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.”
A three-year dispute over cost and revenue sharing for a CapX2020 transmission project moved one step closer to resolution after FERC last week approved a settlement between the city of Rochester, Minn., and the Southern Minnesota Municipal Power Agency.
The dispute concerns the Hampton-Rochester-La Crosse 161-kV and 345-kV transmission line between Minnesota and Wisconsin, which is intended to meet swelling demand in the Twin Cities, Rochester and La Crosse, Wis., areas. Rochester’s Public Utilities Board (RPU) is a 9% owner in the project, which is part of the CapX2020 joint initiative by 11 Minnesota utilities.
The settlement approves revisions to MISO’s Tariff incorporating RPU’s existing facilities in Pricing Zone 20 (the SMMPA pricing zone); converting the RPU transmission rate formula to a forward-looking formula rate template with an annual true-up; and adding RPU to Pricing Zone 16 (the Northern States Power pricing zone) (ER15-277-004).
Still remaining is a dispute between Rochester and Xcel Energy, which is challenging RPU’s proposed recovery of its transmission revenue requirement for the project from Pricing Zone 16. The settlement does not resolve whether any of those costs should be allocated to Zone 20 if it is determined that the costs do not belong in Zone 16.
In a related order, FERC rejected Xcel’s requested stay on RPU’s rate recovery until the line was in service, saying a stay would amount to a “collateral attack” on the commission’s refund effective date (ER15-277-001). FERC agreed with MISO that Rochester’s facilitates were already figured into the Zone 16 revenue requirement when Xcel filed the motion for a stay. As the host transmission owner of six other TOs in Zone 16, Xcel subsidiary North States Power receives and distributes revenues allocated to Zone 16.
“To grant the stay now would require recalculating the Zone 16 transmission rate and providing refunds,” FERC said. “We are also not persuaded that a stay would leave all parties indifferent, as it would cause a delay in [Rochester’s] recovery of costs. … Granting the stay — especially if it lasted until the resolution of the ongoing dispute, as Xcel suggests — could endanger RPU’s ability to recover its transmission revenue requirement for the 2016 year.”
The commission also declined to place Rochester’s share of Zone 16 transmission revenues in an escrow account until a settlement is reached, as Xcel requested.
Xcel charged that MISO’s collection of Rochester’s estimated annual transmission revenue requirement associated with the line in Zone 16 from Jan. 1, 2016, was not justified because MISO did not begin dispersing transmission revenues to Northern States Power until October, when the line was placed into service. Rochester argued that as a MISO TO, it has the right to recover revenue requirements for transmission facilities under the RTO’s control.
In response to Xcel’s request, FERC also clarified that RPU will be subject to refunds if the commission upholds a reduction in the return on equity for it and other MISO TOs. In October, FERC ordered the TOs’ 12.38% base ROE cut to 10.32%. Rehearing requests in the case are pending (EL14-12). (See FERC Cuts MISO Transmission Owners’ ROE to 10.32%.)
The commission also opened a new docket (EL17-44) to examine the Zone 16 joint pricing zone revenue allocation agreement, ordering Xcel and other interested parties to file initial briefs within 30 days after the publication in the Federal Register. FERC also sought briefing on whether MISO’s joint pricing zone agreement can circumvent recovery of commission-accepted transmission rates. Tariff revisions could be necessary, FERC said, as Xcel argued it could not distribute those revenues to Rochester without violating the terms of its joint pricing zone agreement.
MISO’s three-year effort to identify long-term transmission needs started last week with the RTO gathering stakeholders to explain the data that will inform the study.
The regional transmission overlay study will identify new transmission needed to accommodate MISO’s shifting resource mix.
“MISO has been experiencing a significant resource change for quite some time now. … We’re just starting to get our hands around the magnitude of the needs,” Lynn Hecker, MISO manager of expansion planning, said at a special Jan. 31 workshop of the Economic Planning Users Group, the first of four scheduled to take place in 2017. “At the end of the day, the goal is to have the most cost-effective and efficient solution for our footprint to benefit our consumers.”
Hecker said MISO is very early into its study and has not made any conclusions about which or how many projects will be recommended. She said 2017 will be used to identify system needs, and project candidates would not be revealed until 2018 or 2019.
Three Futures
MISO will develop long-term transmission roadmaps for each of three 15-year futures from its 2017 Transmission Expansion Plan: an “existing fleet” future with limited changes and no modeled carbon cap; a “policy regulations” future in which federal rules drive a 25% reduction in carbon emissions; and an “accelerated alternative technologies” future in which innovations in renewables foster a 35% carbon emissions reduction.
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It will also consider other factors, such as the top 30 congested flowgates, forecasted differences in LMPs, production cost savings, and constrained energy sources and sinks to identify new transmission corridors. (See “Long-Term Overlay Study Scoped; MISO Asks for More Responses,” MISO Planning Advisory Committee Briefs.)
Stakeholders asked if MISO planned to use MTEP 17 futures for all three years of the study. Hecker said there would be an annual refresh of futures and weights to inform the study. “That’s where we are going to be able to capture any potential changes,” she said.
