Just one project from MISO and SPP’s coordinated system plan study will move forward for individual votes on regional review, officials told the Interregional Planning Stakeholder Advisory Committee meeting Monday.
The project will loop one Split Rock-Lawrence 115-kV circuit into Sioux Falls to relieve congestion on the Lawrence–Sioux Falls 115-kV line in South Dakota, on the tie line shared between the Western Area Power Administration and MISO’s Xcel territory.
Final results showed costs of $5.2 million and a 4.42 benefit-cost ratio. MISO would pay 81% of the cost and SPP the remaining 19% based on benefit estimates for the first 20 years of the congestion-relieving project.
The project faces an obstacle course of approvals before construction can begin. MISO is conducting a project vote among Planning Advisory Committee voting sectors at a special meeting on April 27 for its portion of the IPSAC vote. SPP’s IPSAC vote will occur at its Seams Steering Committee teleconference on May 3. If both RTOs approve, the project moves into a SPP-MISO Joint Planning Committee vote and then into an IPSAC review conducted via email. If the project passes all review and votes, it will face an approval process before each of the RTOs’ board of directors.
The RTOs hope the approval process concludes in October, said Adam Bell, SPP’s interregional coordinator.
MISO and SPP considered seven potential interregional projects during last year’s coordinated system plan, and in earlier estimates, the South Dakota project fell just short of the $5 million interregional project threshold in the RTOs’ joint operating agreement. Earlier estimates also showed a more even cost split between the RTOs. (See MISO-SPP Coordinated Study Yields 1 Possible Project – For Now.) Bell said recently approved generator interconnect projects in MISO’s queue shifted more of the project’s cost to MISO, as the projects will benefit from congestion relief and increased transmission ratings.
Bell said project construction is complicated by the fact that the project is a tie-line, not wholly located in either footprint, and each RTO’s portion of the construction will be handled independently. MISO staff said how the RTOs ultimately decide to split construction on the small project could be used to define an improved process for projects that cover ground in both footprints going forward.
Bell also said that some interregional projects under consideration failed because of the $5 million cost threshold, which he said the RTOs are open to changing.
Another possible interregional project was revealed on April 19, but the $153.7 million candidate — the Lacygne-Blackberry 345-kV line, 345/161-kV transformer and Blackberry-Asbury 161-kV line in Kansas — graded out with a scant 1.03 benefit-cost ratio. MISO would be allocated 5% of the cost and the remaining 95% paid by SPP.
Davey Lopez, MISO adviser of planning coordination and strategy, said the project barely passed the required 1.0 benefit-cost ratio and the minimum 5% regional benefit thresholds in the joint operating agreement. “Any increase in cost would likely drop the benefit-cost ratio below 1, and SPP is investigating other, much cheaper solutions,” Lopez said at an April 19 MISO PAC meeting.
The project failed to win recommendation from either RTO during the interregional meeting.
HOUSTON —The Gulf Coast Power Association’s 2017 Spring Conference last week attracted around 400 attendees for discussions on energy storage, ERCOT transmission policies, the future of energy policy under President Trump and the changing generation mix in the U.S. and Alberta, Canada. Here’s some of what we heard.
NRG Energy CEO Mauricio Gutierrez delivered the opening keynote address, professing the company’s passion and commitment to ERCOT and the desire for a structure “that is sustainable and provides the benefits of competition to businesses and consumers here in Texas.”
Gutierrez said he was concerned about price formation in the ERCOT market, the growth of renewables and what he called the preference for transmission over market solutions in the planning process. “There’s a lack of balance in transmission planning policy, which undermines wholesale prices and which will eventually overwhelm the competitive retail market and consumers,” he said.
Gutierrez’s solutions? Improve the operating reserve demand curve’s price signal with a locational component; include marginal losses in ERCOT prices; minimize the use of out-of-market actions; address mitigation rules for reliability-must-run units; and balance transmission investment with market-based solutions.
“When you mitigate RMR units, you’re suppressing prices exactly when it’s not supposed to. It interferes with the market’s ability to meet reliability needs,” Gutierrez said.
“I tend to be transparent when it comes to the ERCOT market and very forthcoming,” he said. “I always like to polarize the conversation, because it brings out the essence of the issue. The more open and transparent we have that conversation, the quicker we’ll get to the right answer. We cannot afford to keep dancing around.”
Unwinding Environmental Regulations Won’t Be Easy
Jeff Holmstead, a partner with the Bracewell law firm who headed the EPA’s Office of Air and Radiation from 2001 to 2005, opened a panel discussion on Trump’s first 100 days as president by taking the audience back to the morning after his November election, joking: “You probably woke up to a surprise. Who would have thought California would legalize recreational marijuana?”
Sempra Energy’s vice president of federal government affairs, Maryam Sabbaghian Brown, was more serious. “It’s been made clear, and the president has made clear, that reforming the Clean Power Plan is a top priority. This administration is very focused on delivering on that campaign promise,” she said.
But it won’t be easy, said Brown, who served as an energy and environment adviser to House Speakers John Boehner and Paul Ryan. “There are the delays we’re seeing in nominations for second- and third-tier executives for the agencies that do a lot of the work involved in unwinding these rules,” Brown said. “There needs to be a recognition that there will be a lot of time involved in doing this work. It doesn’t happen with a simple wave of the wand for mechanical and legal reasons.”
“The big challenge is getting through the years and years of regulatory processes,” said Clean Line Energy President Mike Skelly, whose company is working to secure approvals of five different high-voltage transmission lines across multiple states. “We’ve gotten there with one project, and we’re close to the finish line with another. I cannot overstate the difficulty of multistate approvals. Every day is a mad dash.”
Skelly agreed with the Trump administration’s push for a $1 trillion infrastructure bill, which may include some public-private partnerships.
“Energy … doesn’t carry the public price tag that water, bridges and highways do. Those are direct expenditures,” said Skelly, an unsuccessful Democratic congressional candidate in 2008. “I think Democrats will get behind it. In the sense you need a bipartisan vote on infrastructure, transmission may fit in. It’s not a huge universe type of project.”
