VALLEY FORGE, Pa. — Stakeholders moved quickly through PJM’s requested endorsements at Thursday’s Planning Committee meeting, approving all three by acclamation. In addition to largely administrative updates to Manual 22, the committee endorsed:
The sunsetting of the Earlier Queue Submittal Task Force, whose Tariff revisions went into effect on Nov. 1. The revisions allow PJM to start feasibility studies sooner and allocate review and study costs to interconnection customers rather than socializing them. “The big problem is that there were [project] requests that were deficient at the end of the window … that’s what was bleeding into the feasibility window,” PJM’s Andrew Gledhill explained. (See “Stricter Standards OK’d for Project Queue Submittal,” PJM Markets and Reliability Committee Briefs.) James Manning of the North Carolina Electric Membership Corp. supported the changes but requested that there be a “feedback loop” to ensure the rule changes are successful in incenting customers to file their requests sooner. PJM said it would provide updates.
Exempting certain transmission substation equipment from competitive bidding. Brenda Prokop of ITC Holdings thanked PJM staff for making sure the revisions got completed.
PPL Removing Jenkins SPS
PPL’s Jenkins special protection scheme, which was installed to protect against overloads on the Susquehanna-Jenkins 230-kV line, is being removed because the line is being rebuilt. The line will be out of service from March through December.
Planning Coordination with MISO Improved
PJM and MISO filed joint operating agreement revisions for the targeted market efficiency project process with FERC on Dec. 30, PJM’s Chuck Liebold said.
“That was a big need. That should be a very beneficial change to expedite the analysis,” Liebold said. “In the past, it has taken months and months to put together an interregional case.”
Previously, PJM and MISO used incompatible analysis criteria. “Now we can go after any type of project on our border and go after whatever is truly the most cost-efficient project,” he said.
Stakeholders asked why there wasn’t a common interregional model. Liebold explained that FERC set it up so that interregional planning is developed from each RTO’s regional planning process, so it would be impossible for them to be the same.
“We’re not disputing MISO’s assumptions or MISO’s processes. … If their stakeholders have decided that’s the basis on which to go forward on a particular study, they can do that. … I think our responsibility is to make sure … that we come up with the best solution that satisfies the [needs] on both sides,” Liebold said.
Transmission Expansion Advisory Committee
New Proposal Shaves $78M from PSE&G Switch Fix
PJM told the Transmission Expansion Advisory Committee it has developed an alternative solution to address the fire hazard at Public Service Electric and Gas’ Newark transmission switch that would cost $275 million, saving $78 million from a proposal outlined previously.
Planners said the switch is considered at the end of its life and failure to replace it could result in a fire that could engulf the substation, which was built in 1957.
A fire would threaten a nearby school and healthcare facility as well as possibly cut service to 300 MVA of load, including Newark City Hall, Rutgers University facilities, Prudential Center, several data centers and two train lines.
A proposal outlined last August called for building a new gas-insulated switch station adjacent to the existing switch at a cost of $353 million.
The new proposal modifies the scope and layout, reducing constructability concerns. PJM said it would save $18 million in direct costs and $60 million in risk contingency expenses. It would be fully energized by June 2021.
PJM Recommends Spending $10M to Correct AEP Voltage Problem
PJM said it is recommending installing 300-MVAR reactors at American Electric Power’s Ohio Central and West Bellaire 345-kV substations at a cost of $5 million each. Planners said the reactors were needed to correct high voltages on the extra-high-voltage system in AEP’s service territory during light load conditions. PJM is targeting a Sept. 1, 2018, in-service date.
CARMEL, Ind. — MISO is looking to improve its annual resource adequacy survey by expanding the scope of potential projects included in the report, but some stakeholders are still questioning the survey’s credibility.
The survey — a joint undertaking between MISO and the Organization of MISO States — tracks resource adequacy through reports made by load-serving entities. The 2016 survey forecasted a possible capacity shortfall in the RTO by 2018. (See OMS-MISO Survey: Generation Shortfall Possible.)
The RTO wants to include more potential future resources in the survey’s regional and zonal weighted averages, Darrin Landstrom, MISO’s resource forecasting adviser, said during a Feb. 8 Resource Adequacy Subcommittee meeting.
