NEW YORK — Investor-owned utilities will fight any tax overhaul that doesn’t preserve deductions for interest and property taxes, the head of the Edison Electric Institute told Wall Street analysts Wednesday.
As the nation’s “most capital-intensive industry,” electric utilities hope to convince Congress and President Trump that they should be treated differently from others when it comes to eliminating deductions, EEI CEO Tom Kuhn said.
“We can make a case that we’re different,” Kuhn said. His argument: Current tax policies allow utilities to reduce their weighted average cost of capital, saving ratepayers money.
EEI said that while it supports simplifying the tax code, broadening the tax base and reducing rates, it will seek to preserve the federal income tax deduction for interest expenses and state and local taxes (primarily property taxes), as well as maintain parity between dividend and capital gains tax rates.
It also will fight to continue tax “normalization” rules, which require state regulators to treat tax benefits to customers in the same way that the recovery of the cost of the associated property is treated.
Normalization spreads the tax benefits associated with assets over the same time period that the costs of those assets are recovered from customers. “It is critically important to maintain tax normalization to the extent that accelerated depreciation or other investment incentives are retained in the tax code,” EEI said in a position paper.
About 100 analysts attended the annual briefing at the tony University Club off Fifth Avenue, about a block from Trump Tower.
Kuhn said a group of utility CEOs traveled to D.C. a few days after Trump’s inauguration to make their case to White House officials and congressional leaders. “We’re going to be in the front of the curve” in lobbying, he promised.
Although tax reform wasn’t a major issue in the fall elections, Kuhn said he sees the call by the president and Congress for change as reminiscent of the conditions in 1986, before President Ronald Reagan’s tax package was approved.
“Tax reform doesn’t happen very often — every couple of decades,” he cautioned, adding that a tax initiative will likely be a back burner issue until Trump and Congress act on replacing the Affordable Care Act. “I don’t think it’s going to be an easy lift.”
One wild card is the proposal by prominent conservatives, including former secretaries of state George Schultz and James Baker III, for a carbon tax. “It’s really early in the debate right now,” Kuhn said of the proposal, noting questions about how the proceeds for the tax would be spent.
Convincing Regulators on Capital Spending
EEI projects that its 44 investor-owned utilities made a record $120.8 billion in capital spending in 2016, up from $103.3 billion in 2015. Of that, 35% was spent on generation (up from 32% in 2015), while transmission dropped to 17% (from 18%), and distribution was unchanged with a 26% share. Much of that spending has been on smart grid improvements.
What are ratepayers getting for their money? Job growth, resiliency and economic benefits from shorter outages, said David Owens, EEI’s executive vice president for business operations and regulatory affairs.
EEI officials said the increase in smart grid technology — along with stronger wires and poles, use of robocalls and improved situational awareness — helped utilities in the Southeast restore power to all customers within two days after Hurricane Matthew in fall 2016.
About 70 million smart meters have been deployed to date — representing 60% of U.S. households — up from 32 million in 2012, when Superstorm Sandy knocked out power to millions along the East Coast for as long as two weeks.
“We’ve got to demonstrate [to regulators] that there’s a whole string of benefits that accrue” from smart grid investments, said Owens, a long-time EEI official who has announced he will retire June 30. “We’ve got to demonstrate to the regulator that there’s a fair way to allocate those costs. If you’re rolling in those costs, you’ve got to be able to demonstrate that all the customers benefit. If you’re not rolling them all in, you have to charge that individual customer.”
FERC’s Future
Former FERC Commissioner Philip Moeller, EEI’s senior vice president for energy delivery and chief “customer solutions” officer, commented on prospects for restoring the quorum lost Feb. 3 following the resignation of former Chairman Norman Bay.
FERC canceled its Feb. 16 meeting and said no monthly agenda meetings would be scheduled until a third commissioner is confirmed to join acting Chairman Cheryl LaFleur and Commissioner Colette Honorable. FERC’s annual joint meeting with the Nuclear Regulatory Commission will be held as scheduled on Feb. 23.
“Realistically, the most optimistic scenario I would say would be [to have] multiple slots filled in 60 days. But that’s very optimistic,” Moeller said, adding that a candidate who has already cleared the FBI background check could be installed more quickly. Among those rumored as a candidate for the commission is former Texas regulator Barry Smitherman.
He predicted the new commission will seek to ensure that wholesale markets recognize the reliability value nuclear generators provide as baseload resources, citing financial supports approved in Illinois and New York. (See related story, Connecticut Lawmakers to Draw Up Millstone Rescue Plan.)
