CARMEL, Ind. — Facing a FERC complaint from transmission customers, MISO last week defended its calculation of sub-regional transfer limits for the 2016/17 Planning Resource Auction and recommended that it continue to use the same numbers for future auctions.
The RTO made its recommendation based on stakeholder feedback it received, which shows general support for maintaining the status quo, said Kevin Sherd, director of forward operations planning, during a presentation at the Oct. 5-6 Resource Adequacy Subcommittee meeting.
MISO calculates the transfer limits between its North and South regions by deducting firm reservations from 2,500 MW for flows South to North and 3,000 MW for North to South. The initial transfer limits were prescribed in the RTO’s settlement with SPP that became effective in February.
Last month, a coalition of transmission customers filed a challenge to the results of the PRA with FERC, arguing that the limits are too strict and trapped capacity in MISO South, driving up clearing prices. (See MISO, IPPs Ask FERC to Reject Bid to Redo Capacity Auction.)
Six of 11 stakeholder respondents to a MISO survey on the issue endorsed deducting all firm reservations, while three wanted only pseudo-ties subtracted, and one apiece wanted nothing subtracted and net reservations subtracted. Seven recommended maintaining the current initial limits, with the minority split between using 1,000 MW or another method altogether.
Sherd said MISO doesn’t have much of a choice in subtracting firm reservations. “It’s firm transmission service. Firm transmission reservations can be scheduled at any point. It can’t be reduced absent a transmission congestion event,” he said.
But some stakeholders at the meeting disagreed that all firm reservations are absolute and must be subtracted.
In this year’s State of the Market report, MISO’s Independent Market Monitor recommended subtracting “a derating factor that represents the probability that MISO neighbors will request a derating” of the current initial limits.
“MISO is saying there’s no room for redispatch when all of the firm transmissions are subtracted,” Monitor Michael Chiasson said. “We’re saying there has to be something in between. … What’s the chance of that really being the norm and what’s the more likely case?”
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Steve Leovy, a transmission engineer at WPPI Energy, agreed and said a “probabilistic” approach was needed.
But ITC Holdings’ Ray Kershaw said he had never heard of using transmission-use probability. “We can throw out terms like ‘probability,’ but I don’t know of a method for calculating the probability of transmission use. There are certain things that need to be assumptions; there’s the [loss-of-load] expectation, I understand that. Could someone put this method down on paper?”
Leovy said MISO should make a best effort to estimate expected system capability and not focus so much on making sure it does not exceed the limit under any circumstances.
Sherd said it would be an “administrative nightmare” to track individual firm reservations and monitor the likelihood of it being used. “It’s not on a planning year basis; it’s on a daily, weekly, monthly basis,” he said.
According to MISO, the Monitor’s suggestion is not allowed, as MISO and SPP’s settlement agreement forbids a “unilateral” lowering of the sub-regional limit.
Firm Flow Limits Study
Rather than the existing initial limits or 1,000 MW, one stakeholder suggested a study of firm flow limits to establish new initial limits.
Per that request, MISO reviewed market flows compared with firm flow limits on several days this summer, examining 19 Tennessee Valley Authority flowgates that experienced transmission loading relief anytime in 2016. The analysis, MISO said, showed that South-to-North market flows “would generally be firm at flows near or above 2,500 MW.” The RTO said only one of the analyzed flowgates averaged below 2,500 MW.
MISO said it plans to continue reviewing transmission loading relief annually. The RTO is seeking final feedback on reusing the limit approach in the PRA by Oct. 12. MISO staff plan to review a limit proposal at the Nov. 2-3 RASC.
Per SPP and MISO’s settlement, firm transmission reservation holders have until Dec. 1 to confirm or cancel service above 1,000 MW for planning year 2017/18. MISO will publish its sub-regional import constraint and sub-regional export constraint values for the 2017/18 PRA before March.
Dynegy’s Mark Volpe asked if MISO could even discuss its North-South contract limit plans given the complaint at FERC.