Landstrom said the survey currently counts only future resources that have already executed a generator interconnection agreement. The RTO is also considering rolling a 35% share of the capacity from resources sitting in the definitive planning phase of the interconnection queue into the survey’s low-certainty resource total.
Using a sample of natural gas projects entering the queue in 2012, 37% failed after entering the definitive planning phase, while 26% ultimately executed generator interconnection agreements. According to Landstrom, the sample left MISO with a possible percentage somewhere between a conservative 26% success rate to a best-case 63% (assuming every project that enters the definitive planning phase will sign a GIA).
MISO’s use of the 35% value in the 2017 survey would be re-examined next year after the RTO completes the launch of its new queue process.
The RTO had additionally considered the idea of including in the survey projects in the system planning analysis stage of the interconnection queue, active projects in the queue that have yet to sign interconnection agreements and planned projects not yet in the queue.
Some stakeholders argued that the 35% figure was arbitrary.
“Ultimately, the OMS-MISO survey is a range of possibilities,” responded Laura Rauch, MISO manager of resource adequacy coordination.
Asked by RASC Chair Gary Mathis whether the proposal had OMS’s support, Bonnie Janssen of the Michigan Public Service Commission responded that the proposal largely represented the RTO’s work.
While stakeholders expressed concern that no planned resources in the definitive planning phase make it into the survey’s high-certainty category, Landstrom pointed out that projects in the definitive planning phase with generator interconnection agreements are counted among high-certainty resources.
Rauch said MISO does not want to imply that planned projects are “a done deal” by assigning them high-certainty designations. She said the move could send the wrong signal to state regulators, who might reject other projects because they assume the likelihood of a planned project included in the survey with high-certainty status.
Wisconsin Public Service’s Chris Plante said MISO might be able to issue information without editorializing by discontinuing high- or low-certainty designations, which some stakeholders think gives the survey a conservative bias that suggests a resource adequacy problem.
Mathis contended that people tend to pay attention to what’s high-certainty rather than low-certainty.
“Is the load growth in the survey high-certainty?” he jokingly asked.
Rauch said that while MISO is focused on signed and committed projects, the survey could concentrate more on a range of possibilities.
In filings made last year to oppose MISO’s retooled auction design, the Coalition of MISO Transmission Customers and the Illinois Industrial Energy Consumers said the survey does not give a “complete reflection of the future capacity needs in the MISO region.” Stakeholders also questioned why last year’s capacity auction results showed a larger surplus than the survey results for a second year in a row.
Jeff Bladen, executive director of market services, said MISO “remains confident” that the survey is the best forward-looking predictor of resource adequacy.
WASHINGTON — Modest optimism about the Trump administration’s infrastructure plans was tempered with questions about leadership at FERC and other federal agencies at a gathering of transmission developers, RTO officials and environmentalists last week.
The first National Electric Transmission Infrastructure Summit, held Feb. 9-10 by Americans for a Clean Energy Grid, also heard concerns over how to pay for grid modernization in a time of anemic load growth. The organization, an initiative of the Energy Future Coalition, has held regional transmission conferences, but this was its first national event.
The coalition was formed in 2002 by former Sen. Tim Wirth, a Colorado Democrat; Republican C. Boyden Gray, who served as White House counsel to President George H.W. Bush; and Democrat John Podesta, a former aide to Presidents Bill Clinton and Barack Obama who chaired Hillary Clinton’s 2016 presidential campaign.
“I’d love to have more load growth. It ain’t going to happen,” Craig Glazer, PJM’s vice president for federal government policy, told the gathering.
Weak load growth will make it more complicated to finance upgrades for aging transmission, and the lack of a federal carbon tax or renewable mandate is making it difficult to integrate renewable generation, Glazer said.
Much of the current grid was built during the 1950s, 60s and 70s, with the deployment of coal and nuclear power plants, said ITC Holdings Executive Vice President and COO Jon Jipping. Now that many of those big baseload stations are being retired, much of the new generation — mostly natural gas or renewable energy — is in different locations that require new transmission, Jipping noted.
From the podium and on the sidelines, speakers said that while they like the Trump administration’s pro-growth rhetoric, they are also anxious to see FERC restored to full strength and who will be the key lieutenants to energy secretary nominee Rick Perry.
Speakers also cited concerns over cost allocation, regional planning and the shortcomings of FERC Order 1000.