Moeller also said the new commission may revisit Order 745, which required RTOs to pay demand response the same LMPs as generation, and Order 1000, which he said “has not provided the certainty for transmission planning that FERC intended.” (See FERC Won’t Revisit Demand Response Pricing.)
EEI will be urging the commission to change its discounted cash flow model for calculating returns on equity “to attract additional capital to the transmission system,” Moeller said.
In June 2014, Moeller voted with LaFleur and former Commissioner Tony Clark to apply to electric utilities a two-step DCF process that incorporates long-term growth rates. The new formula has resulted in numerous ROE reductions.
Prices dropped by one-quarter to $5.30/kW-month in ISO-NE’s capacity auction Monday, the lowest clearing prices since the RTO eliminated its price floor after the 2013 auction.
Forward Capacity Auction 11 easily surpassed the 34,075 MW of resources needed for the 2020/21 capacity commitment period, with a total of 35, 835 MW. Unlike in recent auctions, the RTO said, no new large power plants qualified, nor did any large power plants announce their retirements beforehand. However, 640 MW of new energy efficiency and demand response resources cleared, the equivalent of a new generating plant.
Three new power plants cleared in FCA 10 last year, which had a clearing price of $7.03/kW-month. That followed two consecutive record-breaking years, topped by the record $9.55/kW-month in 2015. (See Prices Down 26% in ISO-NE Capacity Auction.)
Falling prices are “the result of competition to provide plenty of the capacity that we need in New England,” Robert Ethier, vice president of market operations at ISO-NE, said at a news briefing Thursday.
Although the auction did not have large, significant new resources, “we did have a lot of smaller, other resources clear in the auction,” Ethier added.
The clearing price will be paid to all resources in all three capacity zones in New England and 1,035 MW of imports from New York and Quebec. Imports from New Brunswick, totaling 200 MW, will receive $3.38/kW-month. That price is lower because of excess capacity available over a 200-MW tie line.
The total cost this year is about $2.4 billion, down from last year’s $3 billion and 2015’s $4 billion.
Ethier said the lower prices allowed ISO-NE to acquire more than the minimum target to give it flexibility and to enhance reliability. Almost 40,500 MW — 34,505 MW of existing capacity and 150 new resources totaling 5,958 MW — qualified. (See ISO-NE Capacity Requirement Shows Flat Demand, More Solar.)
Several oil-fired units dropped out of the auction, “well under 200 MW” in the aggregate, officials said, but they remain available in the energy market. “We have not yet received any retirement notices from them,” said Stephen Rourke, vice president of system planning.
The new efficiency and DR resources bring the total available to more than 3,200 MW, or about 9% of the total capacity market.
In addition, demand reductions from the RTO’s forecast of behind-the-meter solar PV growth reduced the capacity target by 720 MW.
Six megawatts of new wind and 5 MW of new solar resources cleared the auction, bringing their totals to 137 MW and 66 MW, respectively.
ISO-NE said it will file the results with FERC at the end of the month, hoping for acceptance that traditionally occurs in June. The commission is operating without a quorum and would not be able to approve FCA 11 results on time if they are contested.
“We’ve thought about it, but it’s not a big concern, yet,” Ethier said.
CARMEL, Ind. – MISO will likely fall back on its existing Planning Resource Auction design next year after its Competitive Retail Solution failed to win FERC approval, but the RTO says the door is still open on instituting a locational auction construct.
At the Resource Adequacy Subcommittee meeting Wednesday, MISO officials were tight-lipped on whether they would seek rehearing on FERC’s Feb. 2 order or what approach they might pivot to in stakeholder discussions this year. (See FERC Rejects MISO’s 3-Year Forward Auction Proposal.)
While MISO Executive Director of Market Design Jeff Bladen discussed the possibility of rehearing, he stopped short of saying that the RTO would file a request. He also said the reliability issue in MISO’s competitive retail areas remains.
“It’s important to remember that there is a 30-day period where any party to the filing can request rehearing. Effectively, the docket remains open until then,” Bladen said. “I certainly would not prognosticate on if anyone would request a rehearing and what FERC would do with that … but I don’t want to be too opaque. MISO still recognizes that some things need to be fundamentally changed.”
While he didn’t rule out changes for the 2018/19 planning year capacity auction, Bladen said a retooled auction design by next year is unlikely. Bladen also said a “one size fits all” auction approach isn’t likely given the differing state regulatory structures in MISO.
“It’s pretty clear the proposal we made with the forward auction is not implementable on the timeline we proposed. It’s impossible for me to answer the hypothetical on what’s possible between now and the 2018/19 auction, but it’s hard to see [auction changes] implemented before then,” he said.
