SACRAMENTO, Calif. — CAISO’s Board of Governors last week provided insight into a new 2030 energy “vision” for California and the region, one of many discussions at the ISO’s 2017 Stakeholder Symposium.
Governor David Olsen said the “Electricity 2030” paper examines the “the sustained, orderly retirement of gas turbines.” It also discusses the importance of states working together and collaboration among agencies and the public.
CAISO is taking comments on the document, which says a decarbonized, decentralized and more regional electric grid is driving the transition in California. The paper calls for a grid powered by two-thirds non-fossil fuel — and no nuclear — generation by 2030, and lists economic benefits from clean energy jobs and better public health.
But operational dispatch to meet locational capacity needs will be different on a decentralized grid, and “there are engineering challenges along the way” to incorporate the combined capabilities of new resources such as solar and distributed generation, Olsen said.
“It is very important for all of us to take these challenges seriously,” he said, “because nothing will stop movement toward a modernized grid faster than a blackout.”
Challenge and Opportunity
NRG Energy last week took steps to withdraw its application for a new natural gas plant in Ventura County to replace 2,000 MW of generation retiring because of the state’s once-through cooling rules. (See NRG Signals Pull-out on Proposed Puente Plant.) The Ventura/Moorpark load pocket is one example of how locational needs require massive capital investment, as costs for the three distributed energy options to replace the capacity range from $309 million to $1.1 billion.
Governor Angelina Galiteva said the shift to a new type of grid is inevitable and discussed what she called the “financial justice” of the transition. Managing renewable integration “is a challenge, but it is also an opportunity,” she said.
“We tend to agree that moving towards a much more decarbonized grid is where everybody is moving,” Galiteva said. A diversity of resources is important to optimize the system, meaning that interstate cooperation to optimize resources “becomes increasingly important.”
She added that climate change is a global issue, and developing countries will benefit from successful efforts in the U.S. “They can leapfrog technologies; they can build microgrids,” she said.
Governor Mark Ferron called for an “optimistic” attitude toward the emerging technology and new communications and called for a “forward-looking approach.”
“I kind of turn it around and say, ‘What’s the alternative?’” he said. “It is not a long-term winning strategy to try to restrict consumer choice or roll back new technology.” He also mentioned the “sea change” of integrating electric vehicles, which must become a grid asset and not a liability.
Regulators Discuss Regionalization
Montana Public Service Commission Vice Chair Travis Kavulla moderated a panel of state regulators who discussed regional differences and the effort to regionalize the Western electricity grid, which is expected to be resumed by the California State Legislature next January.
“There are a variety of cultural issues these days,” California Public Utilities Commission President Michael Picker said, adding that, aside from political differences in California, “we have a long-standing fear of FERC.” He predicted there will be some flexibility in terms of governance of an RTO.
“We have this enormous advantage of having this great diversity of resources in the West,” Picker said, which makes electricity planning easier than planning in other sectors, such as water rights.
Giving the inland West perspective, Laura Nelson, energy adviser to the Utah Public Service Commission, said: “Regionalization is inevitable, but it is a very, very slow-moving ship.” There are political differences to contend with, she noted.
“In parts of the Rocky Mountain West, we really do have a different view of our resources,” she said, but “Utah has been engaged in those conversations.” Utah has traditionally used a lot of coal for generation but also has natural gas and is on track to increase its renewable penetration to 8%.
Most panelists agreed that the trend toward regionalization will increase with time, with the large and dynamic gathering in Sacramento perhaps representing a step toward that end, if all parties can be brought into sufficient alignment while keeping electricity affordable and reliable.
FERC last week decided a seven-year-old dispute over the cost allocation for three Virginia Electric Power Co. transmission undergrounding projects, ruling the costs should be shared by all VEPCO network integration transmission service customers with loads in the state.
The commission reversed some findings from an administrative law judge’s 2016 initial decision while upholding the remainder (EL10-49-005). The commission also denied requests for rehearing of its March 2014 order that said VEPCO loads outside Virginia could not be allocated the incremental costs of the undergrounding, which was ordered by the state (EL10-49-004).
At issue was whether Old Dominion Electric Cooperative and North Carolina Electric Membership Corp. should be required to pay the additional costs of undergrounding VEPCO’s Pleasant View, DuPont Fabros and Garrisonville projects.
“The cost impact of the state’s actions is stark: Approximately 64% of the collective total costs of the projects — almost $150 million — was incurred to place the lines underground,” the commission said. “Considering the three projects together, placing the lines underground nearly tripled construction costs.”
The commission reversed Administrative Law Judge Michael Haubner’s determination on calculating the costs to be allocated to the two utilities for the projects, ruling that it should only include depreciation, return on capital investment, income taxes, accumulated deferred income taxes and property taxes.