Wade Smith, senior vice president of grid development for American Electric Power, said his company has made transmission a higher investment priority than generation in recent years as it focuses more on regulated utility operations.
Modernization is needed because much of the AEP grid is 70 years old, and yet it integrates 9,000 MW of wind, Smith said.
While much of the U.S. electric transmission system was built in the mid-20th century, the infrastructure components are inspected every year, said Rudy Wynter, National Grid’s president of FERC-regulated businesses. The grid was built in big chunks and it will largely be rebuilt in large chunks, Wynter said. This includes not only renewable integration but also preparing for more electric vehicles and offshore wind power, he added.
Siting Authority
During one session, SPP CEO Nick Brown was interviewed by former FERC Chairman James Hoecker, now senior counsel for WIRES Group, which represents transmission developers and utilities. Hoecker stressed the importance of adding three commissioners to get FERC back to full strength. With only two commissioners since the Feb. 3 resignation of former Chairman Norman Bay, FERC lacks a quorum. (See FERC OKs Pipelines, Delegation Order Before Losing Quorum.)
Hoecker and Brown discussed FERC’s inability to gain “backstop” siting authority, saying it’s still very difficult to prevent individual states from blocking a project. The Energy Policy Act of 2015 amended the Federal Power Act to give FERC the authority to site electric transmission lines blocked by states, but court rulings have blocked the commission’s attempts to use it, prompting some in Congress to propose additional legislation strengthening FERC’s authority.
Brown said that Order 1000 hasn’t really helped SPP much with large regional projects.
“We need to decide what we want this grid of the future to look like,” Glazer said. For example, should it be a “localized grid” that can harness distributed generation? he asked. “There’s an added complication; it’s not even clear who is in charge,” Glazer said. FERC, state utility commissions and governors all have a say in siting decisions, he said.
If each governor is asked what infrastructure projects they want, the country will end up with a lot of state-based projects, not interstate ones, Clean Line Energy Partners President Mike Skelly said.
Perhaps the new mantra is “we’re going to make transmission great again,” Skelly said. The power to select infrastructure projects should not be taken away from transmission planners and placed in the hands of Congress, he said.
Skelly and others cautioned the Trump administration not to skimp on project reviews or stakeholder input. The key is that all projects must have “timelines” for regulatory approvals to avoid infinite delays, he said.
The executive director of the AFL-CIO’s Industrial Union Council, Brad Markell, said the labor movement agrees with the need for “hard timelines” to shorten the permit process.
Markell said that labor unions have been in contact with the Trump administration on potential infrastructure efforts.
“From our point of view, more power for the federal government and less power for the states [on electric infrastructure] would be a good thing,” he said.
Others deemed that unlikely. “I think we’re stuck with the system we have,” Glazer said.
Environmentalists Weigh In
Liese Dart, senior energy advisor for The Wilderness Society, said her organization favors prescreening certain public lands for development suitability.
Mary Anne Hitt, executive director of the Sierra Club’s Beyond Coal campaign, said that — contrary to what conference participants may have heard — her organization doesn’t oppose all power lines, only those that appear aimed to “prop up fossil fuels.”
The environmental group opposed the abandoned “coal by wire” Potomac-Appalachian Transmission Highline (PATH) project in PJM. On the other hand, it has backed the Plains and Eastern Clean Line Project, designed to move renewable energy from Oklahoma to Tennessee.
Hitt said she was concerned that President Trump’s nominee for EPA administrator, Scott Pruitt, opposed Clean Line in 2015 as Oklahoma attorney general.
Hitt also said the Sierra Club has concerns about the Gateway West project, a proposal by PacifiCorp and Idaho Power to build about 1,000 miles of high-voltage transmission through Wyoming and Idaho. She said PacifiCorp has been slower than some Western utilities in reducing its coal use and slower than the Sierra Club would like in expanding its renewable resources.
Grid Security
When it comes to protecting the grid, Brown said much of the discussion seems to be centered on preventing cyber intrusions. Perhaps the discussion should be less about how to keep cyber intruders out than to minimize the damage and restore order once they disrupt the system, the SPP official said, likening the approach to “insurance.”
But he said winning regulatory approval for equipment such as spare transformers may be difficult.
“I believe we are going to have to spend much more money on spare equipment, and that’s going to be tough to sell,” Brown said. “We are unwilling to spend that kind of money for spare equipment because it is not ‘used and useful.’”