The company was deep in a problematic $6.8 billion acquisition of Pepco Holdings Inc. while bogged down in a two-front battle trying to get nuclear subsidies for plants in Illinois and New York.
Things look much brighter for the Chicago-based energy giant in early 2017.
First, the acquisition of PHI has closed, adding PEPCO, Delmarva Power and Atlantic City Electric to Exelon’s stable of electric distribution companies.
Second — and against most odds — the company was able to convince Illinois and New York legislators to pass laws providing subsidies for its troubled nuclear plants.
And somewhere along the line, Exelon picked up yet another nuclear generating station, the James A. FitzPatrick station, from Entergy. The FitzPatrick deal is expected to close this spring, the company said.
As Exelon CEO Chris Crane put it during an analyst earnings call on Wednesday, “2016 was a monumental year for Exelon.”
The company earned $410 million ($0.44/share) during the fourth quarter, compared to $347 million ($0.38/share) for the same period in 2015, missing analysts’ expectations by a penny. Annual earnings came in at $2.5 billion, up from $2.2 billion in 2015.
“We made great progress in the ongoing transformation of our company, with a focus on meeting our commitments to stakeholders via the PHI merger and the creation of the [zero-emission credit] programs in both New York and Illinois that compensate our nuclear plants for their carbon-free attributes,” Crane said.
The successful push for ZEC legislation reversed the company’s decision to retire the Clinton and Quad Cities nuclear plants, saving $120 million in projected early retirement costs, Crane said. He also noted that Exelon’s nuclear fleet had a 94.2% capacity factor for the year, up nearly 1 percentage point from the previous year.
Exelon says ZEC credits helped save Clinton Nuclear Plant | NRC
All of the company’s electricity distribution companies enjoyed fewer storms and therefore lower outage-related costs throughout the year, he said.
Looking ahead, company executives are eyeing legislative action in several other states — including Ohio, Connecticut, New Jersey and Pennsylvania — that could result in ZEC-style subsidies for nuclear plants there.
Joe Dominguez, Exelon executive vice president of governmental and regulatory affairs and public policy, described the company’s approach to winning those concessions.
The first stage is “establishing a recognition that nuclear is the lowest-cost and most reliable zero-carbon option” for electricity customers.
“That’s where we are in Pennsylvania,” Dominguez said.
The next step: identify different “solution sets,” such as the ZEC programs already adopted or including nuclear as a qualifying resource for renewable portfolio standards.
“And it’s way too early for me to handicap where that discussion is going to go,” Dominguez said.
HARTFORD, Conn. — Supporters of the Millstone nuclear power plant on Tuesday issued impassioned pleas for Connecticut legislators to save the plant but were short on details on how to provide enough revenue to keep it operating beyond 2021.
Those supporters were speaking at a Joint Committee on Energy and Technology hearing to discuss a preliminary bill, which, for now, merely says its purpose is “to provide a mechanism for zero-carbon electric generating facilities to sell power to electric utilities.” Sen. Paul Formica (R), committee co-chair and lead sponsor of the bill, said the hearing was intended to gather input from different constituencies.
While plant owner Dominion Resources has not said that it will close the Waterford facility, the company has acknowledged that the plant is under financial stress because of record low power prices set by cheap natural gas.
“We need to gather all the facts because we need a baseload power source here in Connecticut,” Formica said. “But if this baseload goes away, what happens to rates?”
Millstone can produce 2,111 MW, or about half of the state’s energy needs.
Bill co-sponsor Melissa Ziobron, a Republican representative from the nearby 34th District, said her husband has worked at the plant for 20 years.
“The premise of Millstone closing is real,” Ziobron said. “It is present for our family and 1,200 others.” She and others said the plant’s closure would devastate the economy of southeastern Connecticut.
An aborted plan introduced at the end of last year’s legislative session is presumed to be the starting point in any current deliberations to help Millstone. In the waning hours of that session, the Senate unanimously passed a measure that would have allowed the plant to bid into the state procurement process now reserved for renewable energy, large-scale hydropower and trash-to-energy facilities.
The bill passed the Senate without any hearings, but time ran out for the House of Representatives to act.
Elin Swanson Katz, the state’s consumer counsel, took no position on the bill, but she said her office is pleased with the mechanisms the state has put in place for long-term energy procurement to protect ratepayers.
“These processes have been highly competitive and well managed,” Katz said.
John Erlingheuser, associate state director of advocacy at AARP, called the bill “a special deal that has the same impact as a subsidy” that effectively reclassifies 50% of the state’s generation as renewable energy.