It also reversed the judge’s determination that the methodology used to allocate the underground component of project costs should be used for future capital expenditures that don’t increase the projects’ capacity. FERC affirmed, however, its 2014 ruling on cost allocation, the ALJ’s determination that future capital expenditures that increase the projects’ capacity are beyond the scope of the proceeding and its determination of refunds, which are dated to March 17, 2010.
VEPCO must submit tariff revisions and rebill customers within 30 days, and file a refund report within 60 days.
The commission rejected challenges to its March 2014 order, which concluded that the undergrounding costs could not be collected from out-of-state loads because the additional cost was necessitated by state requirements, not reliability needs. The projects created “systemwide benefits,” so the costs should be allocated among wholesale customers rather than just retail, the commission said.
“The commission is not limited to adopting only a remedy put forward in the complaint or in briefing, as the rehearing applicants allege,” FERC said. “The commission has considerable discretion in fashioning remedies and can base that remedy on the record developed.”
The opening morning panel focused on the future of carbon policy, with several panelists offering a potential future for coal. A later panel focused on the impact of increasing intermittent generation on the grid.
EPA Deputy General Counsel David Fotouhi said Administrator Scott Pruitt has targeted three coal-related environmental rules for reconsideration: the Clean Power Plan; 2015 steam-electric effluent limitations in the Clean Water Act; and the coal-combustion residuals rule in the Resource Conservation and Recovery Act.
“Those three efforts in common share the touchstones of rule of law, cooperative federalism and process, and making sure the process is regular,” Fotouhi said.
Paul Bailey, CEO of the American Coalition for Clean Coal Electricity, said he received no forewarning of the Department of Energy’s Sept. 29 Notice of Proposed Rulemaking calling for price supports for coal and nuclear facilities.
“We didn’t know this was going to happen until we saw it,” he said. “We’re also trying to understand this proposal like many others right now.”
He said his organization, which represents coal-fired generators, doesn’t view it as a bailout.
Marc Chupka of The Brattle Group said domestic coal production would be aided by the CPP repeal and improving mining techniques to reduce costs. However, he warned that inexpensive natural gas “will end up crushing coal.”
“There is very little that [coal-fired] generators can do in the face of $3 gas,” he said.
Benjamin Longstreth, an attorney with the Natural Resources Defense Council, disagreed with Bailey’s description of the DOE NOPR and said there was “an absolute lack of analysis to support the proposal.” He quoted Pruitt’s complaint that EPA was “picking winners and losers” in the CPP.
“I don’t agree with Pruitt’s description of the Clean Power Plan, but I think it aptly describes DOE’s proposal,” Longstreth said. “We view it as a bailout.”
The NOPR argues that retaining coal and nuclear facilities that have 90-day fuel supplies maintains grid reliability, but Longstreth said that only 0.007% of outages are due to fuel shortages.
Andrew McKeon, the executive director of the nine-state Regional Greenhouse Gas Initiative, said the past 200 years of economic prosperity has been “very closely tied” to fossil fuel use, but the two trends must “decouple” to address climate change.
“The fact is it’s a global problem and needs a global answer,” he said.
RGGI is providing one path, he said. The states involved — Delaware, Maryland, New York, Connecticut, Massachusetts, Rhode Island, Vermont, New Hampshire and Maine — have seen a 45% reduction in carbon dioxide emissions from electric generation since 2005.
“We’re doing the job twice as fast as the rest of the country,” he said.
Filling the Breach
All panelists acknowledged federalism and the importance of states making decisions on their own.
“We absolutely believe that states should step into the breach” left by Trump administration policies, Longstreth said.
New York is trying to be one of those states. In a later panel, NYISO’s Robert Pike explained New York’s analysis for implementing carbon pricing. The state is already providing renewable energy credits (RECs) and zero-emissions credits (ZECs) for nuclear facilities. The state commissioned a study by Brattle to determine if NYISO’s market could achieve the same function as its existing administrative solutions.
“It’s about a wash in costs,” Pike said. “The bills stay about the same for consumers because the carbon price would then offset the need for RECs and ZECs.”
Pike said there also are questions about how the DOE proposal would be applied. He noted a coal facility in New York that runs very infrequently.
“What does a 90-day coal pile look like at a unit that runs 1% of the time?” he asked.
Ralph Romero, of infrastructure developer Black & Veatch, said the cost of energy storage “has dropped dramatically” in recent years to between 40 and 50 cents/W depending on location. He said some analysts have predicted that $100/kWh for batteries by 2020 is “not beyond the realm of possibility.”
ICF International’s Kevin Petak joined with others in the natural gas pipeline industry who have said that securing firm pipeline capacity is complicated and not always feasible. He noted that while electricity can move at nearly the speed of light, gas moves about 30 mph, so suppliers require time and planning to ensure gas is physically available.
Pipeline companies have argued that gas-fired generators need to pay for uninterruptible pipeline deliveries if they want to ensure supplies, but Petak said generators aren’t able to recover that cost from customers.
Marketers can bundle capacity with the gas when they make contracts, he said, but “since there is no mechanism to buy the capacity and pass that cost on to the consumer, there has been reservation on the part of generators to reserve capacity.”