SPP Chief Reticent on Mountain West
Brown declined to reveal much about the status of the Mountain West Transmission Group’s discussions about joining SPP.
Mountain West, a partnership of seven transmission-owning entities within the Western Interconnection, revealed the discussions in January. It said if the talks with SPP are not successful, it would likely explore joining another RTO. (See Mountain West to Explore Joining SPP.)
In response to a question about whether Mountain West was attracted by SPP’s cost-allocation system, Brown replied, “You’d have to ask them.”
“We’re excited about it,” Brown said of the talks, before cautioning, “Nothing is signed.”
CARMEL, Ind. — MISO’s South-to-Midwest transfer limit for the 2017/18 Planning Resource Auction will be 1,500 MW, an increase of more than 600 MW over last year’s auction because of a decrease in firm export and wheel-through reservations. The limit reflects the 2,500-MW cap prescribed by MISO’s settlement with SPP, reduced by 1,000 MW of reservations.
MISO is modeling two sub-regional resource zones for the 2017/18 PRA: MISO South (local resource zones 8, 9 and 10) and MISO Midwest region (zones 1-7).
The Midwest-to-South limit for the 2017/18 PRA will hold at 3,000 MW, with zero reservation offsets.
MISO is looking to align its Attachment Y retirement process with the PRA timeline, implementing a recommendation from the Independent Market Monitor’s 2013 State of the Market Report.
At the Feb. 8 Resource Adequacy Subcommittee meeting, MISO adviser Joe Reddoch said the RTO is considering extending a cancellation period offered to retiring resource owners to align with the release of the upcoming PRA results to give owners a limited window to change their minds regarding retirement.
The Monitor recommended improving the alignment of the PRA and the retirement process so that a unit that has filed retirement plans can defer the retirement date if it clears in the auction. It also said system support resource (SSR) units should retain their interconnection service after their contracts end to allow the “broadest possible participation” in the PRA.
Reddoch said MISO has not yet settled on the length of the cancellation window extension.
The RTO is also contemplating removing the distinction between suspension and retirements in favor of a single deactivation status, Reddoch said. The change would eliminate “conflict between documented plans and the owners’ actual intentions,” he said. The change would simplify the process between temporary, uncommitted shutdowns and pending retirements, according to MISO.
RTO officials said the change would reduce uncertainty in planning processes, with baseline reliability projects being reprioritized if not needed because of a later rescission. Upgrades needed for new generation interconnections would be determined by the known plans of retiring generators.
The issue will be discussed at the Feb. 15 Planning Advisory Committee meeting and referred to the Steering Committee for assignment to a parent committee, Reddoch said.
CAISO’s first pass at soliciting stakeholder input on its primary frequency response product initiative generated a wide-ranging discussion about an obscure but increasingly important aspect of the ISO’s operations.
“We know that [primary frequency response] is important to your fundamental role as a balancing authority, and currently there are no financial incentives to provide this critical service,” Alex Morris, director of policy and regulatory affairs at the California Energy Storage Association (CESA), said during a Feb. 9 presentation to a stakeholder working group convened to lay the foundation for a market proposal.
CAISO is seeking to develop a market mechanism to compensate resources for responding to frequency dips during the “primary” control horizon — just moments after the onset of the event.
“And I don’t mean to be trite, but what we’re seeing from the data is that it’s no longer workable to assume the primary frequency response service will be provided — quote — ‘for free,’” he added.
Inertial Response
By “free,” Morris was referring to the fact that grid operators have benefited from the “inertial” frequency response capability inherent in the operation of most conventional generators, which can automatically vary their turbines’ rotational speed and output based on the pull of load, functioning as a damper for frequency excursions on the grid.
Nonconventional technologies such as wind and solar resources have little or no inertial response to momentary changes on the grid. Late last year, FERC proposed revising pro forma generator interconnection agreements to require all newly interconnecting facilities, including renewable generators, to have primary frequency response capability (RM16-6). (See FERC: Renewables Must Provide Frequency Response.)
“It’s probably been great that for many decades [frequency response] came along as part of the generation fleet for free and that’s how it worked, but unfortunately we’re in a different era with a different grid and we need to wrestle with this problem,” Morris said.