Dominion contends that the policy is justified.
“If Connecticut wants the lowest-cost, longest-term resource that also meets its environmental and economic goals, the solicitation process has to be expanded,” Kevin Hennessey, the company’s director of state policy for New England, said in written testimony.
Power producers say that reverses 20 years of progress in building competitive markets in the region.
“Proposals to selectively grant some resources preferential treatment without regard for the impact of doing so on the rest of the power supply system risk highly adverse and likely irreversible consequences,” the Electric Power Supply Association wrote.
Eric Brown, general counsel for the Connecticut Business and Industry Association, disputed those who said Dominion needs to open its books to justify the policy change.
“We don’t need to see their books,” Brown said. “The marketplace has sent a very clear message: Nuclear power is struggling throughout the country. We’re losing plants in New England. That’s the best kind of evidence.”
Dominion commissioned a recent study indicating that state carbon emissions would increase by 2.5 million tons if the plant retired and was replaced by natural gas-fired generation.
Roddy Diotalevi, senior director of sales and external relations for UIL Holdings, said that Millstone is important in helping the state reach its environmental goals but that the costs to keep the plant running are still unknown.
“UIL remains concerned about the impact that these above-market payments will have on ratepayers and the negative effects that a long-term obligation and financial liability would have on the utility,” Diotalevi said.
Millstone and NextEra Energy’s Seabrook plant in New Hampshire are soon to be the only remaining nuclear plants in New England. Vermont Yankee closed two year ago, while the Pilgrim station in Massachusetts will shut down in 2019. New York’s nuclear fleet has been saved by a state subsidy, but that program is currently being litigated.
VALLEY FORGE, Pa. — If you thought the ending of Sunday’s Super Bowl matchup was electrifying, you’re not alone. The event had a noticeable impact on electricity demand.
Just after the game started at about 6:30 p.m. on the East Coast, PJM’s demand dipped below the RTO’s forecast by about 1,000 MW, or about 1%, when everyone dropped everything to watch.
It recovered and then jumped above the forecast around 8 p.m., roughly corresponding with halftime, when everyone took a break to do other things, like cooking wings or microwaving some more queso dip. The load then followed the forecast until the game ended around 10:30 p.m., when it again exceeded the forecast as everyone went back to their normal routine.
The “Super Bowl dip” is a phenomenon that many RTOs experience. In fact, ISO-NE examined it in a post it published on its website last week. Part of the reason PJM could predict the load with fairly good accuracy is because the RTO factored the phenomenon into its forecast.
But that isn’t always the case. A similar event happened on Jan. 15, when the real-time load dropped about 2,000 MW, or roughly 2%, below the forecast around 6:30 p.m. ET, then jumped back up to the forecast around 8:30 p.m.
“It seems to have coincided with the end of the Green Bay [Packers]-Dallas [Cowboys] football game,” PJM’s Phil D’Antonio told the Operating Committee on Tuesday. “Apparently, that [playoff] game had enough attention that people were sitting in front of the TV. Then after the game, they went back to their normal lives.”
D’Antonio, a manager of reliability engineering at PJM, explained that the “load deviation” caused alerts within PJM’s control system. Ken Seiler, PJM’s senior director of system operations, noted later that it caused an eight-minute spin response of almost 703 MW.
CAISO has issued a draft final proposal to prevent smaller transmission owners from bearing the high costs for network upgrades needed to interconnect generation serving load outside of their service territories.
While the latest revision keeps its focus on the specific circumstances faced by Valley Electric Association, it would also provide CAISO the flexibility to apply the proposal’s principles to similar TOs seeking entry into the ISO in the future.
CAISO has developed the small transmission owner generator interconnection proposal to accommodate Valley Electric Association, which faces high network upgrade costs for resources intended to serve other load centers. | Valley Electric Association
That plan (referred to as “Option A”) would require CAISO to determine on a case-by-case basis whether a candidate TO should be allowed to fold low-voltage generator interconnection costs into high-voltage transmission revenue requirements. Doing so would diffuse the costs among the ISO’s full rate base to avoid saddling small TO ratepayers with outsized fees.
Under the proposal, CAISO will make its determination based on whether the TO is:
Very small relative to other TOs, with a gross load of 2 million MWh or less (currently about 2.2% of the load of the ISO’s largest TO);
Located in a renewable resource-rich area gaining “elevated” interest for generator procurements; or
Not subject to a renewable portfolio standard or does not need the new interconnecting generation to meet that requirement.