CROMWELL, Conn. — In Connecticut, “50 by 50” does not refer to the state’s renewable energy goals by the half-century mark, but to the projected rise in sea level: 50 centimeters by 2050.
Speaking Tuesday at the Connecticut Power & Energy Society’s Future of Energy Conference, Robert Klee, commissioner of the state’s Department of Energy and Environmental Protection (DEEP), pointed out that the Connecticut Institute for Resilience and Climate Adaptation had just briefed his staff the previous day on estimates for localized sea level rise.
“That’s a fundamental change in the way we need to plan for infrastructure along the coast,” Klee said.
But Klee touted the state’s grid-scale clean energy procurements and low- and zero-emission renewable energy credit programs — as well as the work of the Connecticut Green Bank — in helping develop a sustainable energy framework.
“You can’t drive around Connecticut anymore without seeing rooftop solar somewhere, on homes, on businesses — and that’s a real achievement,” Klee said. “And microgrids were kind of a sleeper hit. I go to microgrid conferences, and folks in other states are always amazed that we have six that are operational. Most other states are still [at the stage of] drawing boards or concept.”
Utilities Focus on Customers
Penni McLean-Conner, chief customer officer at Eversource Energy, serves on the Boston Green Ribbon Commission, which gathers business, institutional and civic leaders to seek ways to fight climate change.
She explained that her company built its newest substation in Boston’s Seaport neighborhood 23 feet above sea level, designed to handle 150 mph winds and with 80 pilings that sink into the bedrock below.
“Why? Because we’re right on the water,” she said. “We know the flooding is going to occur as we look at the climate models going out to 2050, so if we’re going to put in an asset that’s going to last another 50 years, we need to be thinking about resiliency.”
But whether adapting to climate change or using new technologies to provide a reliable energy platform, the utility of the future will be dramatically different from today in that it will be grounded in the voice of customers, McLean-Conner said.
UIL Holdings CEO Anthony Marone III agreed, saying utilities need to match offerings to customer wants.
“You can have all the technology in the world, but not every customer wants to pay for it,” Marone said. “We can’t just keep putting more gadgets on the system if there’s not a value proposition that makes sense.”
Mike Calviou, senior vice president for regulation and pricing at National Grid USA, said the utility of the future has to be more agile to meet varied needs, driven by three primary forces: decarbonization, decentralization and digitization.
“On regulatory innovation, we’re absolutely convinced that the traditional, backwards-looking, rate-based regulated utility just really doesn’t make sense in the environment we’re moving into,” Calviou said. He cited electrification of transportation as the most exciting opportunity for utilities.
Need for Market Evolution
On Energy Secretary Rick Perry’s call earlier this month for price supports for coal and nuclear plants, Dean Ellis, Dynegy senior vice president for regulatory affairs, said “I would argue there’s a big difference between a sales tax break upstream or a property tax agreement, and paying someone to produce electricity when it’s not economic to do so.” (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)
Subsidies lead to more subsidies, and while production incentives incent a build-out of a particular resource type, they also affect other resources competing in the market, Ellis said.
“We definitely agreed with the [Department of Energy’s] issue that there needs to be some evolution here with the markets, but the way they went about it was absolutely wrong. It’s a solution looking for a problem,” he said. “If the DOE is going to pay us to keep 90 days of coal on-site, we’ll put coal in the cafeteria if we have to, but that’s not the best way to go about incenting the outcomes. If one of the outcomes is to increase grid reliability, then let’s have a really honest conversation about what a reliable grid looks like in the future.”
Carbon pricing looks better than subsidies to Stephen Molodetz, vice president for business development at Hydro-Québec US.
“We’re one of the few suppliers who thinks the real solution is to price carbon into the market,” Molodetz said. Getting participants in a multistate RTO like ISO-NE to agree on a pricing mechanism “seems to be the Holy Grail,” he added.
“We’re currently working hard [on carbon pricing] in New York, again a one-state ISO … and to be honest there, I still think it’s a longshot,” Molodetz said.
Katie Dykes, chair of Connecticut Public Utilities Regulatory Authority (PURA), asked industry executives what “X factors” they’ve considered in the their company planning.
“If you look at some of the recent history of the emergence of the New England markets, there’s a lot of unexpected surprise factors that have created the landscape, the shale gas revolution being one,” Dykes said. “Who would have guessed that we were going to have people fretting about how to deal with very low wholesale prices?”
Molodetz said that, in Hydro-Québec’s six partnered bids for Massachusetts’ recent clean energy procurement, he was surprised by the high level of public engagement in the siting processes. And that’s not a negative point, he added. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
“Increased environmental stakeholder involvement will lengthen the siting process, but we’ll have better projects for it,” he said. “The demand for clean energy is large and it’s growing. Québec peaks in winter, while New England peaks in summer, so matching those peaks in connected transmission is great for consumers and for grid operators.”