NERC reliability standard BAL-003-1.1, which was phased in between November 2015 and last April, requires each balancing authority area (BAA) to carry sufficient capability to respond to a frequency event. Meeting that requirement will become increasingly difficult as California’s 50%-by-2030 renewable portfolio standard drives increased penetration of renewable resources.
The NERC rule requires BAAs to respond to a deviation within about 20 to 52 seconds of occurrence. That rapid reaction requires a resource to automatically detect under-frequency and autonomously ramp its output without receiving a market signal or manual instructions from the ISO.
Procurement Needed
An issue paper published by CAISO in December laid out the ISO’s deteriorating frequency response performance in recent years and raised the alarm of further declines. (See CAISO Seeks Primary Frequency Response Market.)
“Without explicit procurement of primary frequency response, the ISO cannot position our fleet in a way that will provide sufficient frequency response,” said Cathleen Colbert, senior market design and regulatory policy developer at CAISO. “We need to also mitigate the risk of noncompliance” with the NERC standard.
“We’re concerned about continuing to rely solely on procuring this adjustment in the long term,” Colbert said. Instead, CAISO seeks to provide internal generators with the ability to compete against external BAAs to provide the service.
In his presentation to the working group, Morris sketched out a preliminary proposal in which the ISO would develop a product that would incentivize frequency response capability and performance while compensating resources for their opportunity costs — for example, forgone energy market revenues.
Under the plan, the CAISO day-ahead and real-time markets would solve for current constraints and products while also reserving capacity from resources capable of providing primary frequency response. The market would compensate those resources for the service, as well as the energy injected during a frequency deviation event, similar to the energy settlement for regulation service resources that follow a dispatch order.
Regulation Service
“I thought that regulation was simply a zero-energy service,” said Mark Smith, vice president of government and regulatory affairs at Calpine.
George Angelidis, a principal at CAISO, explained that the energy a regulation service provider gives and takes from the grid should, in theory, sum up to zero, which is why regulation is considered a control service rather than an energy service.
“But there’s a capacity behind it, and through the energy provision, you provide the control service, but the expectation is that over a long period of time it’s more or less a zero-energy service,” Angelidis said.
“The general high-level view is that this resource is sitting at the ready — [and] frequency drops,” Morris continued. “The resource autonomously bursts out energy to provide the primary frequency response. In so doing, it’s giving energy to the grid. It may be appropriate to compensate [the resource] for the energy it gave to the grid.”
Biddable or Not?
Morris acknowledged that he avoided taking a position on whether frequency response provision should be biddable in the market on a standalone basis.
“I think as long as it’s being solved for inside the market — it’s co-optimized among the many other constraints in the market — then the opportunity cost of providing this service is then reflected,” Morris said. “So there would be some element of payment for providing this service, whether that’s just an opportunity cost, if any, or not.”
Jan Strack of San Diego Gas & Electric questioned the effectiveness of a “non-biddable” solution.
“The issue is, if you don’t have a bid, I think the market has no ability to select,” Strack said. “Which [resource] would it select? There’s no way to know. So I think you inevitably end up with a capacity offer situation just like you do with regulation.”
“I hear you,” Morris responded. “But I also think just the information about the energy costs will inform the optimization, similar to how with the [CAISO] flexible ramping product you can bid your flexible ramping capability for zero dollars, but you also have an energy bid, so [the market] knows if you have an opportunity cost.”
Smith wondered whether a generator that did not receive an award would be allowed to disable its frequency response capability, as it would automatically respond to an event.
“Basically, we make sure that you provide the service all the time, but if while you provide the service you suffer a lost opportunity cost for it, then you will be compensated adequately for it,” Angelidis said, adding that disabling that capability could run “contrary” to a generator’s interconnection agreement.
In comments filed with CAISO, Seattle City Light — which currently provides the ISO with transferred frequency response under a yearlong contract — said it hoped the ISO would develop a market mechanism that would allow transferred capability to compete with internal resources.
Mike Benn, energy trade policy analyst at Powerex, backed up City Light’s position.
“We’re supportive of what CESA said to co-optimize the procurement of frequency response in real time, but we think there would be a gap there and we’d like a forward procurement mechanism as well, similar to the [resource adequacy] construct,” Benn said. “So you could go out and procure on a year-ahead basis, and then they could procure from internal [resources], or they could also go and procure from external BAs.”