“First, you have to recognize the unifying nature of energy and environmental policy within the Republican Congress,” Brown said. “Health care and tax reform are taking up the greater part of the oxygen in Washington, D.C. It’s difficult to get consensus on those issues within the Republican conference, but energy and environmental policy presents a real contrast to those issues in that it is a unifier for their conference, and it can also be a bipartisan issue. I think there’s a real opportunity to advance policies that support the energy business.”
Skelly was less optimistic about the tax credits for wind and solar energy, which are due to begin phasing out this year. (See Solar to Shine Under ITC Extension.)
“We’ve been in many discussions with the leadership and others in Congress and the administration, and it’s like, ‘A deal is a deal. You guys agreed to phase these out.’ You never know, but you feel like the decision’s been made.”
Addressing FERC, which is one commissioner short of a quorum and also has Colette Honorable facing the end of her term this summer, Brown said the commission will likely defer more responsibility to the states and grid operators.
“We’re still waiting for the formal FERC nominations, but it seems as though the new commissioners are not coming in with a preconceived federal agenda as we saw with the [George W.] Bush and Obama administrations,” she said. “It will be perhaps more reactive, and give a lot of deference for the states to do what they want to do. That’s not to say we won’t see involvement from the federal government, but the states and ISOs are going to continue to lead in their spaces.”
Alberta Electric System Operator CEO David Erickson described his own challenges with governmental change in Canada and the resulting effect on the ISO’s market, which is home to the country’s oil sands production. AESO has been operating an energy-only market, under a right-leaning, business-friendly Progressive Conservative party government that has controlled the province for decades.
When the New Democratic Party took control following the 2015 elections, Erickson said AESO — which relied on coal for 62% of its power production last year — was forced to determine how to phase out coal-fired generation by 2030.
“The new government wanted to do something in a more aggressive way. It wanted to do things quicker,” he said. “We came to the conclusion an energy-only market was not sustainable unchanged. There was too much investment needed in thermal power plants, too big of an influx of renewables that push down the price and impair that [thermal] investment.”
AESO is now transitioning to a capacity market to ensure reliability and price stability. It supports the government’s Climate Leadership Plan.
“We’ll replace two-thirds [of coal energy] with wind and [the remainder] with natural gas,” Erickson said. “That’s our only choice. We did not want power to be a business disincentive for the province or start losing business to other states because of power issues.”
Desires of Consumers, Commercial Customers Changing Generation Mix
As part of a panel discussing how consumers can drive changes in wholesale and retail power markets, Chris Hendrix, director of markets and compliance for Wal-Mart Stores, agreed that renewable power is squeezing out conventional power sources.
“Why are the large corporations doing it?” he asked. “It really comes down to they’re getting pressured by investors, owners, customers and employees, or a combination of those, to green up their footprint. Instead of greenwashing it, they’re going out and buying green power.”
Maura Yates, co-CEO of Mothership Energy Group, a group of women-owned energy solutions companies, agreed. “They’re being driven to procure for a number of reasons,” she said. “It’s now a value stream for the corporation. We’re seeing loads influence the power market. It’s a really telling thing that loads today are buying based on subjective and objective values.”
Asked whether the demand for customer choice might lead to further deregulation, Hendrix said the push to deregulate goes in ebbs and flows. “It looks like we’ll get it nationwide, then it falls apart,” he said. “Now you see California talking about full and open retail competition. A lot of it is driven not only by the large industrials, but retail customers who want to have a say in where their generation comes from.”
“Another reason is the transparency,” Yates said. “There is so much more transparency in the deregulated space than there is in the regulated space. That makes it so much easier to charge 20 cents/kWh” in the latter, she said.
Mike Sullivan, CEO of Texas retailer Champion Energy Services, said no one should assume renewable energy and storage technologies will lead to migration away from the grid.
“If people knew what they wanted, that might expedite that,” he said. “But the fixed costs are there. You can’t fight city hall, and you damn sure can’t fight the utilities.”
A panel devoted to energy storage and related “technology enablers” agreed that as costs continue to come down, the industry will only become more familiar with storage devices and more open to their use.
“When you’re planning systems five years out, the culture makes it very hard to get planners to look at storage, because they’re very technical,” Electric Transmission Texas President Kip Fox said. “As they become more familiar with storage technology, we’re starting to see these applications for batteries rather than traditional transmission solutions.”
“This is very commercial right now,” argued Kiran Kumaraswamy, market development director for AES Energy Storage. “There’s no need to do research and development and promotion projects. It’s always cheaper than what you think the cost is. Even though we talk about storage in isolation, adding storage to the system helps you operate your facilities much more efficiently. We’re optimizing price patterns on the overall grid. That’s something AES has seen in every market we have entered, whether it’s PJM [or] the Chilean market.”
HOUSTON — The CEOs’ roundtable has become one of the top draws at the Gulf Coast Power Association’s Spring Conference, and this year was no different. Bill Magness (ERCOT) moderated an April 19 panel that included John Bear (MISO), Steve Berberich (CAISO), Nick Brown (SPP) and Brad Jones (NYISO). The five discussed the state of wholesale markets, grid operations, implementing federal and state statutes and regulations, and cybersecurity readiness.
“We have renewable portfolio standards by states, tax incentives for wind,” Bear said. “That has a big impact on our marginal costs, especially in Illinois, and that has put a lot of pressure on coal plants and nuclear plants there. Rather than talk about state issues and state subsidies, we’ve got to talk about all the issues together, because they’re colliding. They’re coming to a head.”
Berberich agreed, saying that as CAISO has installed more solar and wind capacity, it needs to find ways to harness their power. “If we don’t use a distributed generating asset in our market, we’re going to have to duplicate them on the central system, and they cost too much,” he said. “As a grid operator, I’m sure we can all agree storage is a valuable resource. It’s the most flexible resource you can get. We have to be concerned about all system costs, because I think system costs are one of these things that can stop decarbonization.”