Molodetz said Hydro-Québec foresaw growing demand for renewables and began expanding its hydro capabilities a decade ago to enable the company to increase its cross-border transmission. The company’s largest customer is still the province of Québec, with New England a distant second and New York behind that.
Elisabeth Treseder, senior regulatory adviser at DONG Energy North America, pointed to the technological leap in capability for renewable resources. She said renewable energy providers often look to the states for leadership on procurement, but that everyone benefits from evolving technology.
“We recently decommissioned our first offshore wind project, built in 1991, which produced as much in 25 years as one of our new projects can generate in 16 days,” Treseder said.
Millstone Issue
During the conference, Commissioner Klee also addressed a question about state support for Dominion Energy’s Millstone nuclear plant.
In June, Connecticut’s General Assembly failed to pass a bill that would have allowed the 2,111-MW facility to bid into the state’s procurement process (S.B. 106). The following month Gov. Dannel Malloy issued an executive order requiring state officials to assess the plant’s economic viability and determine whether the state should provide support it financially. The governor also directed DEEP and PURA to assess the viability of all forms of renewable energy and to report their findings by Feb. 1. (See Commenters Seek Broader Response on Millstone.)
“Millstone is the largest single power plant in New England and is essential in terms of being a carbon-free resource and to the grid’s reliability,” Klee said. “The flip side is, because it is so large, our normal set of tools that we traditionally use don’t always seem to fit or may start to cause intersections with the regional grid and its market rules and components that are new and different, uncharted territory.”
The plant is also essential for the region’s winter peak problems, which are exacerbated by gas pipeline constraints, he said. The state is currently getting those gas-free and carbon-free reliability attributes for “free” in paying wholesale with no adder, Klee said.
“That valuation process is complicated and that starts getting into things that are more in the crucible of a legislative session,” Klee said. “The answer is still unknown and it gets more complicated by the week as DOE is inserting itself into this space with their [Notice of Proposed Rulemaking] on reliable or 90-day sources of baseload energy.”
Mary Sotos, deputy commissioner for energy at DEEP, encouraged participants to comment on the docket her agency has opened on Millstone. “We’re accepting comments throughout the proceeding and are required to deliver the results of that study to the legislature in the beginning of February,” she said.
Dynegy’s Ellis said the DOE proposal talked about preserving baseload energy because it is more resilient.
“Again I would argue that all resource types offer different reliability attributes,” Ellis said. “Natural gas-fired plants complement the intermittency of renewable energy better than baseload energy does. … If we’re going to pick and choose which reliability attributes we want to value, we need to take a look at all of them.”
The projects include new construction, end-of-life replacements and upgrades to address reliability criteria violations and relieve congestion throughout the RTO’s 13-state footprint, which includes D.C. The board approved upgrades in areas served by American Electric Power; American Transmission Systems Inc.; Commonwealth Edison; Dominion Energy; Duke Energy Ohio & Kentucky; East Kentucky Power Cooperative; Pennsylvania Electric; and Public Service Enterprise Group.
“Maintaining the reliability of the grid is paramount and involves continuously reviewing small and large transmission projects,” PJM CEO Andy Ott said in a statement.
The two costliest projects are both in PSEG’s zone: one in northern New Jersey near New York City and one in the southern part of the state near Philadelphia. The northern project will consist of a 69-kV transmission network at an estimated cost of $197 million, while the southern project will consist of another 69-kV estimated at $98 million. Constructing a substation in ComEd’s zone will cost about $90 million.
The approvals also include results from the first proposal window of the 2017 Regional Transmission Expansion Plan, which closed on Aug. 25. PJM had requested proposals to correct 40 reliability violation flowgates identified in a reliability analysis for 2022. The RTO received 51 proposals from 10 entities addressing nine target zones and added five additional “immediate need” baseline upgrades that will be performed by incumbent transmission owners. (See “RTEP Window Results,” PJM PC/TEAC Briefs: Sept. 14, 2017.)
WASHINGTON — FERC on Thursday set a 40-year default term for hydropower licenses, a move it said will reduce administrative costs and encourage dam owners to upgrade capacity and make environmental or recreational investments.
“This is quite a big deal, because we’re changing a policy we’ve had in place for several decades,” said Commissioner Cheryl LaFleur.
The commission’s policy statement (PL17-3), which will apply to original licenses and license renewals, also set conditions under which it will consider terms longer or shorter than 40 years:
If necessary to coordinate license terms for projects located within the same river basin;
When a different term is included in a “generally supported” and “comprehensive” settlement agreement that does not conflict with terms for projects in the same river basin; and
When an applicant requests a longer term based on “significant measures” voluntarily implemented during the prior license term or expected to be required for renewal. The commission has previously found that the construction of pumped storage facilities, fish passage facilities, fish hatcheries, recreation facilities, dams and powerhouses warranted longer license terms.