The “gap,” according to Benn, stems from the fact that short-term procurement of frequency response won’t guarantee resources will be available on a given day and might be insufficient to spur development.
“The transferred response from external BAs is a yearly product,” Benn said. “So in that way, when you get to real time, you’ve guaranteed that the resources are available.”
Benn pointed out that the absence of a forward procurement option would exclude the participation of external resources because NERC’s frequency response reporting requirement is based on an annual obligation that cannot be transferred on a daily basis. FERC recognized this fact on Feb. 2, when it approved the terms of CAISO’s transferred frequency response contracts with City Light and the Bonneville Power Administration. (See FERC OKs CAISO Frequency Response Contract Terms.)
“I think the two processes — a market mechanism and a transferred frequency response mechanism — aren’t mutually exclusive, and it’s probably good to think about them in that sense,” said Andrew Ulmer, CAISO director of federal regulatory affairs. “From a relatively non-engineering, non-market design perspective, I think of both as insurance mechanisms.”
CAISO has asked stakeholders to submit comments on the primary frequency response initiative by Feb. 23. A second working group meeting on the issue will be held on a date yet to be determined.
SPP will juggle a number of studies and reviews with its seams neighbors this year, following a 2016 filled with “lots of good stakeholder engagement.”
Adam Bell, SPP’s interregional coordinator, told the Seams Steering Committee last week the major effort could come with MISO. Besides the usual joint studies and regional reviews, the two RTOs could engage in a targeted market efficiency project (TMEP) study, similar to that between MISO and PJM. (See MISO-PJM TMEP Projects Drop to Five.)
Bell said he was not certain whether it would be separate from the joint study already planned for 2017 or rolled into it.
“We’re still talking about it,” he said.
SPP and MISO are already working on a targeted coordinated system plan (CSP) that is considering seven potential projects. If the two RTOs agree to move forward on any of the projects, SPP would conduct a separate evaluation allowing stakeholders and the Board of Directors to verify benefits and costs for the RTO. If none of the seven projects moves forward, the RTOs’ staffs will use the CSP results as an input into the 2017 joint study. (See SPP-MISO IPSAC Turns Attention to 2017 Study.)
Bell said the joint study will begin in April and will be “a pretty lengthy process. … We both agreed to a broader, much more comprehensive look following the 2016 study.”
The two RTOs will discuss that during their next Interregional Planning Stakeholder Advisory Committee meeting March 9 in Metairie, La.
SPP and Associated Electric Cooperative Inc. wrapped their joint CSP in January, identifying two projects near Springfield, Mo.: a 50-MVAR reactor at Springfield’s 345-kV Brookline substation, and a new 345/161-kV transformer at an AECI substation and an uprate of a related 161-kV line.
The SPP Board of Directors and Markets and Operations Policy Committee both approved the project in January, but it must still go through a regional review.
SPP also meets twice a year with Southeastern Regional Transmission Planning process representatives. The organizations review their regional planning processes, determine whether a study is needed and, toward the end of the year, exchange data.
M2M Report
Staff’s monthly market-to-market report showed MISO piled up its third biggest month yet of M2M payments to SPP in December, with 444 hours of binding resulting in a $1.98 million payment to its neighbor. Temporary flowgates again accounted for most of the payments, with 128 binding hours costing $1.65 million.
MISO has made $14.2 million in M2M payments since the two RTOs began the process in March 2015.
New Representatives Welcomed
The Seams Steering Committee welcomed two new representatives: Nebraska Public Power District’s Dustin Betz and Empire District Electric’s Tina Gaines.
SPP is using a new medium to explain its Integrated Transmission Planning (ITP) process: a web-based application summarizing a 200-page technical report with appealing graphics and less industry jargon.
Director Antoine Lucas and his transmission planning group developed the 2017 ITP10 story map to simplify the 2017 10-year assessment, which was presented to the MOPC and the board in January. Titled “Strengthening the Grid,” it has been viewed almost 700 times since being published just before the Jan. 31 board meeting.
“We have a diverse audience of stakeholders, ratepayers and regulators,” said Lanny Nickell, vice president of engineering. “It’s crucial that we present the information on which they base their decisions in a way everyone can fully understand and appreciate, especially as our studies become increasingly more comprehensive and complex.”