Distributed generation also was on the mind of Jones, who said if ISOs and RTOs are going to accommodate those resources onto their systems, “We have to chart that path for the aggregators.
“We have to show them what type of generation we need. We have to show them how we price them and how we dispatch them. We have to show these providers how we’ll monitor their performance,” Jones said.
Among the challenges the CEOs share is forecasting variable resources.
“I’ve been fascinated with the success we’ve had in forecasting [wind energy],” Brown said. SPP has integrated 16 GW of wind into its footprint, with penetration levels exceeding 54%. “That success has come from the granular nature of the forecasting. We’re taking multiple data points in each counting. That amount of data is massive, but that’s just the tip. As many have postulated, solar will be the next wind. If you look at our footprint, the solar will be laid over the wind. The next question is, where will it go?”
Jones said NYISO has made progress on the challenge of quantifying rooftop solar. “We’re actually taking real-time data right now off of 10% of the rooftop panels statewide,” he said. “We’re rolling that through a forecasting tool, which looks at each [transmission] zone across the state. We’re having incredible results with that now.”
Asked about the Department of Energy’s recent announcement of a study on renewable energy’s effect on baseload generation, Berberich said, “I’d say it’s a short study. I could probably do it in about an hour.”
“Natural gas took the first bite out of coal and nuclear; that’s not going to change,” he continued. “When you inject zero-cost renewables, it’s going to crush capacity costs. So, there you go. There’s the report.”
Cybersecurity Concerns
Brown addressed the grid’s security, using the military’s drilling with live ammunition as an example.
“We talk about the grid being such a huge national resource and yet, in my view, we’re not really taking any steps to prevent [physical] attacks because of the money involved,” he said. “The concept in many of our states is there’s only so much spare equipment that meets that used-and-useful test. A utility is not going to get recovery on that, which kind of boggles my mind. We’re not, in my view, taking adequate steps to build the infrastructure to be able to respond.”
Community Choice Aggregation
Looking into the future, Berberich said Pacific Gas and Electric could be losing as much as 40% of its load to community choice aggregators, which draws into question the entire utility model. “These aggregators are generally communities, towns, cities and counties that want to procure their own energy and get out from under the incumbent utility,” he said. “Many of them are associated with cleaner, greener energy, but there’s the broader issue here of just choice. Should the utilities be in the retail business? Because all this load is coming off anyway.”
PHILADELPHIA — PJM’s Grid 20/20 conference last week on grid reliability and fuel diversity left room for discussing all generation sources, but the conversation kept finding its way back to the natural gas pipeline system.
Jackie Roberts, the director of the West Virginia Consumer Advocate Division, started it off with a big proposal.
“It’s time for FERC to have someone regulate the pipeline build in the most efficient manner and make sure they’re built where they need to be built, not unlike transmission planning in PJM,” she said on the first of three panels throughout the day. “This needs to be resident in an expanded RTO or ISO. You know the problems we have with dealing with other RTOs. Imagine if we’re dealing with a different industry. It’s just unnecessary to have those complexities, so I’m proposing [a] PJM division that would do for the gas industry what it does for the electric industry.
“If I had a Ferrari in a race, I really wouldn’t want the fuel to be brought to me in the pit by the fuel barrel. I would want to know it was there and it was sufficient and it was being used as best it could be,” she added.
‘Premature’
Glen Thomas, president of the PJM Power Providers Group and GT Power Group, said such a sweeping change is “premature,” but the electricity industry needs to better understand the supply chain of one of its most critical inputs.
“The big message is we all [have] to get a little smarter about gas and understand the industry better than we currently do,” he said.
Mark McCullough, American Electric Power’s executive vice president for generation, pointed out an imbalance. Generation owners know even the smallest details of their units, he said, but “then you think about what’s happening on the other of the gas valve and wonder if those same kind of delivery approaches are taking place that brings that critical fuel to the asset that you’re spending so much time [on] making sure everything else works.”
That question isn’t unique to PJM, where a third of power is supplied by gas. Jeff Weathers, Southern Co.’s resource planning manager, said his company maintains a predominantly gas-fired generation fleet and performs an annual analysis of how the company could respond to potential pipeline failures.
Robert Kott, CAISO’s operations policy manager for regional operations policy and analytics, said 54% of California’s generation fleet is gas. He noted that a leak at the critical Aliso Canyon gas storage facility last year forced the ISO to adjust its market to reflect pipeline constraints. (See FERC OKs One-Year Extension for CAISO’s Aliso Canyon Gas Rules.)
Cara Lewis, Public Service Enterprise Group’s associate general regulatory counsel, said “heavy reliance on one fuel source negatively impacts resiliency and is not good for consumers.” She pointed to a pipeline explosion in Pennsylvania in April 2016 that created supply constraints in the Mid-Atlantic region.
“Our analysis shows that if this had happened in winter, we would have had to interrupt our electric-gas generation in order to fully supply our heating demand,” she said. “The choice for our customers would have been heat or light, but not both.”
Jurisdiction
Part of the issue is who is in charge of what. Joseph McClelland, the director of FERC’s Office of Energy Infrastructure Security, stressed that his office doesn’t set standards and regulations, only assesses their implementation and makes recommendations to the commission and other federal agencies. The Department of Energy coordinates the entire energy sector, he said, and the Department of Homeland Security and Transportation Security Administration set standards for pipeline cybersecurity, while the U.S. Coast Guard does so for LNG terminals.
McClelland echoed Thomas’ comments that the electricity industry needs to do more to understand the natural gas supply system. He said gas-fired generators need to consider “what sort of contractual obligations do [pipelines] have? What’s their security posture? And what’s your recovery plan if the gas pipeline is lost?”
“The good news is in terms of how we built out the grid, it’s incredibly efficient, it’s economically effective, it’s highly reliable — but it’s also more heavily interconnected than it’s been at any given point in time in the history of the grid,” PJM’s Jonathon Monken said. “That’s why this conversation is timely and relevant because we need to look at those interdependencies in a different way.”