FERC regulates more than 2,500 dams with 55,800 MW of capacity, more than half of all hydroelectric capacity in the U.S. The Federal Power Act allows the commission to issue original licenses for up to 50 years and renewals for between 30 and 50 years. There is no minimum license term for original licenses.
| FERC
The commission’s policy on renewals had been to set a 30-year term when there is little or no new construction or environmental mitigation required; a 40-year term for projects with a “moderate” amount of such activities; and a 50-year term for projects requiring “an extensive” amount of such activity.
The change resulted from the commission’s November 2016 Notice of Inquiry, which followed licensees’ complaints that the commission should consider longer license terms to recognize settlement agreements, prior investments, relicensing costs and losses in generation value resulting from environmental measures. (See FERC Considers Change to Hydro License Rules.)
The NOI generated more than 40 responses, most of which supported policy changes. Some complained that license applicants lack guidance on what measures will yield longer license terms. Others said that because the commission’s policy is forward-looking, licensees delay seeking approval for capacity upgrades and environmental and recreational enhancements until they apply for a new license.
Some industry commenters complained that the license term cannot be used as a “bargaining chip” in settlement talks because the commission might reject that term; they also said the current policy penalizes well-maintained and low-impact projects that don’t require substantial new investments and thus only receive a 30-year license.
Compromise
The 40-year default represents a compromise between industry stakeholders — who generally supported a 50-year default — and environmental groups and most federal and state resource agencies, who said making the default equal to the FPA’s maximum would eliminate incentives for applicants to agree to mitigation measures.
“The resource agencies also contend that such policy would result in applicants focusing their license application study efforts on disproving project effects rather than on identifying potential mitigation measures,” the commission said.
FERC staff expects more than 300 relicensing requests through 2025, which would have required case-by-case analyses under the current rules.
The commission said the change will provide licensees and other stakeholders with more certainty while reducing administrative burdens. Case-specific assessments will only be required for licensees seeking a term longer than 40 years that is not subject to a settlement agreement.
The new rules will apply to all licenses issued following publication of the policy statement in the Federal Register. Those with pending license applications can file petitions demonstrating why the commission should grant a term longer than 40 years or settlement agreements that include longer terms. “The commission, however, will not entertain applications to amend existing licenses to extend their license terms simply on the basis of this new license term policy,” FERC said.
FERC on Thursday approved ISO-NE’s request not to disclose — even to non-market participants — any proprietary information from certain de-list bids for the RTO’s upcoming 12th Forward Capacity Auction.
The commission’s Oct. 19 order (ER17-2110) accepted the filing of de-list bids and granted the RTO’s request to waive a requirement that parties seeking privileged treatment for certain filings provide intervenors who execute a nondisclosure agreement access to that material.
ISO-NE in July submitted both privileged and public versions of a filing describing the permanent de-list bids and retirement de-list bids submitted for the upcoming FCA 12, to be held in February 2018 for the 2021-22 Capacity Commitment Period.
Pittsfield, Mass generator being scrapped
The RTO reported that it received one permanent delist bid and 23 retirement delist bids from six power suppliers for the upcoming FCA, covering resources located throughout all eight New England zones.
FERC staff in August issued a deficiency letter in response to ISO-NE’s filing of de-list bids, asking that the RTO also submit a form of NDA. The RTO responded two days later with an NDA as well as its waiver request.
The RTO’s auction qualification process requires owners of existing capacity resources that wish to exit their capacity supply obligation to submit delist bids specifying a price below which they do not wish to provide capacity. Such bids submitted ahead of an FCA may be “static” for a one-year exit from the capacity market; “permanent” for a permanent exit from the capacity market; or a “retirement” de-list bid for permanent exit from all ISO-NE markets, including that for energy.
Public Citizen Protest
Public Citizen filed the only protest to the request, contending that lack of access to the privileged components of the filing made it “impossible to determine” whether the permanent de-list bids and retirement de-list bids were just and reasonable.
ISO-NE countered that the privileged information includes “the [de-list] bidders’ expected cash flows, expectations regarding capacity market payments and information regarding opportunity costs … [and] critical aspects of suppliers’ likely bidding strategies … [which], in conjunction with the other confidential information, reveals the prices at which supply would be withdrawn in the auction.”
The grid operator asserted that the privileged portions of its filing contain “highly confidential, market sensitive information” that could “provide market participants who obtain it with an unfair competitive advantage” in future capacity auctions, thus negatively affecting the competitiveness of those auctions. The RTO referred to an earlier FERC order on FCA 8 in which the commission agreed that revealing resource-specific bid data would result in such significant harm to the Forward Capacity Market that it could not be provided to parties even if they signed an NDA.
Public Citizen argued that the FCA 8 order did not apply to its own request because the organization is not a market participant.
“We disagree,” the commission said in its ruling. Although the FCA 8 order referred to market participants, the commission reiterated its finding that harm could not result solely from disclosure to market participants. Rather, “the potential for harm to the FCM and to New England customers from any disclosure of this protected information could be significant.”