A team of SPP geographic information systems experts and analysts used the Environmental Systems Research Institute’s Story Maps application to produce a contemporary web design with industry mapping tools already used to visualize Bulk Electric System components. Engineering and communications staff worked together to distill the 2017 ITP10’s assumptions, approach and conclusions.
SPP Sets New Winter Generation Mark
SPP set another record for wind generation Feb. 9 when the footprint produced 13,342 MW of energy, smashing the previous record by more than 1,000 MW. The mark came at 9:34 p.m.
It was SPP’s first wind record for 2017. It established six peaks last year, the last coming Dec. 30 at 12,336 MW.
The Public Utility Commission of Texas last week granted Lubbock Power & Light’s request to delay a decision on who will pay for studies related to the municipality’s planned move to the ERCOT grid.
In a letter to the commission, LP&L asked that the assignment of study costs be held until ERCOT and SPP can finish separate cost-benefit studies on the potential move (Project 45633). The municipality said the two grid operators have not agreed on a common assumption for gas prices, “a key variable,” and said that the studies will indicate “the extent to which the LP&L integration into ERCOT would benefit customers in both systems.”
“Deciding who should pay the cost of the studies now, in the absence of that information, would mean assigning the cost of the studies to LP&L before it is known whether consumers in SPP and ERCOT would benefit from the transition,” LP&L said.
“I’m OK with waiting,” said Chair Donna Nelson during the PUC’s Thursday open meeting, echoing the position of the other two commissioners.
LP&L announced in September 2015 it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. An ERCOT analysis completed last June indicated it will cost $364 million and take 141 miles of new 345-kV rights of way to incorporate LP&L into the Texas grid. Both ERCOT and SPP are currently conducting separate studies on their systems with and without LP&L’s load. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
The utility, which plans to conduct its own study, said it “continues to expect that, on a net basis, the system transition that LP&L seeks will present quantifiable benefits to consumers in both the SPP and ERCOT systems.”
In a separate letter to the PUC laying out their respective study scopes, ERCOT and SPP estimated the combined analyses would cost between $225,000 and $255,000. The grid operators said they have assigned internal project codes to track the hours incurred for the studies and promised a final accounting to the commission.
Commissioner Ken Anderson noted SPP planned to perform its production-cost analysis with and without forced generation outages, but ERCOT would do so without taking the outages into account. Asked what the likely variance would be, ERCOT Senior Director of System Planning Warren Lasher said he didn’t think it would be a “game-changer.”
“You will be able to look at the two results and be able to see the difference, but often, it’s not going to change your decision,” Lasher said. “ERCOT doesn’t do this because it is complicated to do. You need to have very accurate data regarding outage rates, which is something we’ve had significant difficulty getting from market participants.”
Lasher said the difference in outage-rate data may also be “a function of the different market designs we have in the SPP region and the ERCOT region.”
The grid operators’ studies are expected to be completed by midyear.
Hand-Held Devices Allowed to Enroll Retail Customers
The commissioners adopted a change to the PUC’s administrative rules that will allow retail electric providers (REPs) to use laptops, tablets, smart phones and other hand-held devices to enroll customers (Project 45625).
The rulemaking came with a warning, however. “I’m going to be watching,” Nelson said.
The PUC chair added language that requires the REPs to “accurately and truthfully answer any questions” when giving customers an opportunity to review the enrollment documents.
“To the extent we get complaints about this, it’s not going to be something we look on favorably,” she said. “We want to make sure the customers get what they need.”
SPS Details Winter Storm Restoration Effort
Southwestern Public Service briefed the PUC on its recovery efforts following January’s winter storm, which left 58,000 of its customers in the Texas Panhandle without service and damaged 7,500 poles and other structures.
Transmission lines after the January 2017 Ice Storm | SPS
Evan Evans, SPS’ regional vice president of rates and regulatory affairs, said the company was prepared for the storm and its forecast of one-tenth of an inch of ice. The storm began with rain Jan. 13, transitioning into freezing rain and bitter cold through Jan. 15 that resulted in up to 3 inches of ice in some areas.
“It was a major ice storm … the worst residents said they had seen in over 50 years,” Evans said.
SPS used almost 1,100 employees, contractors and mutual aid partners to restore service to all its customers by Jan. 23. Evans said cellphone communication problems and waiting on electricians to repair damage on the customers’ lines and meters slowed the restoration effort.