“I think given the complaint is public and MISO’s response is public, there should be very little issue in discussing it,” MISO’s Jacob Krause said.
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.
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“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.
CARMEL, Ind. — MISO’s mechanism for allocating charges under its settlement with SPP was certified by a FERC administrative law judge last week (ER14-1736).
MISO has been using a temporary miscellaneous charge based on market load ratio share to collect the $1.33 million a month it is paying SPP until February for flows over 1,000 MW passing through MISO’s North-South interface. Under a settlement reached with its stakeholders, MISO will use a new, modified market load ratio share basis to allocate those costs. This method also applies to the $16 million it paid from Jan. 29, 2014, to Jan. 31, 2016, but that amount won’t be subject to resettlements, MISO Director of Market Services John Weissenborn told the Market Subcommittee on Oct. 4.
From Feb. 1, 2016, to Jan. 31, 2021, MISO will use a transitional, hybrid method, with a continuously declining percentage of the costs allocated through the new load ratio share calculation and an increasing amount through a flow-based benefits allocation methodology.
Weissenborn said the RTO will continue to allocate the costs under the current method until FERC accepts the settlement agreement and accompanying Tariff language. After approval, MISO can begin resettlement for costs from Feb. 1, 2016, and beyond.
“We can almost anticipate two resettlements: one to true-up the $1.33 million and another to implement the cost allocation,” Weissenborn said. Weissenborn said payments under a true-up will be a simple calculation, but the new cost allocation will be trickier: “The challenge that we have is that this is another new software change, but we will comply. We will get it done.”
Weissenborn said MISO will hold future stakeholder meetings on two remaining internal cost allocation issues under the settlement: how much entities with firm transmission that reduced the 1,000-MW capacity limit will have to pay and what cost allocation is needed for entities with capacity benefits that raised the Planning Resource Auction limit above 1,000 MW.
IMM Seasonal Review: Pricing Changes Still Needed
Independent Market Monitor David Patton used a review of last summer to continue his push for pricing changes.
Patton said summer’s 44% rise in energy prices over spring’s was due to increased natural gas prices and 1% larger year-over-year demand from summer 2015.
“Because of hot temperatures, we did rely more heavily on peaking resources,” Patton told the Market Subcommittee. The uptick led to more revenue sufficiency guarantee payments, culminating in a peak of almost $1.7 million in payments on July 21, when nearly all of MISO’s generating turbines were committed during a maximum generation event. The day also resulted in 1.6 GW of voluntary load curtailment, which lowered real-time energy prices to $36/MWh, even though the day-ahead price was $78/MWh. (See “IMM Makes Pricing Suggestions Following First Max Gen Event Since Polar Vortex,” MISO Markets Committee of the Board of Directors Briefs.)
“The problem with this is these are megawatts outside of MISO’s control,” Patton said. “You’re incurring an awful lot of costs just to turn these generators on. You’re certainly forcing the system to accept a lot of high-price energy. It makes it difficult to price the energy. …There are some things MISO could take a look at, and MISO is taking the process very, very slow.”
Patton repeated his suggestion that increasing the number of generators allowed to set prices under extended locational marginal pricing would temper erratic pricing.
“Procedures that say ‘turn everything on’ are not efficient, especially when there’s a more surgical” method, Patton said.
Jeff Bladen, executive director of MISO market services and liaison to the MSC, said the RTO will need to work with individual states and load-serving entities to improve the visibility of demand response. But he stood by the July 21 decision to issue the alert.
“What drove the over-commitment was not self-deployment. It was very much about the weather. Had the [stormy] weather in the forecast materialized, we would have absolutely needed the commitments,” Bladen said. Patton said he didn’t completely agree with that assessment.
Patton also said summertime outages that impacted constraints had a hand in increasing real-time congestion to $463.4 million in summer 2016 from $342.2 million in summer 2015.
MISO to Expand ELMP Price Setting, but not to IMM’s Specs
MISO Market Design Engineer Congcong Wang said the RTO is willing to expand ELMP to online resources with a one-hour start-up time without software changes.