In the FCA 8 order, the commission noted that parties had access to a significant amount of publicly available information regarding the auction and therefore did not require ISO-NE to disclose the privileged information.
“We find that the same rationale applies here,” FERC ruled Thursday.
WASHINGTON — Gas supply for New England and Southern California is the top reliability concern for the coming winter, FERC officials said Thursday.
Commission staff said they saw no major risks of significant disruptions this winter but that they would be closely monitoring gas supplies in the Northeast and the area around California’s Aliso Canyon storage facility.
“You’d probably be the market that keeps me up at night,” Commissioner Robert Powelson told ISO-NE Vice President of System Operations Peter Brandien at the commission’s monthly open meeting, where officials of all six FERC-jurisdictional RTOs and ISOs gave their annual presentations on winter preparedness.
Brandien earlier had pronounced himself “cautiously optimistic.”
Bull’s-Eye
“I always feel like I have a bull’s-eye when on me when I come down to talk about these things,” Brandien said, prompting laughter.
While the 2014 polar vortex jolted PJM and others to tighten rules ensuring generators’ reliability, ISO-NE has been dealing with the issue since the 2004 “cold snap,” he said. New England produced 49% of electricity using gas in 2016, up from 15% in 2000.
Since a second scare in winter 2012-13, the RTO has been relying on temporary winter reliability measures that encourage gas operators to have dual-fuel capability and access to LNG. The temporary program will give way to the Pay-for-Performance rules beginning June 1, 2018, that contain stronger capacity market incentives for securing fuel.
Brandien said tight pipeline capacity and limited visibility into LNG shipments remain his region’s concern.
“I think we’re pretty much coordinated-out,” he said when asked if additional gas-electric coordination would help New England. “The problem is we have full pipes.”
Brandien said the additional pipeline capacity provided by Spectra Energy’s Algonquin Incremental Market project in January has been offset by the retirement of the 1,500-MW coal-fired Brayton Point Power Station at the end of May.
“I actually was encouraged when I saw that some of the [gas] future prices for New England were higher than other places because those are the kind of things that are going to incent some contracts or some arrangements to be made to get [LNG] ships moving to New England,” he said.
Gas availability also could be a concern for New York City, which gets 95% of its generating capacity from gas or dual-fuel plants, said Wes Yeomans, NYISO’s vice president for operations.
The ISO’s 90-10 base case for the winter shows a statewide capacity margin of more than 11,000 MW, but that drops to 7,000 MW if generators receive only firm gas supplies and less than 4,300 MW if all gas is lost.
CAISO
The reduced capacity of the Aliso Canyon gas storage facility following the 2015 leak also was the subject of concern.
Sixty-two of the facility’s 114 wells were taken out of permanent operation. As a result, FERC staff said, the Southern California Gas system has 65 Bcf in storage, the lowest on record for this time of year since at least 2001 and far below its five-year average of 118 Bcf.
Although there were no supply interruptions this summer, staff said, Aliso Canyon’s limited storage “could challenge regional stability and increase natural gas and electricity prices” this winter. “The recent outages of SoCalGas Line 235-2 and Line 3000 may also limit flexibility in the region. This risk could also be magnified by upstream pipeline issues, like further outages or wellhead freeze-offs.”
Nancy Traweek, CAISO’s executive director of system operations, said California’s wildfires are not currently a threat to transmission but are having an impact on distribution.
One subject that was not raised as a reliability concern by the RTO officials who spoke to FERC was fuel diversity and the continued retirement of coal generation — an issue cited by Energy Secretary Rick Perry in his call for price supports for coal and nuclear plants. FERC Chairman Neil Chatterjee on Oct. 13 praised Perry for raising the issue. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.)
In a press conference after the meeting, Chatterjee said the RTO officials were only some of those whose views will be considered by the commission in the Notice of Proposed Rulemaking (RM18-1).
“We will find out from a variety of stakeholders whether there are conditions today or in the future that we need to consider,” he said. “Perhaps the fuel mix is working for them today. As market conditions continue to change, we don’t know what the future will hold. As some of these assets are retired, that will change the fuel mix.
“We need to be constantly vigilant and monitor the grid, monitor market changes, to ensure that this winter and beyond we don’t have circumstances that could lead to catastrophic outcomes.”
Chatterjee said he was withholding judgment on whether high penetrations of wind pose a reliability concern.
Bruce Rew, SPP’s vice president of operations, said the RTO was forecasting a new wind penetration record of 66% Friday. Thanks to accurate forecasting, Rew said, the RTO has already handled penetration of 55% wind and wind output swings of 10,000 MW within a day “without any problems.” The region has added 3,000 MW of wind capacity since last winter.
[As it turned out, wind peaked at 13,039 MW in SPP Friday, short of the 13,342 MW record set Feb. 9.]