Evans said the company upgraded its infrastructure standards in 2014 and will look for ways to improve its communications and further harden its facilities. He pointed out some neighboring utility customers are still waiting for service that may still be a week or two away.
Working to restore service after the January 2017 Ice Storm | SPS
“Your team did a tremendous amount of work in very dangerous conditions,” Commissioner Brandy Marty Marquez said.
“I’m amazed that you have people that have been out [of power] for seven days asking us if we were OK,” Evans said. “They see us working around the clock.”
Fines Approved, Cybersecurity Program OK’d
The commission’s consent agenda included approval of fines against Luminant Energy and Oncor Electric Delivery, once sister companies under bankrupt Energy Future Holdings.
Luminant agreed to an administrative penalty of $170,000 for not updating its ancillary service schedules 11 times in 2015 after ERCOT issued instructions to do so (Docket 46724). Oncor agreed to a $288,500 penalty for falling short of benchmarks on the length and frequency of outages for 2015 (Docket 46733).
The PUC also gave Executive Director Brian Lloyd the authority to negotiate and implement a contract to develop “a comprehensive cybersecurity and physical security outreach program” for Texas utilities, cooperatives and municipalities (Docket 46773).
VALLEY FORGE, Pa. — PJM has made several changes to its proposed planning process for competitive transmission projects in response to stakeholder feedback, staff said Friday.
At a special Planning Committee meeting on redesigning the Regional Transmission Expansion Plan and the Transmission Expansion Advisory Committee, PJM’s Fran Barrett said the RTEP “is not just about [FERC] Order 1000.”
“The RTEP has been in service for 18 years. It’s served us well, but the market is changing,” Barrett explained. “We have heard you. [The redesign] is not just going to be about technology. It’s going to be about timing; it’s going to be about interactions.” (See PJM Proposal Would Lengthen Reliability RTEP Cycle.)
The changes would be detailed in a proposed Manual 14F. Among the changes is considering cost containment in the project selection phase, the details of which have not been finalized. “At this point, we have not made an effort to [separately] define ‘cost cap’ and ‘cost-containment mechanism,’” PJM’s Mike Herman said.
Alex Stern of Public Service Electric and Gas cautioned against creating a “race to the bottom” by selecting projects for having the lowest cost cap.
GT Power Group’s Dave Pratzon asked how the evaluation standards will be applied to what he called “squishy” situations, where the costs and benefits of a proposal might not be straightforward.
“How incidental a failure in PJM’s initial study does someone have to have before” the project is rejected? he asked.
Herman agreed that more consideration could be applied to the issue but said the manual can’t anticipate all possible situations. “I think we could get into lots of detailed discussions about ‘odd’ situations,” he said.
Removing supplemental projects as a criteria driver, a response to stakeholders who said such projects don’t fit with market efficiency projects and should have their own diagram;
Including a footnote that explains how public-policy decisions factor into the public-policy criteria driver;
Adding “evaluation of impacts on other projects” into PJM’s factors for consideration, with a focus on whether the proposal alleviates the need for a supplemental or previously approved baseline project; and
Moving “stakeholder review” from the TEAC recommendation phase to one of the factors for consideration, to emphasize the importance of ongoing stakeholder feedback.
Stern reiterated his suggestion that the manual be limited to market efficiency projects.
“I’m not intending that we stop the discussions on reliability. In my mind, that’s going to take longer,” said Stern, who offered his own edits to the proposed manual.
“We thought there were a lot of similarities [between reliability and market efficiency projects] both on the front end and on the back end,” Herman said. “They still fall within the same decisional thinking process. … We felt it made most sense to put it all together in one manual.”
Decisional Process Map | PJM
“We think it’s prudent to put the language together so you can see the differences,” Barrett added.
Other stakeholders agreed they preferred a single document. “That kind of leans me back toward ‘Let’s do this all together,’” PJM Public Power Coalition’s Carl Johnson said.
“Can I just say ‘what Carl said,’ or do I have to repeat it?” Calpine’s David “Scarp” Scarpignato said.
FirstEnergy’s John Syner also leaned toward a single manual, but he said incumbents should be given “brownie points” such as basis points for their longevity and reliability.
“I don’t know how you can put a manual together and be able to give all of those ‘brownie points,’” he said, adding that it likely will need to occur during transmission owner prequalification and would require a Tariff change.
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.