Hecker said it is likely that MTEP 17 futures will be used, even with the Trump administration’s plan to abandon the Paris Agreement on climate change and EPA’s Clean Power Plan. “We don’t expect to see very drastic changes in 2017 versus 2018 futures,” she said.
It’s still undecided if MTEP 17 futures will be reweighted with less emphasis on a policy regulations future. The issue is expected to be discussed at the February Planning Advisory Committee meeting. (See MISO Stakeholders Seek Review of MTEP Futures Under Trump.)
MISO Director of Regional and Economic Studies John Lawhorn said that by 2031, the RTO expects gas prices to hover around $7.50/MMBtu, with:
Between 5 GW of renewable additions under an “existing fleet” future to 52 GW in an “accelerated alternative technologies” future;
Coal generation retirements of 8 GW to 24 GW under the same scenarios;
An increase in solar capacity from 180 MW in 2016 to 4,938 MW by 2021; and
An increase in wind capacity from 16,319 MW in 2016 to 23,554 MW in 2021.
Move from Inventory-Based Generation
“We’re going from inventory-based sources of energy [like coal piles and natural gas storage] to non-inventory. We want to make sure we meet system needs both on a reliability and economic basis,” Lawhorn said. “Our generation interconnection queue is full of intermittents and continues to grow.”
Consultant Roberto Paliza of Indianapolis expressed concern that MISO might overlook some transmission solutions if it only relies on the megawatt limit in MISO and SPP’s contract path in modeling, which is in place until 2021. MISO staff pointed out the transmission overlay study is one of three MISO studies currently in progress that could identify a project to expand the transfer capability between MISO North and South. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs.)
MISO Policy Studies Engineer Matt Ellis said the economic benefit of load diversity — taking advantage of different areas peaking at different times — could be expanded beyond the RTO’s borders to include capacity exchanges with neighboring systems.
“If you can connect pockets of renewables across regions, you can make those resources look not so intermittent anymore,” Ellis said.
Ellis said he was only introducing the idea and that MISO would conduct discussions on how a load diversity analysis could work into the transmission overlay. He said while MISO could expand peak load obligations exchanges into the Eastern Interconnection, the RTO could also exchange capacity with the Western Interconnection if DC line upgrades are made. MISO estimated that load diversity could save it $4 billion per year.
Sam Gomberg, an energy analyst in the Midwest office of the Union of Concerned Scientists, asked if MISO sufficiently explored its own load diversity before looking outside the footprint. Ellis said the benefits of load diversity within MISO were already being realized with a reduced planning reserve margin.
An afternoon portion of the workshop, at which MISO and stakeholders discussed thermal constraint locations covered by Critical Energy Infrastructure Information (CEII) rules, was not open to the public. Stakeholders representing MISO’s North, Central/East, South and West regions split by region to discuss potential transmission needs. Bill Booth of the Mississippi Public Service Commission said his commission did not have access to CEII but still wanted in on the conversation.
Hecker said most study results would be made public, but detailed transmission maps with current bus and transmission line locations will not be posted publicly.
Lawhorn stressed the three-year study will be peppered with stakeholder opportunities to weigh in.
FERC on Friday granted New York officials’ request to exempt new “special case resources” (SCR) from buyer-side market power mitigation rules in NYISO (EL16-92).
The commission, however, denied a request to exempt SCRs currently subject to mitigation. An SCR is a demand-side resource that participates as a supplier in NYISO’s capacity market.
NYISO’s rules apply the minimum offer price rule (MOPR) to new capacity resources in the New York City or G-J Locality ICAP markets.
The Advanced Energy Management Alliance, the Natural Resources Defense Council and several New York state agencies, including the Public Service Commission, filed a complaint last June seeking the exemption. They said subjecting SCRs to NYISO’s buyer-side market power mitigation rules presents an “unreasonable barrier” for demand response providers that increases consumer costs and interferes with state policy objectives under the Reforming the Energy Vision initiative.
NYISO agreed with the complainants, saying mitigation was unwarranted because SCRs do not have the ability to suppress capacity prices.
FERC also agreed, rejecting arguments from the Independent Power Producers of New York and the Electric Power Supply Association that SCRs could have the same influence on installed capacity prices as other resources.
The commission said the argument is “based on the incorrect assumption that SCRs — which are generally individual or small aggregated sets of ‘resources’ — have the same ability to suppress ICAP market prices as a single, large market participant.”
Commissioner Norman Bay added a six-and-a-half-page concurring statement that questioned the overall efficacy of the MOPR. “I concur with this result but would go further in reconsidering the MOPR’s rationale and applicability in the wholesale electricity markets,” Bay wrote.
He appended a similar statement to another order on Friday that approved a MOPR exemption for renewable energy in ISO-NE. (See related story, Bay Blasts MOPR on Way Out the Door.)
The commission also ruled as moot a request for rehearing and its dismissal of a related NYISO compliance filing (EL07-39-007).