“We’re going to make a fact-based determination based on what the record reflects,” Chatterjee said. “I certainly respect the gentleman’s opinions, and I will defer to his expertise as well as others to make that assessment.”
Comments on the rulemaking are due Oct. 23.
On Thursday, a bipartisan group of eight former FERC commissioners — including former Chairmen Elizabeth Anne (Betsy) Moler, James J. Hoecker, Pat Wood III, Joseph T. Kelliher and Jon Wellinghoff — filed joint comments saying that Perry’s proposal would be “a significant step backward from the commission’s long and bipartisan evolution to transparent, open, competitive wholesale markets.”
“The commission’s adoption of the published proposal would instead disrupt decades of substantial investment made in the modern electric power system, raise costs for customers and do so in a manner directly counter to the commission’s long experience,” they said.
So big that, even before it made landfall in Texas on Aug. 25, the National Weather Service was warning via Twitter that it was “unprecedented.”
“All impacts are unknown and beyond anything experienced,” NWS said. “Follow orders from officials to ensure safety.”
| CenterPoint Energy
“If you follow the National Weather Service … on Twitter, there’s not usually a lot of hyperbole,” ERCOT CEO Bill Magness observed. “This one, you could tell, was like nothing they’d ever seen.”
There was no shortage of superlatives Tuesday as AEP Texas and CenterPoint Energy executives briefed ERCOT board members on the impact of the massive storm and their recovery from it.
| AEP Texas
The largest rain event in U.S. history dumped an estimated 40 to 60 inches of water in southeast Texas and southwest Louisiana — so much that the NWS had to add more colors to their maps to display the totals, Magness said.
Harvey made landfall at Rockport, Texas, as a Category 4 hurricane with winds of 130 mph on the evening of Aug. 25. The following day, it stalled over the state, picking up more moisture from the Gulf of Mexico before making a final landfall in Louisiana on Aug. 30.
While that meant unprecedented flooding, “from a transmission system perspective, the fact that it stopped was a good thing because … it was pretty much tearing up the transmission system that it passed through,” said Dan Woodfin, ERCOT’s senior director of system operations.
“When the storm was first coming onshore in the late hours of the 25th, we were having upwards of 20 … transmission elements tripping off each hour,” Woodfin continued.
“Our folks were running … N-1-1 studies — so, not just what it takes to be secure, but what it takes to be secure if the next line goes out. … Almost as soon as they finished the study, that line would trip and then we’d have to redo it for the next N-1-1.”
The ISO lost 12,000 MW of generation as gas-fired plants were evacuated or flooded and coal plants were derated as they switched to gas, their coal piles too sodden to burn. Wind turbines were shut down until the winds fell below their maximum operating speed. Other generators that could have run were unable to because they had no transmission.
Luckily, cooler weather meant that loads were as much as 25,000 MW lower than the week before.
The wind was the biggest problem for AEP Texas’ territory along the Gulf Coast, company President Judy Talavera told the ERCOT board. The utility, which had 220,000 customer meter outages at its peak, had to replace or repair 766 transmission structures and more than 5,700 distribution poles. Four million feet, or about 757 miles, of transmission and distribution conductor was replaced.
| AEP Texas
About 5,600 people, many from other utilities, helped the company restore 96% of outages within two weeks. “We drill for these types of events but those don’t quite prepare you for the actual event,” Talavera said.
For CenterPoint, which serves the Houston area, rain and lightning was the bigger challenge than wind, said Kenny Mercado, the company’s senior vice president of electric operations. The company recorded 42,000 lightning strikes. There were 150 tornado warnings in Houston, with more than 30 twisters touching down. The warnings created “a tremendous amount of anxiety” for residents, he said.
| CenterPoint Energy
Seventeen substations were impacted; half of them knocked out of service, the other half inaccessible because of the flooding of the San Jacinto River, the Buffalo Bayou and other waterways.
The unrelenting rain limited the utility’s ability to restore service. In 2008, by contrast, “[Hurricane] Ike moved through the city and then we could go to work,” Mercado said.
Only 200,000 metered customers were out of service at any time. “But the problem was every day we’d get another 200,000. And the next day we’d get another 200,000, and the next day. So, it never ended until eventually we saw blue skies,” Mercado recalled.
Helped by Hardening, Technology
The good news, utility officials said, was that flood protections and technology added in recent years limited damage or increased the speed of the recovery.
A flood wall built after 2001’s Tropical Storm Allison protected the Grant substation, which serves the Texas Medical Center in Houston, the world’s largest medical complex.
A 50-MVA mobile substation installed on a church’s grounds allowed the company to restore power for 10,000 customers after 10 days. “They would have been out for probably another five days without it,” Mercado said. “So, the mobile substation technology that we have today is very, very valuable in terms of resiliency of the grid.”
Hundreds of intelligent grid devices saved 140,000 customer outages and provided critical situational awareness for restoration. Smart meters allowed the company to bill 700,000 accounts with actual readings and execute 45,000 orders remotely during the storm.
