, he said, while the introduction of financing options makes it available to the middle class.
Also participating in the discussion — though not staking a position on either extreme — was Mark Glick, administrator for the State Energy Office in Hawaii, a state that has provided a cautionary tale for regulators as generous subsidies have threatened to overwhelm the islands’ grids with solar generation.
Utility-Scale vs. Distributed Solar
Hennessey | RTO Insider
The session, moderated by Caileen Gamache of Chadbourne & Parke and Matthew R. Rudolphi of Duncan, Weinberg, Genzer & Pembroke, also touched on the virtues of distributed versus centralized solar generation.
“The question of whether or not [rooftop solar is] harmful to the grid or harmful to the average consumer I would turn around,” Hennessey said. “When you have infrastructure purchased by a utility and then spread across the entire rate base — with a fat profit, by the way, for the utility — that is a choice made decades in advance — and I think we’ve seen now, not always with the best of foresight,” he said. “Whereas when you have solar and the other distributed energy resources I’ve mentioned, that’s private investment in infrastructure that then benefits everyone around, with less peaking generation required.”
Hennessy said utilities that want to develop large-scale solar should be required to use a nonutility business unit rather than competing with other developers by using the utility’s low cost of capital and other advantages.
“What we’ve found is that every time they have tried that they have failed and they’ve had to close up shop, as [Arizona Public Service] did in Arizona.”
Jurisdictional ‘Mess’
Roberts | RTO Insider
Roberts said the Supreme Court’s FERC v. Electric Power Supply Association ruling, which preserved FERC’s right to regulate demand response, left a “jurisdictional mess” because the commission has no authority over net metering sales. Such sales should be a FERC-regulated wholesale sale under the Public Utility Regulatory Policies Act (PURPA), he said.
Roberts also cited studies showing utility-scale solar is two to three times more efficient than rooftop solar.
The rush to distributed generation could repeat the kind of mistakes California regulators made with the first retail choice program in the 1990s, which resulted in overpayments to qualifying facilities under PURPA and politicized integrated resource processes, he said.
“The goal of grid modernization should be to allow — without preferences or without predetermining who’s the winner and who’s the loser — equal access to all of these forms of technology to compete against each other and then wait and see where the next innovations come from,” he said.
“Nobody knows what the next big technological breakthrough is going to be. It might be large-scale generation, and if we’ve skewed our investments in the grid toward microgrid or small-scale [generation], we could find ourselves once again looking at investments and wondering why we did that.”
Hawaii’s Glick said “there’s no doubt” that utility-scale solar is cheaper than distributed resources. “But ultimately that will change and we have to allow the market to develop while that change occurs,” he said.
CARMEL, Ind. — Reviving his criticism of MISO’s lenient thresholds for uninstructed deviations, the Independent Market Monitor last week presented new data showing the impact of the RTO’s rules.
Market Monitor David Patton told the Oct. 4 Market Subcommittee meeting that slow-ramping units have too much flexibility to deviate from their dispatch instructions — so much so that generators can essentially ignore dispatch signals and not be penalized under MISO’s rules. Currently, generators are flagged if they deviate more than 8% from dispatch instructions for four consecutive intervals.
Under the current rules, generators drag by an average of 65 MW five minutes after receiving their dispatch instructions, and the drag worsens to an average of 314 MW when extrapolated to an hour, Patton said.
Generators are “basically being held harmless for poor performance,” Patton said. “We should not be paying you for refusing to turn on a mill.”
Patton has proposed moving to a system based on ramp rate, setting the threshold at half of the unit’s ramp capability with a cap of 10% of the dispatch level to limit gaming. The rules would make it so that units that are not responding to instructions after 20 minutes would be flagged.
“You can be motionless for 20 minutes before you would be flagged for dragging,” Patton explained. “You have to fail for three consecutive dispatch intervals before you are flagged for that hour.”
| Potomac Economics
Patton also said the proposal would eliminate the incentive to understate a unit’s ramp rate. The current 6-MW floor and 30-MW ceiling would remain.
The Monitor’s suggestion is not new: It first appeared in his 2012 State of the Market report, and it’s been brought up every year since, with Patton expressing disappointment that no progress had been made. (See MISO Monitor Debates Capacity Rules with Board.)
Stakeholders countered that it takes a long time to get large, baseload generators running. Operators will sometimes delay starting up units to make sure the dispatch signal is accurate, they said.
Patton responded that the heart of his suggestion is a “tolerance” that would give generators extra time to respond before they are flagged for dragging. But he said he could do more analysis on the reasons behind start delays.
The Monitor also said his team continues to investigate wind resources, which have larger deviations than any other resource type. “We think there may be economic incentives to over-forecast wind, and wind resources may be deliberately over-forecasting to MISO,” Patton said.
Chad Koch, market strategist for WEC Energy Group, said Patton’s proposal may hurt “fast-moving, accurate machines.” While “big resources move slowly and wind resources are up to the whims of Mother Nature, they should not get free rein,” Koch said.
MISO said an analysis against historical real-time data is needed to understand the impacts of the Monitor’s recommendation before it is adopted. In late spring, the RTO said the scope of the project had delayed its target for implementation to next year. (See “Changes to Uninstructed Deviation Thresholds Longer than Anticipated,” MISO Market Subcommittee Briefs.)
MISO’s John Weissenborn said staff would come back to the Nov. 29 Market Subcommittee meeting with its own proposal. Threshold changes, Weissenborn said, would most likely go into effect by the middle of the second quarter.