PJM CEO Andy Ott addressed the topic with his opening remarks, saying one of the RTO’s current questions is whether it’s recognizing the operational risk of a pipeline disruption. “Instead of worrying and saying, ‘Are we sure we’re secure?’ I think defining the problem and looking toward defining solutions is the way to go,” he said.
The Natural Gas Supply Association, which had a representative in attendance, did not respond to requests for comment.
HOUSTON — Mexican policymakers said last week their country is moving steadily in its efforts to inject competition into its electric industry but acknowledged its 2018 presidential campaign is bringing fears of uncertainty.
Kicking off the Gulf Coast Power Association’s second annual summit on the Mexican market, Jeff Pavlovic, managing director of electric industry coordination for Mexico’s Ministry of Energy (SENER), briefed his audience on the country’s fledgling energy market.
In a matter of years, he said, Mexico has begun a short-term energy and ancillary services market, a capacity balancing market, long-term auctions for energy, capacity and clean-energy certificates, and bilateral transactions. Medium-term auctions are scheduled to be conducted in October and a financial transmission rights auction in November, with the clean energy certificate market beginning next year.
“The fact that we’re getting a bilateral market up and running is a big deal,” Pavlovic said. “We don’t want to centralize decisions … so the development of a bilateral contract market is important.”
He said the FTR manual is up for final approval and will soon be published for all market participants. One change participants will see is in credit requirements, which were previously published at 250 pesos/MWh (about $13.29).
“We heard loud and clear that that was too high and would scare away all participation,” Pavlovic said. “We need to get smarter in the new manual and with a new scheme. Each FTR will be valued on expected value and its variability.”
He took a minute to brag about the volume and diversity of the market’s first two long-term auctions, which resulted in approximately $6.6 billion of total investment. Pavlovic said the auctions acquired solar and wind capacity equal to 171% of the previous 18 years’ additions. In the meantime, SENER continues to transition responsibility for the market to Mexico’s Energy Regulatory Commission (CRE).
“The ministry will eventually hand over the keys to the car to the CRE,” he said. “We tried to move the most volatile rulemakings out of the ministry to the more stable place, which is the CRE. We’ll do it for the next several months because we can do it more quickly, but we will move that to CRE by the end of the year.”
CRE Commissioner Guillermo Zuñiga | Guillermo
It wasn’t that long ago that the Comisión Federal de Electricidad (CFE), the state-owned electric monopoly, dominated every aspect of the market. There are still issues to be worked out, CRE Commissioner Guillermo Zuñiga said.
“One of the main issues is the Tariff,” he said. “We’re working on the costs of the [CFE] legacy plants … and their allocated costs. Subsidies may come later.
“Before reform, subsidies were embedded in CFE’s financial statements. You couldn’t tell the size of the requirements’ subsidies, because it was in the belly of the monopoly. We want transparent subsidies.”
Explaining the Benefits of Market Participation
CFE Calificados, the former monopoly’s qualified supplier, in November completed the market’s first hedge contract with Frontera Mexico Generacion, a subsidiary of power generator Fisterra Energy. It didn’t come easy, resulting from months of work and meetings throughout the country.
“We try to educate and explain to the final customer,” said CFE Calificados CEO Katya Somohano, who has helped complete several power purchase agreements. “One of the lessons is to move from fixed contracts to where the customer benefits from a change in gas prices. We’ve been very keen showing that and telling customers how it works.
“We spent about two years going around the country. We spent three to four hours explaining the market and the risks. One of the lessons is to move from fixed contracts to where the customer benefits from a change in gas prices. Experience is something very important. If they make the move, they’ll be in the market for three years, by law. We explain that. The Tariff is at such an [advanced] level that some, not all, customers will be in a better position in the market.”
“Four or five years ago, I would have called the market very regulated with not a lot of opportunities,” said Juan Guichard, director of competitive qualified supplier Ammper Energia. “We have come a long way in a brief amount of time. I see it as an execution of what has been designed. To be here in Houston, talking about the Mexican energy market, is proof of that.”
Political Uncertainty Cast Cloud over Market
During the GCPA’s first summit on the Mexican Market last year in Mexico City, Nick Panes, a senior partner with local consulting firm Control Risks, made predictions about the U.S. presidential election. Like many pundits, he was wrong.
“We’re living with the political reality of certain events that happened last November,” he said, apologetically. “We’re living in a global, bilateral political reality. The key issue for us has always been that planning and careful consideration of the issues one is going to face will help avoid unnecessary delays.”
Panes said the key issues to market success have not changed: legal and regulated risk, community relations, human resources and capital, the rule of law and transparency, and — especially in northern Mexico — security.
“For many years — perhaps justifiably, perhaps not — security has dominated the headlines around Mexico,” he said. “Our line, as last year, is that it does not represent an insurmountable obstacle to investing and operating in Mexico. It is going to be a critical political issue going forward. In certain parts of the country, [security] has deteriorated, and it is likely not to improve going forward into 2018” when Mexico holds its national elections.
Adrian Katzew, CEO of clean-energy developer Zuma Energía, said next year’s election is already creating challenges.
“Those of us with intermittent resources may have to buy certificates in some years because the wind is not blowing,” he said. “We need the system to be healthy. To be healthy, the projects need to become reality. We need certainty. One of my concerns is some of these not be able to mature. [Competitors] will point to the industry and say, ‘See, prices are too cheap. Clean energy can’t be this cheap.’”
WESTBOROUGH, Mass. — Although the Marcellus Shale is currently producing about 19 Bcfd of natural gas, it remains a challenge to get that gas to New England, Tom Kiley, CEO of the Northeast Gas Association, told the ISO-NE Planning Advisory Committee on Wednesday.
“What we’re seeing now is that while projects have FERC approval, they are being denied permits by state agencies,” said Kiley, whose group represents gas distribution and transmission companies, and LNG importers.
“Projects are often being delayed one or more years — even with federal permits in hand, even with contract commitments,” Kiley said in a presentation.