CAISO rejected a more “formulaic” Tariff-based “Option B” that included the last two provisions but would have had the Tariff specify that a small TO’s gross load be no larger than 5% of that of the largest TO.
“Rather than trying to develop Tariff provisions that could address every potential unique circumstance, this [Option A] proposal specifies guiding principles the ISO would apply on a case-by-case basis to alleviate unintended adverse impacts for each unique” participating TO, CAISO said.
The option would require ISO management and staff to apply the principles to determine the “appropriate treatment” of each small TO and then seek approval for its recommendations from the Board of Governors and FERC.
CAISO dismissed the contention of some stakeholders who preferred Option B out of concerns that a case-by-case review could bog down the interconnection process.
“The ISO does not agree with the argument that Option A would cause delays since any ISO decision and subsequent FERC approval could be combined with the [TO] application process when a new [TO] joins the ISO,” CAISO said.
Valley Electric, CAISO’s only out-of-state member, serves 45,000 customers and about 100 MW of load in a 6,800-square-mile region along the California-Nevada border. The cooperative last year agreed to sell its 230-kV transmission network to GridLiance for $200 million. (See Valley Electric Approves Sale of 230-kV Network to GridLiance.)
The utility’s service area has high potential for the development of new renewable resources that would serve more populous areas of the ISO. Two projects with a total capacity of 100 MW await interconnection with the Valley Electric system, with more slated to enter the queue, according to the ISO.
Under CAISO’s Tariff, a TO must reimburse its generator interconnection customers for the costs of local reliability and deliverability network upgrades necessary to connect a resource to the transmission network. The TO can then seek regulatory approval to roll those reimbursement expenses into its rate base, passing them on to ratepayers through either a high-voltage or local low-voltage transmission access charge (TAC). The ISO considers any line under 200 kV to fall into the latter category.
While the high-voltage TAC is allocated to all ISO ratepayers at a postage-stamp rate based on the total revenue requirements of all TOs owning high-voltage transmission, the low-voltage TAC is charged only to customers within the service area of the TO owning the facilities.
That arrangement could burden ratepayers in low-population service areas who are forced to bear the low-voltage network upgrade costs for generation intended to serve other locales attempting to meet renewable goals.
CAISO has scheduled a Feb. 13 conference call to discuss the proposal and is asking stakeholders to submit comments by Feb. 22. ISO management seeks to present a plan for board approval in March.
Dominion Resources is changing its name to Dominion Energy to unify the look and brand of the holding company that now does business in 18 states.
The company said it wanted to bring all of its businesses under a single flag, especially since its $4.4 billion acquisition of Questar in September, which added 56 Bcf of gas storage and 3,400 miles of gas transmission.
| Dominion Resources
Dominion operates natural gas and electric distribution companies in seven states, with 2.5 million electric customers in Virginia and North Carolina, 2.3 million gas customers in Idaho, Ohio, Utah, West Virginia and Wyoming. It also has 1.3 million retail energy and energy services accounts in 13 states.
The company owns 26,400 MW of electric generation, 6,600 miles of electric transmission and 14,600 miles of natural gas pipelines.
Its newly branded Power Delivery Group, Power Generation Group and Gas Infrastructure Group will replace Dominion Virginia Power, Dominion Generation and Dominion Energy.
The new name — subject to stakeholders’ approval at the company’s annual meeting this spring — will be accompanied by a new logo: a blue “D” with energy-suggestive strips through it.
“Our company and our employees are proud of the work we have done in delivering energy for 119 years,” CEO Thomas Farrell said in a statement. “Dominion Energy builds upon this equity, updates our company’s look and unifies the company’s brand across all of our lines of business.”
“This is a good time to unify the brand, clarify the name and simplify the logo,” said Kelly O’Keefe of Virginia Commonwealth University’s Brandcenter, who worked on the branding project.
The branding announcement comes about a week after Dominion announced earnings of $457 million ($0.73/share) for the fourth quarter of 2016 and $2.1 billion ($3.44/share) for the year. The company earned $357 million for the fourth quarter of 2015 ($0.73/share) and $1.9 billion ($3.20/share) for that year.
Farrell used the earnings call to spotlight some of the company’s accomplishments for the year, including adding 727 MW of solar to its portfolio, bringing it up to 1,400 MW; continued progress on its 1,588-MW combined cycle station in Greensville County, Va.; the connection of 11 new data centers; and the completion of $784 million in transmission projects, with another $800 million on the horizon.
DALLAS — The SPP Board of Directors and Members Committee last week approved 13 of 14 transmission projects in the Integrated Transmission Planning 10-Year Assessment but directed staff to further evaluate the largest project in the portfolio.