The RTO says the possible expansion “captures a majority of peaking resources.”
Wang said the Monitor’s original recommendation that online price setting be spread to all resources with a two-hour minimum run time is neither cost effective nor beneficial with MISO’s current software. “The full expansion to two-hour minimum runtime will require software changes,” Wang said. (See MISO Study Undercuts IMM Proposal on Expanding ELMP Pricing.)
MISO’s path forward would increase eligible peaking resources from 8% to 58% on a capacity basis. Wang said the expansion without software changes captures about 60% of the Monitor’s recommendation “in terms of real-time commitment.”
With the addition of one-hour start-up units, ELMP price setting, which currently includes about 45 10-minute start-up units with a combined capacity of 1.2 GW, would increase to 179 units at 8.4 GW. The Monitor’s advice to include two-hour minimum runtime units would bring the number to 256 units at 14.4 GW.
However, MISO is not willing to budge on removing offline units from price setting in ELMP, another Monitor suggestion. Wang said MISO’s research shows that offline fast-start resource participation can address shortages. MISO said it “will work with its IMM to continue monitoring offline participation and will exclude a resource from pricing if it is found infeasible.”
Wang said MISO would likely make a final decision on resource pricing under ELMP at the December Market Subcommittee meeting.
If the RTO decides to go with the option that does not require a software change, Wang said implementation could begin in the first quarter of 2017.
The introduction of coordinated transaction scheduling with PJM will be delayed from March to next October, Bladen said during a Market Subcommittee liaison report.
Bladen said the date change is needed while MISO waits on PJM to complete market improvements and staff training. He added that joint filings will be made soon to update FERC on the later implementation date.
David Sapper of Customized Energy Solutions asked how stable CTS will be given that MISO is also trying to implement interface pricing rules with PJM. (See “No Consensus on Interface Pricing,” MISO/PJM Joint and Common Market Meeting Briefs.)
Bladen said while there is a relationship between the two market improvements, they aren’t related to a degree that would prevent them from being introduced independently.
“There’s no premise that you have to have one before the other,” he said. “They’re not intrinsically tied. They’re relative improvements of the same process.”
CTS is intended to reduce uneconomic flows between the two RTOs. The new product would allow traders to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeds a threshold set by the bidder.
MISO Considering Moving Reserve Buy-Back into RSG
MISO is investigating a way to make up lost revenue for resources committed in real time that have previously cleared day-ahead offline supplemental reserves, said Jason Howard, MISO manager of market quality.
Currently, generators that commit in the real-time markets have to buy back their supplemental reserves.
MISO is considering providing make-whole payments to such generators through revenue sufficiency guarantee payments, Howard said. He said the proposal, which would require a Tariff change, would ensure that those units aren’t operating at a loss.
MISO looked at four years of historical data and found the average cost for buying back supplemental reserves amounts to $1 million per year across the RTO, Howard said.
CARMEL, Ind. — MISO’s Market Roadmap projects have been rearranged following stakeholder complaints over the lack of transparency behind the RTO’s reasoning for how it ranked them.
Stakeholders first raised their concerns over the rankings, and how MISO’s ordering was merged with stakeholders’ classification preferences, during the August Market Subcommittee meeting. The projects in the Market Roadmap, a work plan for market issues, were originally supposed to be ranked by early August.
“There were obviously some differences between what MISO and its stakeholders thought were priorities,” said Mia Adams, a senior market strategy analyst. Now, the four high-priority Market Roadmap projects are:
Aggregating load to meet minimum participation limits, which was previously ranked as a low priority by MISO;
Automatic generation control enhancement for fast-ramping resources, which was ranked high priority by stakeholders; MISO revised the priority from “low” in June to “high” in a second draft of the work plan in August;
Behind-the-meter storage aggregation under Type II demand response resources, which MISO previously gave a low priority; and
Introduction of multiday financial commitments, voted high priority by both MISO staff and stakeholders.
| MISO
With the reorder, MISO’s goals of developing additional short-term capacity reserve requirements and incorporating DR, emergency DR and boiler-turbine-generator deployment during capacity emergencies moved from high to medium priority. In addition, a pricing structure for voltage and local reliability commitments moved to low priority despite solid accord for a medium-priority ranking from the RTO and stakeholders.