Kiley cited National Fuel Gas’ response to the New York State Department of Environmental Conservation’s April 7 decision to deny water quality permits for its Northern Access pipeline. “National Fuel made a very strong statement, so we’re hoping that this pushback will lessen the resistance to new pipelines,” Kiley said. “Something has to give.”
In the statement, CEO Ronald J. Tanski said any impact of the pipeline construction on water quality would be “temporary and minor.”
“These construction activities would certainly have less effect than either exploding an entire bridge structure and dropping it into Cattaraugus Creek (Route 219) or developing and continuously operating a massive construction zone in the middle of the Hudson River (Tappan Zee Bridge) for a minimum of five years, both NYSDEC-approved projects,” Tanksi continued.
He said the state is attempting to create “a new standard that cannot possibly be met by any infrastructure project in the state that crosses streams or wetlands, whether it is a road, bridge, water or an energy infrastructure project.”
ISO-NE Embeds Behind-the-Meter PV in Load Forecasting
ISO-NE planners will capture about three-quarters of the region’s behind-the-meter solar PV in their 2017 capacity, energy, loads and transmission (CELT) load forecast, Manager of Load Forecasting Jon Black said.
The RTO began forecasting BTM PV in 2014 in response to concerns that its rapid growth would not be captured within the long-term load forecast, which relies on historical load trends. The RTO has contracted with Quantitative Business Analytics for PV production data at five-minute intervals from more than 9,000 installations in New England.
“We’re taking a lesson from Germany, where they don’t have telemetrics on every source, but a representational subset,” Black said during an update on the RTO’s efforts.
Black said that RTO staff used the last five years of data. “Before 2012, PV was insignificant, just background noise,” he explained. He used the same term — “noise” — to describe the scale of storage of PV-generated energy today and explain why the grid operator does not yet have projections for storage growth or its potential load impact.
For forecast year 2017, the CELT’s net load projections includes 479 MW of “embedded” PV, which represents 83% of the PV indicated by the forecast for the year. The RTO predicts that the embedded PV — 1.6% of load for 2017 — will rise to nearly 3% of load by 2026.
“Some people think we’re just subtracting something off the load forecast, but separate component forecasting requires reconstituting the element to have an accurate PV reading on net load data,” Black said.
He also said separately forecasting and accounting for BTM PV as the RTO is doing will provide protection against the risk of under-forecasting load if the timing of the summer peak shifts later in the day as PV output diminishes, or if growth in BTM PV slows down from its recent pace.
Eversource to Build Control House at Mount Tom
Eversource Energy and ISO-NE told the PAC they support a $7.7 million project to keep the Mount Tom switchyard and build a control house.
Eversource’s Carl Benker gave a presentation on the plan, a response to Dynegy’s announcement that it will retire its 146-MW coal-fired Mount Tom Generating Station on June 1, 2018, and demolish the facility.
Because the three 115-kV transmission lines to which the plant is connected (line 1039 to Midway, 1447 to Pineshed and 1428 to Fairmont) will remain in service, the protective relays, controls and a DC control power source located within the plant must be relocated.
A previously recommended solution that would reconfigure the three 115-kV lines would be less than half the cost at an estimated $3.7 million, but ISO-NE and Eversource no longer support it because it would expose Pineshed to an additional N-1 contingency that would result in disconnecting all of the line’s load.
ISO-NE and Eversource also considered and rejected three other options ranging from $9 million to $10.1 million.
ISO-NE Post-Winter Review: Uneventful
The RTO’s resource adequacy engineer, Mark Babula, said system operations over the winter months were “relatively uneventful,” but he advised the PAC that fuel security will be an issue in future, as will pending generation retirements.
The Winter Reliability Program was instrumental in augmenting liquid fuel security for the region.
Eighty-four generating units participated in the program to procure back-up oil supplies, burning 114,000 barrels and leaving more than 3 million barrels left in inventory eligible for compensation at a cost of $31.2 million (at $10.21/barrel).
Six assets provided 23 MW of interruption capability through the demand response program at a cost of $70,500. The RTO dispatched the assets once, between 6:39 and 8 a.m. on Jan. 10.
Two generators participated in the LNG program, which will cost $291,000 (171,000 MMBtu at $1.70/MMBtu).
Asked why LNG deliveries to New England pipelines showed such a sharp decline from last winter, especially in January, Babula had a one-word answer: economics.
| ISO-NE
“We … didn’t see gas go above eight bucks this winter,” he said. “Henry Hub has been like $3. Pipeline gas is always cheaper than LNG.”
According to FERC’s 2016 State of the Markets report, Algonquin Citygate prices averaged $3.10/MMBtu for all of 2016, a 35% reduction from 2015. Henry Hub prices averaged $2.48/MMBtu, down 5%, while Transco Zone 6-NY dropped 42% to $2.19/MMBtu. (See FERC: Gas Continued to Dominate in 2016.)
Next winter will be the last for the reliability program, which will be replaced in June 2018 with the Pay-for-Performance market design. The new design will increase penalties for generators that fall short of capacity commitments and provide bonuses for those that overperform.
Babula said that the 15 to 20 critical notices or operational flow orders issued by natural gas pipelines this winter — all related to extreme weather — were typical for winter. There also were six unplanned pipeline outages, all related to compressor station outages.
The region benefited from expanded gas capacity as Spectra Energy put the final piece of its 342,000 Dth/d Algonquin Incremental Market project into service on Jan. 7. Tennessee Gas Pipeline’s Connecticut Expansion project (72,000 Dth/d) was delayed until 2018, however.
| ISO-NE
On March 27, FERC gave Algonquin Transmission permission to begin construction on the Connecticut portion of its Atlantic Bridge gas project connecting points in New Jersey and New York with New England and Canada’s Maritime provinces (CP16-9). The commission granted a certificate of public convenience and necessity for the project in January. (See Atlantic Bridge Project Approved by FERC.)