RTO members and the board asked staff to further study and update a proposed 90-mile, 345-kV line in Southwestern Public Service’s service territory in the Texas Panhandle and bring back another recommendation to the April board meeting. SPS argued against the need for the project during January’s Markets and Operations Policy Committee meeting, saying it was “the wrong time” for the line. (See SPP MOPC Endorses 14 Tx Projects over Objections.)
SPS President David Hudson and the company’s director of strategic planning, Bill Grant, reiterated comments made a day earlier at the Regional State Committee meeting.
“Overall, our view is this could be a good project,” Hudson said. “It could taste great, but we don’t think it’s ready to come out of the oven. We think it needs more study.”
The line — which would run southwest of Amarillo to an SPS power plant that is currently being evaluated for continued operation — does little to relieve congestion in the area, Grant said. He also noted that several SPS customers are becoming more responsible for their resource needs.
“It just moves [the congestion] a little further south. It does move the north LMPs down, but it doesn’t merge the north LMPs and the south LMPs,” he said. “If anybody believes we’re building this line and all of a sudden the congestion goes away, that’s a misconception.
“I think that whole area needs to be looked at. I would like to see that better vetted before we go down this road.”
SPP staff said the proposed line would resolve local congestion dating back to 2001, estimated at an annual average cost of $21 million the last two years. At a projected $144 million for engineering and construction costs, accounting for 71.6% of the portfolio’s $201 million cost, the project has a benefit-to-cost ratio of 1.4 to 1.7.
“We just don’t believe some of these assumptions are warranted. We’d like to talk about it some more,” Hudson said, pointing to a likely delay of the Clean Power Plan and the replacement of a Tolk Generating Station coal unit with a gas-fired combined cycle plant. “We’re just not comfortable about a project that started coming back in the fourth quarter last year.”
Staff’s supplemental analysis late last year helped identify the project as an economic need. The addition of future generation in the latest planning models indicated more congestion than in previous versions, SPP Engineering Vice President Lanny Nickell said.
“We’ve matured in terms of the metrics we actually use to calculate these studies,” Nickell said.
American Electric Power’s Richard Ross advocated making the best use of that analysis.
“If we don’t get ahead of this with the economic analysis staff has done, we could be waiting for the shoe to drop,” Ross said. “When an entity requires another unit, we’re going to get behind the curve.”
Ross was concerned that SPP could face a reliability issue if it couldn’t get the line built in time to meet a future need. “Let’s make use of the best available information,” he said.
SPP Board Chair Jim Eckelberger agreed. Channeling his inner salty dog, the retired Navy admiral said, “We need to go back and make damn sure we’re going in the right direction before we start spending a hell of a lot of money.”
Director Bruce Scherr urged those “who have voiced reasonable doubts and sensitivities” to “come to the table and provide solutions and ideas that improve the understanding of the project and its benefits and costs.”
Members voted overwhelmingly for further study, with only ITC Holdings abstaining.
The ITP10 also recommended a 345/161-kV transformer and 161-kV line upgrade in southwestern Missouri, near Springfield. The line connects to an Associated Electric Cooperative Inc. substation in Morgan and could qualify as a seams project pending negotiations with AECI. (See “SPP-AECI Joint Study Recommends Two Projects,” SPP Seams Steering Committee Briefs.)
Stakeholders Try to Grasp Wind Energy’s Implications
The board and members devoted time to discussing the phenomenal growth of wind energy in the footprint and how best to integrate the variable resources.
SPP Operations Vice President Bruce Rew told stakeholders that another 3,100 MW of wind capacity began operating in the last quarter, bringing total installed and operational wind capacity to 15,500 MW. Another 630 MW of wind resources were registered as 2017 began, although they’re not yet operational.
Real-time wind output during the fourth quarter ranged from a record 12,336 MW to a minimum of 384 MW, Rew said. Output averaged 6,041 MW, up nearly 40% from the third quarter.
Wind energy’s variability is exacerbated by the diverse nature of SPP’s 14-state footprint, which ranges from Louisiana to the Canadian border. On Jan. 12, the footprint saw a 98-degree spread in temperatures — from 20 below in Bismarck, N.D., to 78 in Shreveport, La. The simultaneous temperature spread that day was 78 degrees.
Brown said SPP has experienced the loss of more than 10,000 MW in a single 24-hour period, underscoring the importance of “top-notch” forecasting tools.
“That’s the equivalent of 10 nuclear units,” he said. “That type of variance certainly got my attention. [Wind energy] is a wonderful resource, but it certainly keeps us on our toes.”