The companies resorted to drones to survey damage, airboats and amphibious vehicles to reach flooded substations and helicopters to move new transmission poles.
| AEP Texas
When standing water became a health hazard to workers, AEP outfitted their workers with mosquito nets to wear over their hardhats.
One technology that was not so successful for CenterPoint was its Tiger Dam, water-filled balloons that can function like sandbags but are quicker to deploy. “Didn’t have so much luck with it in Round 1,” Mercado said. “But it’s a skill set. We’re going to have to learn a little bit better how to do something in real time in terms of planning and preparation to look at those kinds of solutions.”
The company also plans to raise substation equipment to make it less susceptible to flooding.
Automated Calls, Facebook
| AEP Texas
The utilities also made use of newer means of communicating with their customers, including Twitter and Facebook.
Although 1.2 million CenterPoint customers lost service, “we only had 175,000 customers call … letting us know the power was out. … Only 67,000 customers used a live agent,” Mercado said. “So, the world’s changing. We’re seeing more and more automation take care of customers’ needs. Our power alert service technology pushed [text messages] out to 350,000 customers.”
CenterPoint’s website saw six times as much traffic as normal.
AEP Texas saw its Facebook followers more than double as the company made about 100 informational postings.
Public Support
Talavera said she was touched by the customers’ expressions of thanks to the restoration workers.
Residents offered workers meals, water and Gatorade, “wanting to show how much they appreciated them,” she said. “It’s really humbling. We know we provide an essential service and we’re proud of the efforts that were undertaken to restore service to our communities. But it’s certainly a partnership in working together with them.”
ERCOT will face higher prices and lower capacity margins following Vistra Energy’s retirement of 4,100 MW of coal-fired generation, Independent Market Monitor Beth Garza told the ISO’s Board of Directors on Tuesday.
Assuming ERCOT’s analysis of the pending retirements doesn’t identify local reliability concerns that would result in reliability-must-run contracts for any of the units, Garza said, “We’re looking at a much different situation going into the summer of 2018 than the fat and happy times … of the last couple of years.
“We’ve had really two years of clearly unsustainably low prices with high reserve margins,” she continued. “I think I’ve been saying it in those terms for the last couple of years, and I think we’re now seeing evidence of that unsustainability.”
Since Oct. 6, Vistra Energy’s Luminant unit has announced retirements of the two-unit Big Brown generator north of Houston (1,150 MW); the two-unit Sandow, northeast of Austin (1,137 MW); and its three-unit Monticello plant in East Texas (1,800 MW). The retirements will leave the company with just two coal plants totaling 3,850 MW. (See Vistra Energy to Close 2 More Coal Plants.)
In addition, the Texas Municipal Power Agency announced in July that it will put its 470-MW Gibbons Creek unit in seasonal mothball status, operating only from June through September.
| Potomac Economics
Garza said the announcements were no surprise given that coal units’ fuel costs have been consistently above combined cycle gas units since the beginning of 2015 and coal units were likely unprofitable in 2016.
Although the trends have been clear for some time, Garza said the timing of the Luminant announcements forced her to revise her presentation to the board.
Her presentation showed a 15% reserve margin for 2018. But that could fall to 12% because of the new retirements, she said. She cautioned that her data did not reflect changes in the interconnection queue since ERCOT’s last Capacity, Demand and Reserves report in May.
| Potomac Economics
“It seems to me like the market’s working and folks are responding to appropriate market incentives,” said Director Peter Cramton. “And now it’s time for us to let the market work.”
“I would echo that,” Garza responded. “Generators have a fairly low barrier to entry to the market. Along with that, I think it’s important to have an easy exit as well.”
“You’ve been rubbing the dark side of your crystal ball here pretty good,” Director Karl Pfirrmann pressed Garza. “Now let’s start rubbing the other side a little bit. Tell me, what is it in our marketplace that’s going to correct this problem?”
Garza said the retirements are likely to push forward prices higher, creating pressure for load-serving entities. “If I were a load-serving entity, I would be a little more anxious about the surety of supply going into the forward years than I am right now,” she said. “So, you might see contracting opportunities for new generators that haven’t been there in the past.
“I’m hopeful … that we won’t try to keep units in the market longer than they would like to be there,” she continued. “We just have to be comfortable with what that means — likely higher, more volatile prices going forward than what we’ve experienced in the last couple of years.”
Cramton, an economist at the University of Maryland, agreed. “If we let the market work, it will be a higher forward price — and especially the forward prices many years out. There’ll be pressure on the demand side.”
But he said he feared the transition could be interrupted by “regulatory uncertainty around large subsidies for keeping guys in the market that shouldn’t be there.” It was an apparent reference to Energy Secretary Rick Perry’s call for price supports for coal and nuclear units, although his proposal is limited to FERC-jurisdictional RTOs and ISOs.
“That’s what’s going to damage the market,” Cramton added. “So, I would urge everyone to tell their congressmen to stop that.”