SPP’s Regional State Committee last week approved doubling the timeframe for conducting regional cost allocation reviews (RCARs), leaving only approval from the Board of Directors this week before the change becomes official.
Staff had been conducting RCARs every three years. With board approval of the recommendation and accompanying revision request (TRR-223), those reviews will now be conducted every six years.
The Market and Operations Policy Committee earlier approved the same recommendation from the Regional Allocation Review Task Force, which said the change would save SPP manpower and consulting costs. (See “Cost Allocation Review Cycle Could Extend to 6 Years,” SPP Markets and Operations Policy Committee Briefs.)
The most recent review, RCAR II, showed more positive benefit-to-cost ratios and only one deficient transmission zone, which already has a project in the 2017 Integrated Transmission Planning assessment. SPP said it took about 2,100 staff hours and more than $417,000 in payments to outside consultants to complete the review. The first RCAR incurred a similar expense.
“It’s a really elegant solution, because it takes a tremendous amount of staff’s time,” said Donna Nelson, chair of the Public Utility Commission of Texas. “It’s a heavy lift. All of the commissioners here have been very respectful of each other, with respect to the cost-benefit analysis.”
South Dakota Public Utilities Commissioner Kristie Fiegen isn’t so sure. “I believe we could be locking in winners or losers for an extended period of time,” she said. “It concerns me we’re moving the cost allocation review out six years, but I certainly appreciate the group looking at the cost of the study. The cost-benefit ratio is extremely important to our stakeholders.”
Feigen | kristiefiegen.com
Patrick Lyons, chair of the New Mexico Public Regulation Commission, advocated for a four-year delay between reviews, but none of the other committee members backed his proposal.
Staff pointed out that any member that feels it has an imbalanced cost allocation can request relief through the MOPC. It also said it was trying to improve the review process through the use of more accurate information.
“One thing staff is doing now is using real market data and running the market [model] without that transmission, then going back to Day 1 of the market to find the value of the transmission,” SPP General Counsel Paul Suskie said. “We’re looking at possible different ways to do the RCAR.”
Golden Spread Electric Cooperative’s Mike Wise told the committee that his Export Pricing Task Force did not have a “whole lot of solutions” for shipping SPP’s ample wind resources out of the footprint.
“We’re waiting on members and staff to bring ideas,” said Wise, who chairs the group and the Strategic Planning Committee. “There’s no stomach inside the task force or the SPC, that I’ve heard, that we want to build transmission to export wind and have the consumers in the footprint pay for it. I would encourage anyone who wants to come get the wind to build the transmission.”
The group has prioritized several market changes — such as ramp products and storage resources — to accommodate wind exports as staff time and dollars are available over the next few years. Wise said the group would continue meeting over the next few months as “opportunities” are brought forward.
SPP has more than 16 GW of installed and operational wind capacity, another 8 GW with signed generation interconnection agreements and a potential 43 GW overall.
The task force has begun to explore coordinated transaction scheduling, which allows for near real-time scheduling of power across RTO interfaces, based on the price spread between RTOs. (PJM has adopted CTS with NYISO and plans to launch with MISO this fall.)
“We really have to work with the other RTOs,” Wise said. “It’s not MISO that needs the power, it’s the other RTOs east of MISO.”
Committee Approves CAWG Recommendations
The RSC also approved several motions from the Cost Allocation Working Group, which reports up to the committee. The items were also approved by the MOPC earlier this month.
A recommendation to approve the Seams Projects Policy Paper as consistent with previous RSC actions. The paper sets guidelines for SPP approval and cost allocation processes for non-FERC Order 1000 interregional transmission projects on a project-by-project basis.
Another recommendation to approve regional funding for SPP’s portion of a transformer project and line uprate at an Associated Electric Cooperative Inc. substation near Springfield, Mo.
Approval of RTWG-RR208, which implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission expansion plan, creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program.
Finding MRR203 consistent with respect to the allocation of financial transmission rights. The revision adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-to-sink path can be nominated.
Finding RR202 also consistent with the RSC’s past policy decisions with in allocating FTRs. The change complies with FERC guidance on SPP’s disparate treatment of point-to-point and network integration transmission service (NITS) during re-dispatch. NITS would be eligible for ARR during limited times of the year and only for the service not subject to redispatch, but not for long-term congestion rights. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)
CARMEL, Ind. — MISO last week presented a strawman proposal for non-transmission alternatives that includes redispatch, load shed, reconfiguration and remedial action schemes.
The Planning Advisory Committee is currently working on Business Practices Manual 020, which outlines the process for considering non-transmission alternatives. (See “Rules on Non-Transmission Alternatives Ready for PAC Review,” MISO Planning Subcommittee Briefs.)
At the April 18 Planning Subcommittee meeting, MISO officials provided details of the alternatives:
The generation redispatch option would require an evaluation to “demonstrate that there are sufficient generation units that are available to provide the incremental capacity necessary to maintain loadings and voltages within applicable [ratings], without reliance on any single unit,” MISO proposed. The RTO said no more than 10 individual units or 1,000 MW will be used in any redispatch plan. Candidates for redispatch include all network resources and energy resources, and participating generators must have a distribution factor of greater than 3%. Before using a redispatch plan that requires decommitting a resource, the RTO said it will evaluate reliability and voltage without the unit. MISO will also exclude non-dispatchable units and nuclear generation from possible redispatch solutions.
Load shed will be allowed when local planning criteria permits, MISO said. The RTO committed to flagging constraints that result in load shed of 1,000 MW or more for potential physical upgrades.
System reconfiguration will be allowed as a corrective plan, MISO said, unless reconfiguration places noninterruptible load on a transmission radial “such that a single contingency would interrupt service to multiple customers, the reconfiguration results in opening of more than a single transmission line or the reconfiguration results in transmission flows to be routed through sub-transmission or distribution facilities.”
“All three of these come from current, real-time operating procedure,” engineer Patrick Jehring said.
