The D.C. Circuit Court of Appeals on Tuesday declined to overturn a FERC decision requiring Portland General Electric to purchase the full output of an Oregon wind power project under the Public Utilities Regulatory Policies Act.
The three-judge panel also rejected a claim by PáTu Wind Farm that PGE was required to accept the wind producer’s power through dynamic scheduling.
The court dismissed the utility’s petition for lack of jurisdiction and denied PáTu’s argument on its merits.
Pa’Tu Wind Farm Construction | PaTu / White Construction Company
The case centered on a 2015 FERC ruling in which the commission determined that PGE must purchase all of the six-turbine, 9-MW wind farm’s power under a power purchase agreement between the two parties set out under PURPA.
Because PáTu, located in rural Oregon, is not directly linked to PGE’s grid, it sells power to the utility under the state Public Utility Commission’s approved PPA for “off-system” generators.
In order to transmit power to PGE’s grid, PáTu obtains transmission services from the Wasco Electric Cooperative and the Bonneville Power Administration. Wasco wheels PáTu’s power to BPA, which in turn transmits the energy to PGE’s Troutdale substation, the PPA’s designated point of delivery.
“Before the ink had dried on the power purchase agreement, the parties locked in a dispute over the nature of Portland’s purchase obligation,” the court said.
Believing it had purchased a firm product, PGE required PáTu to set day-ahead schedules under which the wind farm committed to delivering whole blocks of energy for each hour of the day. If PáTu overscheduled its deliveries, PGE paid the favorable avoided cost rates for the power delivered and required the wind farm to make up the difference by buying firm power from BPA, which was compensated at the lower market rate because it was not generated by PáTu.
On the other hand, if PáTu underscheduled, PGE only accepted and paid for only scheduled deliveries, forcing the wind farm to dispose of the excess at less-favorable rates, the D.C. Circuit noted.
PáTu contended that PGE could only buy all of its variable output through “dynamic transfer” — or scheduling in real time. PGE countered that, under its PURPA agreement, the wind farm was a customer of the utility’s merchant arm, not a transmission customer, and was therefore ineligible for dynamic scheduling.
In December 2011, PáTu filed a complaint with the PUC. The regulator saw nothing in the PPA requiring PGE to utilize dynamic scheduling, concluding that the utility must purchase all power PáTu generates and delivers.
But drawing a distinction between power “produced” and power “delivered,” the PUC appeared to leave PGE free to refuse to purchase any power produced in excess of what PáTu scheduled.
PáTu appealed to the Oregon Court of Appeals, which affirmed the PUC’s decision without opinion. The wind farm owner then filed a complaint with FERC, arguing that PGE must buy all of its output, scheduled or not, and that dynamic scheduling was the only way to accomplish that result.
FERC concluded that the PPA and PURPA regulations required PGE “to accept PáTu’s entire net output … delivered to Portland,” the D.C. Circuit noted.
FERC rejected PáTu’s specific request for dynamic scheduling, explaining that it has never required a utility to use any particular method to carry out its purchase obligation. It nonetheless clarified that, contrary to what the PUC had suggested, PGE could not escape its PURPA obligation by imposing overly rigid scheduling requirements or by refusing to purchase all power that PáTu produces.
CAISO management is considering whether to approve two low-cost transmission upgrade projects using an accelerated procedure that bypasses the usual stakeholder process and the Board of Governors.
One project would entail landscaping changes needed to accommodate an uprate on the Pacific DC Intertie, Southern California’s direct link with hydroelectric generation coming out of the Pacific Northwest.
The other would employ cutting-edge technology to avert the temporary threat of summertime overloading on key transmission lines serving the San Diego area.
CAISO bylaws allow for ISO management to approve projects with capital costs less than $50 million on an expedited basis under conditions in which there is an “urgent” need for the project, coupled with a “high degree of certainty” those projects won’t conflict with other solutions being considered in the normal transmission planning process.
Another requirement is the accelerated timeline must be “driven by the ISO’s evaluation process or external circumstances,” according to CAISO. The process also comes with some obligations on the part of management, including requirements to allow stakeholders to review and comment on the project, followed by a briefing of the board.
The two projects under consideration could receive approval early next month, the ISO said.
External developments are driving the need for the proposed Pacific DC Intertie project, requested by Southern California Edison in response to upgrades performed by the Bonneville Power Administration at the line’s northern terminus at Celilo Station, near The Dalles Dam in Oregon.
BPA’s improvements have increased the line’s north-to-south transfer capability from 3,100 MW to 3,220 MW. To capture its estimated 60 MW share of the uprate, SoCalEd must pay for its portion of the costs to grade and recontour the land under the southern end of the line, which it owns jointly with the Los Angeles Department of Water and Power (LADWP).
Total costs are expected to come in at less than $1 million. CAISO considers the nudge in capacity to be “extremely cost effective” for SoCalEd — estimated at less than $10/kW.
“We do think it would be a waste not to capture the incremental benefits,” Neil Millar, the ISO’s executive director of infrastructure development, said during an April 25 call to discuss the projects.
“Barring new information to the contrary, the ISO is interested in moving forward with approval” of the intertie project, CAISO has said. SoCalEd expects LADWP to complete the grading work in October.
The proposed San Diego area project is more technologically complex.
San Diego Gas & Electric is seeking to deploy advanced power flow devices on area transmission lines in order to reduce the utility’s local capacity requirements during the summer of 2018.
The utility is concerned that completion of the Sycamore-Penasquitos 230-kV transmission project — recently pushed back from early to late June 2018 — could meet with further delays. That would increase the risk next summer of overloading the Mission-Old Town 230-kV circuit — a pair of lines serving a populous load pocket in the city — under circumstances in which peak loads shift dramatically because of variability in behind-the-meter solar output. CAISO estimates that it could be forced to shed as much as 370 MW of load within 30 minutes of a line outage.