Ross agreed. He said that while forecasting is important, so is reliability, and he stressed the need for market participants to be able to effectively hedge when pursuing transmission service.
“The reliability issue is the paramount issue,” Ross said. “We need to be mindful of the impact on the existing base of the region and what our actions are doing to the existing customers.”
Ross, who chairs the Market Working Group, said he will coordinate the group’s work with the Transmission Working Group. The MWG will look at reliability unit commitments, negative lift prices and whether the market is sending appropriate price signals.
“It’s not clear what the solutions are, but it’s clear what the problems are,” said Golden Spread Electric Cooperative’s Mike Wise, who chairs the Strategic Planning Committee. “Substantial amounts of generation remain online with minimum loads.”
Given the difficulty of clearing coal plants in the day-ahead market, the RTO must determine how to get those plants offline if they’re not needed for long periods, Wise said.
“We’re pushing huge amounts of energy onto [a] market we have no load for,” he said.
SPP CEO Nick Brown suggested asking staff to develop a list of all the issues being discussed in order to assign responsibility, an idea seconded by Eckelberger.
“My concern is making sure we have the right people looking at the right issues,” Eckelberger said. “Let’s make sure we’re being as comprehensive in our thinking and getting the right answers.”
Rew also said that SPP added 10 market participants during the fourth quarter and now has 187 entities registered for its Integrated Marketplace, 121 of which are classified as financial-only. He said the market systems continue to be readily available, with the real-time balancing market successfully solving 99.97% of all intervals and the day-ahead market delaying postings just twice in 12 months.
SPP ‘Working Diligently’ with Mountain West
Brown said that Mountain West Transmission Group is “working diligently” with his staff as the two organizations explore potential RTO membership. Mountain West announced last month that is was entering discussions with SPP. (See Mountain West to Explore Joining SPP.)
COO Carl Monroe will continue to serve as the RTO’s lead in negotiations with Mountain West and Nickell has been designated as staff lead in the integration efforts, which could take up to two years, Brown said.
“In the past, we’ve learned the value of the officer responsible for integration to be intimately involved in the negotiations over the final details,” he said.
Brown said Mountain West’s potential membership is “front and center on my plate,” along with seams projects, integrating wind energy, cybersecurity and cost shifts within SPP’s transmission zones. (See Strategic Planning Committee to Continue Work on Tx Cost Shifts.)
“Our charge as staff is to bring very specific proposals to the SPC for [its] consideration,” Brown said. “I can assure you we will wrestle this to the ground very quickly.”
He said he had assigned Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel, to lead the zonal cost shift effort.
Oversight Committee Provides Update on MMU Search, Audit Compliance
A search firm is conducting a nationwide hunt for the new executive director of the SPP Market Monitoring Unit, according to Oversight Committee Chairman Joshua W. Martin III, who hopes to narrow the selection by the committee’s next scheduled meeting. Current Director Alan McQueen has indicated that he wants to retire this year.
“We’re satisfied, based on the results of that report, that the MMU is operating correctly,” Martin said.
SPP has not yet followed through on FERC’s suggestion that the MMU be physically separated from the RTO’s office space inside the corporate headquarters, but the operation is “occurring.” Other items from the report have been implemented, such as new time-keeping standards and practices ensuring new employees are aware of the unit’s independence, he said.
Barbara Sugg, the RTO’s chief security officer, said that the amount of malicious cyber activity continues to grow and that email phishing attacks are “more prevalent and real than any other security threat.”
“The numbers are just staggering. Your numbers are staggering,” she told members. “It’s crazy, the amount of traffic that tries to come in. It’s not targeted at SPP, but we’re just bombarded with the amount of information that comes up to the firewall.”
Sugg said SPP received 12 million emails in just one month and that only 7% were deemed legitimate. Eight million were deemed malicious.
SPP sends out emails as bait to see if anyone will click where they shouldn’t and then uses them as a learning experience, she said. Sugg regularly briefs the OC on cybersecurity issues and also represented all RTOs in testimony to Congress last week. (See related story, Interdependence Key to Cybersecurity Efforts, Congress Told.)
Eckelberger said that while SPP has done well with various audits and inspections, “the black eye we still carry with us” is a SERC Reliability Corp. cyber audit in 2013 that has yet to be closed.
“It’s still ugly, but [during] the last year — as a result of learning what’s going on here — we’ve quintupled the amount of people in the organization dedicated to cybersecurity,” Eckelberger said. “And we’re still less than other organizations.”