Remedial action schemes will use language pulled directly from NERC, with existing schemes allowed as acceptable corrective action plans. New schemes will be evaluated on a case-by-case basis. The evaluation will include expected frequency of need for a RAS and comparison of costs to install and maintain it compared to the cost of a transmission upgrade. “Remedial actions schemes must be far cheaper than a new line,” Jehring said.
Jehring also said most of the strawman was borrowed from existing MISO standards, but that the RTO still wants stakeholder suggestions. He asked for written feedback by May 5.
“How much risk to the load-serving capability is acceptable on the planning horizon?” Jehring asked stakeholders.
In response, they expressed concerns in particular on load shedding as a non-transmission alternative option.
Consultant Roberto Paliza of Indianapolis said MISO should be transparent when it identifies specific solutions. Paliza added that too much load shed to resolve contingencies can cause a concern and could make transmission construction more appealing. Planning Subcommittee liaison Jeff Webb agreed. “If the solution is load shed, we should be explaining why that is acceptable,” Webb said.
NRG Energy’s Tia Elliott asked if MISO could gather all transmission owners’ individual load shed criteria and consolidate it into a single document. “It varies across the footprint from transmission owner to transmission owner,” she said. “Not understanding what those variables are makes it difficult for stakeholders to make an informed decision.”
Jehring said MISO already posts such planning criteria, though not consolidated, on its website.
MISO Unveils MTEP 17 Transfer Analysis
As part of its 2017 Transmission Expansion Plan, MISO outlined a proposed analysis on a half-dozen MISO transfers.
| MISO
This year, MISO is proposing to study transfers between MISO North and SPP; two transfers from Manitoba Hydro to MISO North; wind resources in Northern Illinois to Ohio (both PJM territories) using MISO transmission in Indiana; MISO North and Central to MISO East; MISO Central to the Tennessee Valley Authority; and MISO South to SPP.
Scott Goodwin, MISO transfer analysis engineer, asked for stakeholders to review the transfer selection.
This year, MTEP studies include the usual base reliability and economic studies along with a trio of specialized studies: the multiyear regional transmission overlay study, a generation retirement study and the footprint diversity study, which could identify an alternative to using SPP transmission for transfers between MISO North and MISO South. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs; “Generators Identified in MISO Retirement Analysis,” MISO Planning Subcommittee Briefs.)
WESTBOROUGH, Mass. — A new analysis by ISO-NE shows that increasing carbon allowance prices from $24/short ton to $64/short ton would boost the region’s LMPs by more than 30% under all six scenarios studied.
The RTO added the new sensitivity in response to stakeholders who said the $24/short ton (2015 $) allowance price used in an earlier version of the 2016 Economic Study was too low to drive the investments needed to meet greenhouse gas reduction goals. The $64 figure is based on the federal government’s estimated social cost of carbon.
Michael Henderson, ISO-NE director of regional planning and coordination, presented the results of the revised study to the Planning Advisory Committee on April 19.
The Regional Greenhouse Gas Initiative emissions cap — 91 million short tons in 2014 — is set to drop by 2.5% annually through 2020. Some activists have called on RGGI to double the cuts to 5% per year. Most of the six scenarios studied failed to meet those targets.
| ISO-NE
Dan Pierpont, manager of external affairs for CPV Towantic, asked about the “pricing effects of RGGI goal-busting performance,” while an unidentified woman participant on the phone said she wanted “RGGI-threatening scenarios clearly delineated in the executive summary for state policymakers.”
New Names for Numbered Scenarios
In place of the six numbered scenarios in the earlier draft study, Henderson said, “we’ve given nicknames to the scenarios so they’ll be intuitively obvious.” The new names are:
RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas (combined cycle units). It fails to meet the RGGI targets regardless of whether transmission constraints are modeled or not.
ISO Queue: Physically meet RPS and replace generator retirements with new renewable/clean energy. It meets the 5% RGGI reduction only in the transmission-unconstrained model and then only using the $64/ton carbon adder.
Renewables Plus: Physically meet RPS; add renewable/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage; and retire old generating units. It meets the RGGI targets under all sensitivities.
No Retirements (beyond Forward Capacity Auction 10): Meet RPS with resources under development and use RPS alternative compliance payments (ACPs) for shortfalls; add natural gas units. It fails to meet the RGGI targets under all sensitivities. It shows the highest LMPs assuming a $64/ton carbon price, averaging $69.70/MWh including transmission constraints.
Gas + ACPs: Meet RPS with resources under development and use ACP, and replace retirements with natural gas. It does not meet the RGGI targets under any sensitivity. It shows the highest LMPs under a $24/ton sensitivity, at $52.63 (transmission constrained).
RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV. It meets the RGGI targets under the $64/ton sensitivity but fails under the $24/ton transmission-constrained model. It had the lowest LMPs of all six scenarios under all sensitivities, averaging $34.12/MWh ($24/ton) and $44.21/MWh ($64/ton) with transmission constraints modeled.
“Clearly, scenarios with the heavier renewable elements, scenarios 3, 6 and 2, show the lowest CO2 emissions,” Henderson said. “As far as load-serving entities go, there is no change in the scenario order: The least expensive remains least, and the most expensive remains most.”
Scenario 2 shows the biggest decrease in LMPs when transmission constraints are relieved, a difference of almost $22/MWh assuming $64/ton carbon.
LMPs for scenarios 4 and 5 show virtually no change with the transmission constraints modeled because they have little congestion, Henderson said.
25-MW Threshold
| RGGI
Henderson noted that the study applies carbon allowance prices to all generating units in New England — including those below the 25-MW threshold employed by RGGI.
Ignoring the carbon prices for smaller units could actually increase emissions, Henderson said, because high emitting small units, such as biomass, would be dispatched more often.
“The new methodology is important, for when you raise carbon prices — if you do nothing to affect the resource dispatch order — you have no effect on emissions,” Henderson said. “As the resource mix changes and you end up with a greater amount of zero-emission resources, overall emissions decrease.”
The completed study is “on track” for publication in the second quarter, and a natural gas analysis will be announced at the May or June PAC, he said.