The reorder provoked little discussion, as MISO almost completely aligned its prioritization with the stakeholders’ opinions.
MISO’s power marketers sector advocated that a virtual spread product be given high priority, but Adams said the RTO would need technological upgrades before it could complete the project. The issue was ranked low priority.
Of the 17 issues identified in the Market Roadmap process at the beginning of the year, five — including coordinated transaction scheduling with SPP — were placed in “parking lot” status, meaning they aren’t going to be given attention anytime soon.
MISO will unveil the final project prioritization in December.
Energy Future Holdings reached a major milestone in its Chapter 11 reorganization Monday, completing its tax-free spinoff of Luminant and TXU Energy into a new standalone company, TCEH Corp.
TCEH issued 427.5 million shares of common stock and other assets to the “pre-emergence” first-lien creditors of Texas Competitive Electric Holdings Co. It will trade on the OTCQX market under the ticker symbol THHH.
Luminant is Texas’ largest electric power generator with almost 17,000 MW of generation, including 2,300 MW of nuclear power, 8,000 MW of coal and 6,000 MW of natural gas. TXU Energy, a competitive retail electricity provider, has 1.7 million business and residential customers in Texas.
TCEH appointed as its CEO Curt Morgan, a consultant for the first-lien creditors and a former operating partner at private equity firm Energy Capital Partners. Also appointed to the board of directors were Gavin Baiera, Jennifer Box, Jeff Hunter, Michael Liebelson, Cyrus Madon and Geoffrey Strong.
In a statement Tuesday, Morgan said the company emerged from bankruptcy “with a strong balance sheet and the potential for stable earnings and significant cash generation,” having eliminated more than $33 billion of debt and other obligations and reduced its leverage to a low 2.3 times of gross secured debt to cash flow.
EFH said it was continuing its efforts to complete its reorganization with its sale of its 80% interest in Oncor, Texas’ largest transmission and distribution utility.
NextEra, EFH Seek to Reassure Texas PUC on Merger
Last week, EFH and NextEra Energy sought to assure Texas regulators they won’t be constrained in their review of NextEra’s agreement to purchase Oncor, which includes a $275 million termination fee.
During an update hearing Sept. 26 on EFH’s emergence from Chapter 11 bankruptcy (14-10979-CSS), Judge Christopher S. Sontchi said he had filed a joint letter from EFH and NextEra addressing the Public Utility Commission of Texas’ concerns.
PUC Commissioner Ken Anderson said during a Sept. 22 open meeting that the termination fee “appears to be an effort to really tie the commission’s hands in the proceeding,” as it would allow NextEra to cancel the deal if the commission imposed “overly burdensome” conditions. Anderson also called the fee an “improper attempt to constrain the commission.” (See Texas PUC Expresses Doubts over NextEra-Oncor Deal.)
NextEra has proposed buying Oncor for $18.7 billion.
According to the letter, “NextEra is not entitled to a termination fee under the merger agreement if NextEra Energy terminates the merger agreement because the commission either approves the merger agreement transaction with ‘burdensome conditions’ … or does not approve the merger agreement transaction.”
NextEra and EFH said the termination fee would be triggered only if EFH or Energy Future Intermediate Holding Co., Oncor’s direct parent, terminate the merger agreement. The companies wrote they “would like to make clear that, in any event, NextEra will not seek to collect any portion of the termination fee contemplated by the merger agreement in the event it terminates the agreement.”
Sontchi opened Monday’s hearing by quoting from the transcript of the PUC meeting.
“I believe [the] letter addresses the concerns raised by Commissioner Anderson,” Sontchi said. He said any possible triggering of the termination fee is “an issue for the bankruptcy court, and not for the PUCT and ratepayers.”
The PUC’s approval is just one of several favorable regulatory rulings NextEra and EFH must secure before closing the deal.