SPP RE Works to Improve Misoperations Numbers
Dave Christiano, chair of the SPP Regional Entity trustees, delivered mostly good news in a report. He said the six reported system events last quarter were at the lowest level of severity, improved audit processes have resulted in decreased audit times and team sizes, and 90% of violations were self-identified, denoting strong compliance cultures.
“That’s a good thing,” he said of the self-identified violations. “It’s good for you, it’s good for us.”
Director Harry Skilton noted misoperations were a “new green line” for FERC and inquired about how SPP ranked compared with other grid operators.
“We’re not one of the better performers,” Christiano said.
The most recent quarterly misoperations report shows an 88.7% success rate for relay operational performance. SPP’s sparsely populated footprint — approximately 18 million people in all or parts of 14 states — and long transmission lines play a part in the results, Christiano and Brown both noted.
“The problem is more the backup relays than the primary relays,” Christiano said. “When the primary relays operate, the backups don’t. They don’t get any credit for operating correctly, which might be part of the reason.”
“It’s hard for me to believe our relaying practices aren’t any more robust than anyone else’s,” Brown said, “but that could be.”
Board Remands 1 Revision Request, Approves 6 More
The board remanded BPWG-RR 155 back to the Regional Allocation Review Task Force, asking the group to decide whether the change needs to become a business practice and come back for another vote. The revision request, which failed to pass the MOPC in January, documents the potential Regional Cost Allocation Review remedies and clarifies the process to be used when implementing a remedy.
The board approved RTWG-RR 187, with only Westar Energy voting against it, replacing the old capacity margin terminology with a 12% planning reserve margin requirement. The change incorporates previously approved policies that identify who is responsible for resource adequacy, the resource adequacy requirement, and how and when the requirement can be and should be met. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
The board’s consent agenda, which passed unanimously, included five revision requests, a change to the Transmission Process Improvement Task Force’s white paper, the 2016 SPP Transmission Expansion Plan and several other minor revisions.
ORWG-RR 134: Clarifies previously ambiguous operating criteria language for the initial submission and subsequent updates of unit de-rate information in SPP’s control room software system.
MWG-RR 191: Clarifies that there should not be a requirement to reprice the day-ahead and/or real-time markets for every data input/software error.
ORWG-RR 195: Simplifies the process of SPP’s data-specification document required by NERC Reliability Standards IRO-010-2 and TOP-003-3 and makes basic formatting changes to the operating criteria document.
RTWG-RR 197: Completes the MMU’s annual review of frequently constrained areas by updating the list of constraints and resources.
MWG-RR 198: Uses a variable demand curve that moves SPP toward a more robust valuation of regulation and operating reserve and more accurately addresses and values operating and energy shortages during scarcity events.
FERC on Friday accepted PJM’s compliance filing on its fuel-cost policies for generating units but required the RTO to make another compliance filing to address a number of additional details (ER16-372-002).
The commission sided with PJM on several issues that have generated discussion at stakeholder meetings, including the relationship between the RTO and its Independent Market Monitor. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
“We agree with PJM that the proposed changes related to the fuel-cost policy are not designed to change the fundamental roles between the IMM and PJM, but rather to codify the role of the IMM in advising and providing input to PJM in its determination of whether to approve a fuel-cost policy submitted by a market seller,” the order read. “Accordingly, we reiterate our finding in the order that PJM has the final approval authority on fuel-cost policy.”
FERC declined PJM’s proposal that any differences between the RTO and its Monitor should be referred to the commission’s Office of Enforcement. That is the duty of administrative law judges, the order said.
The commission said the compliance filing, due in 30 days, should include:
PJM’s resource-dispatch formula and the process for determining the lowest-cost offer;
A broader description of which resources will be subject to mitigation;
The standard of review and an explanation of how a market seller would be found to be noncompliant with it;
specifics on when the penalty for a noncompliant fuel-cost policy would be terminated by the RTO, including a timeline with specific milestones;
A 90-day grace period before a new resource must submit its fuel-cost policy; and
A definition for when the penalty for noncompliance ends, along with a rebuttal period.
“We note that the penalty can still apply during the rebuttal time period, but if found to not be in violation of its fuel-cost policy, a market seller must be issued refunds as of the date of its rebuttal,” the order explains. “During this rebuttal period, if a market seller does not have a PJM-approved fuel-cost policy on file, it will still be required to submit a $0/MWh offer, but in the event that it is mitigated to its cost-based offer during this time period and its costs to operate, as per a PJM dispatch, are not covered by its market revenues, PJM should make the market seller whole by providing it with an uplift payment.”