Study of Other Options Requested
David Ismay, senior attorney for the Conservation Law Foundation, gave a presentation asking the RTO to develop and price at least two new scenarios for generation and transmission that could reduce emissions to or below the levels of Scenario 3 at a lower cost.
“By developing a range of least-cost options for such public policy-compliant futures, the result of a Least-Cost, Emissions-Compliant System Topologies Study could be used to test the ability of market reforms to deliver the desired results of the market-policy integration that is the goal of both the on-going [New England Power Pool] Integrating Markets and Public Policy (IMAPP) effort as well as FERC’s recently opened Docket No. AD17-11,” Ismay said in a letter to Henderson.
Henderson replied that the RTO “requires specificity in any suggested economic study and will not invent a new system.”
Doug Hurley of Synapse Energy Economics offered to help Ismay and the CLF develop the right metrics for their request. Other participants spoke up to support Ismay’s use of the PAC forum to address his and the foundation’s concerns.
CAISO is curtailing an increasing volume of renewable generation this spring as the ISO sees its “duck curve” already dipping to levels not forecast to occur until 2021.
Compounding the issue is an unusually high snowpack coming after years of drought that had previously undercut California’s hydroelectric output, making more room for solar.
Recent events have put CAISO “net load” effectively off the original “Duck Curve” chart, with load served by dispatchable resources falling to levels not forecast to occur until 2021. | CAISO
“Everything’s kind of playing out the way we had expected, maybe just a little bit faster,” Mark Rothleder, the ISO’s vice president for market quality and renewable integration, said during an April 19 meeting of the Energy Imbalance Market (EIM) Governing Body.
All-Time Low
“We’ve seen net load levels of 10,386 MW” — an all-time low, Rothleder said. “This is about four years ahead of the schedule of where we expected to be” when the ISO first introduced the duck curve in 2013.
“Net load” represents system load minus the combined output from utility-scale wind and solar resources. The ISO cares about those three components because they all represent variable factors, Rothleder explained. Where system operators once had to track and balance only load, they must now deploy dispatchable resources to balance whatever portion of the load is not being served by renewables.
The all-time-low net load figure cited by Rothleder occurred on April 9. It was also off the charts of the original graph, which only forecasted out to 2021 (see graph).
“When we put the duck out a few years ago, we probably didn’t factor in the effects of behind-the-meter solar as much as we’re actually seeing play out,” Rothleder said.
CAISO estimates that its balancing authority area contains about 5,000 MW of rooftop solar capacity, which reduces system load during daylight hours.
Rothleder pointed out that the duck curve is also intended to illustrate the sharp daily ramps needed from dispatchable resources as solar output starts to wane as residential load ticks upward in the evening. In December, the ISO observed a 13,000-MW three-hour ramp about four years ahead of expectations.
Deeper, Longer, Steeper
“Looking forward, we should continue to expect that the belly of the duck is going to get deeper and that the evening ramps will get longer and steeper as well,” Rothleder said.
At about 11,000 MW of net load, the ISO has “to start stacking up what other supply is already on the system that you can’t move,” Rothleder explained. In California, that means about 2,000 MW of nuclear, 1,000 MW of qualifying facilities under the Public Utility Regulatory Policies Act and — “in a good year” — around 6,000 MW of hydroelectric output.
With snowpack levels in the Sierra Nevada mountains currently at about 180% of normal, and California’s drought officially declared over, this is a very good year for hydro.
In leaner times, the steady growth of California’s solar capacity conveniently substituted for the decline in hydro, Rothleder said. Now the two must compete, with hydro curtailments limited by flood control needs and environmental restrictions on spilling water over dams.
“You’re now getting into a condition where you have an excess amount of energy and you have to do something with it,” Rothleder said.
One key response has been exporting to neighboring BAAs through the EIM, which last month helped the ISO avoid more than 100 GWh of renewable curtailments.
“And if we run out of that ability, we effectively get to the point where we have to curtail, whether it be economic curtailment through bids on the wind and solar resources to dispatch down, or manual curtailment because we ran out of bids,” he said.
80 GWh Curtailed in March
CAISO curtailed about 80 GWh of renewable generation in March, nearly double the curtailments during the same month last year. So far this year, curtailments have occurred in 31% of all five-minute dispatch intervals, compared with 21% last year and 16% in 2015, the ISO estimates.
Graph indicates how the EIM has helped CAISO avoid renewable curtailments this year, although avoided curtailments are down from previous years. | CAISO
EIM Governing Body member Valerie Fong asked how the curtailments were allocated across the ISO’s market.
“It’s not an allocation,” Rothleder replied. Rather, resources are curtailed based on what price they offer into the market. Renewable resources frequently bid in at negative prices because of other compensation derived from renewable energy certificates and tax credits.
“The one that’s bidding -$15 will be dispatched down first before [a resource bidding] -$30,” Rothleder said.
Is Storage an Answer?
Body Chair Kristine Schmidt asked whether there were any developments related to energy storage that could help reduce curtailments.
Rothleder said “the proposition of storage is an ongoing question” in which CAISO market participants must determine when curtailments reach a level that warrants investment in “higher-cost” storage solutions.
“When does that threshold get crossed? I don’t think we’re there at the current levels” of curtailments, Rothleder said.
Sara Edmonds, general counsel with PacifiCorp Transmission, pointed out that the ISO’s own numbers show that curtailment avoidance through the EIM this year is lower than last (see graph).
“I’m still trying to understand that myself,” Rothleder said. “There could be various reasons.”
One potential reason is that supply conditions across the West are different from previous years, with snowpack high in other regions as well.
A second possibility: EIM participants could be changing the way they deploy resources, reducing the potential for downward dispatch in their own balancing areas.
A third: The inclusion of Arizona Public Service and Puget Sound Energy in the EIM last October could be altering the dynamic of the market.
“So I don’t have the full explanation,” Rothleder said. “I think we’ll see how things continue to play out over the rest of the spring and summer — and especially with other hydro conditions throughout the West.”