The risk is, in part, being precipitated by the retirement of the 950-MW natural gas-fired Encina power, which could be given an extended life to help mitigate the potential overload problem until the Sycamore-Penasquitos line is energized.
John Jontry, manager of Electric Transmission Grid Planning at SDG&E, noted that keeping Encina’s capacity in reserve would be a costly solution.
“The less generation we have to procure, the less we have to pay,” Jontry said.
The utility is instead proposing using a combination of a portion of Encina generation complemented by power flow control devices installed on the Mission-Old Town line that would, in an emergency, create up to 5 ohms of impedance on the line, forcing flows into other parts of the system.
“The devices push power away from the line to which they are connected,” said Andee McCoy, an executive with Smart Wires, the company that manufactures the equipment.
McCoy added that the “breadth” of the deployment could be correlated with the amount of Encina generation expected to be online next year.
Depending on the number deployed, estimated costs run from $6 million to $12 million, compared with $8 million to $10 million for a phase-shifting transformer and $20 million to $30 million to reconducutor the lines for what is effectively a temporary issue for the utility.
Jontry also lauded the fact that a “big chunk” of the capital costs are covering devices that could be redeployed to other areas when they’re no longer needed for the Mission-Old Town line.
“We’re kind of breaking new ground here because it’s a new way of looking at utility infrastructure,” Jontry said.
CAISO will present the proposed upgrades during the board’s May 1 meeting and will take stakeholder comments until May 2.
WILMINGTON, Del. — What’s a megawatt really worth?
That question is at the base of the current debate about PJM’s capacity market construct, which last week shifted to whether there is a willingness to consider moving away from centralized markets.
At Friday’s meeting of the Capacity Construct/Public Policy Senior Task Force, the coalition of cooperatives and municipal power authorities that initiated the task force’s creation presented an alternative perspective on the objectives of a resource adequacy construct.
The task force was approved in January after the coalition pushed for months to revisit PJM’s controversial Capacity Performance construct. It began meeting in March. (See PJM Capacity Task Force Considering 60+ ‘Design Concepts’.)
Is the Market the Problem?
Navigant economist Cliff Hamal, representing American Municipal Power, offered a critique of a presentation that PJM’s economist Hung-po Chao gave at the task force’s first meeting in March. Hamal argued that PJM’s centralized capacity market is itself the problem.
“My goal was to try to ask the question whether the objective of this task force [should be] to maintain … what I believe to be an imperfect, problematic centralized auction and deal with state actions, or consider much broader options that have the potential to do it cleaner,” he said.
He argued that the task force’s objectives should allow consideration of market options based on long-term bilateral contracts that attract least-cost financing and have the potential to provide adequate supplies at a lower cost.
Other stakeholders questioned Hamal’s perspective, saying that eliminating the market would reduce variety and the ability to accurately price various options, potentially harming market participants.
“The buyer that enters into the long-term contract now has a liability that the rating agencies insist get shown on their books, such that by entering into this long-term contract, it increases the amount of debt that the rating agency sees and potentially results in a downgrade of the entity’s debt ratings because it’s incurring more debt,” said a representative of a generation owner that is actively building combined cycle plants. “You’re not looking at the other side of the equation for the buyer in that it increases the rate associated with all of his borrowing, and that’s a huge deterrent.”
Mike Borgatti of Gabel Associates argued the proposal limited the ability to shop for alternatives. He gave an example of buying wind production for $300/MWh when the capacity auction clearing price was $100/MWh.
“The difference there is that I know I could have bought other capacity for $100, but I liked this flavor of capacity better, so I overpaid for it,” he said. “The market has functioned correctly, and the price signal out there informed my transaction. If the price signal doesn’t exist out there, I don’t know if $300’s a good deal or a bad deal.”
Chocolate vs. Vanilla
Borgatti attempted to make the same point with a less esoteric product: ice cream.
“Look, chocolate’s over here; it’s available in the market for $3/gallon. I’m a vanilla guy, so I’m gonna go over here and I’m going to procure vanilla at a premium price because I love vanilla. That transaction is totally legitimate; I did what I wanted to … I love my vanilla. I’m sitting on my couch in my underwear having a great time,” he said. “I think it’s hard to think about a market that doesn’t have any price transparency. … It’s very difficult to know [if another construct would be better] because you got rid of the price that you would benchmark it against.”
“Your position seems to favor long-term contracts as a way to attract cheaper capital, but a potential result could be long-term contracts with cheaper capital but underlying resources that are much higher cost than other resources that would compete down the road,” Direct Energy’s Jeff Whitehead said. “If I take a 20-year position on a power plant that has a certain cost, 10 years from now, there might be another power plant technology available that’s much cheaper, so while I might get a cheaper cost of capital, I might actually get a more expensive overall solution.”
Hamal acknowledged there are tradeoffs, but he emphasized that the task force is establishing objectives at this point, not choosing among alternatives.
The remainder of the meeting attempted to distill some of the 71 objectives proposed for “a well-functioning capacity construct” into categories, but that effort fell apart as stakeholders felt the nuance of certain proposals was being lost. Dave Anders, who is facilitating the task force for PJM, decided to abandon that effort and instead include all of them into a poll to measure stakeholders’ interest in each proposed objective. PJM will be sending the poll out to all stakeholders signed up to receive notifications about the task force.
The task force also worked on developing a list of public policy initiatives states might make and plans to complete it at the next meeting, Anders said. Work will then begin on determining how to balance the state activities against PJM’s current capacity construct.
Jennifer Chen of the Natural Resources Defense Council gave a presentation on subsidies to add context to the public-policies list.
The task force has a target of the end of the year to determine if any changes to the capacity market should be made.
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.)
