VALLEY FORGE, Pa. — PJM’s Patricio Rocha-Garrido last week briefed the Planning Committee on proposed Manual 20 changes to revise how winter peak weeks are calculated.
Staff say the new methodology is necessary because the current “theoretical” approach used in PJM’s PRISM modeling software to estimate RTO-wide generator outage levels during the winter peak does not reflect historical outage levels. Staff proposed using historical outage data to build the winter peak week’s capacity model.
Stakeholders asked for additional data to confirm that PJM has determined the best option.
Rocha-Garrido added that the revisions are only necessary for winter peaks and that he didn’t see any “far-right tail” indicating problems with PRISM’s analysis of summer conditions.
“We took a look at the summer, and we were comfortable with what we saw. What PRISM is doing reasonably matches historical data,” Rocha-Garrido said.
AMP Disappointed with Cancellation of Ratings Discussion
American Municipal Power’s Ed Tatum said he was “exceptionally disappointed” that staff and PC members decided to skip discussion of NERC Standard FAC-008-3, which governs how transmission owners must document their methodologies for calculating facility ratings.
Committee members decided to table it until next month’s meeting after the discussion on incorporating cost containment in transmission planning ran long. (See related story, Cost Containment Proposal Survives; Headed to MRC.)
TEAC Redesign
PJM’s Aaron Berner walked through revisions to Transmission Expansion Advisory Committee processes to increase transparency and opportunities for stakeholder input.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, voiced his approval of the changes.
“It’s very noticeable. You’ve done a great job,” he said of PJM’s efforts to provide information sooner.
Tatum suggested adding information to templates that addresses repeatedly asked questions.
“That is definitely one of the things on our mind to try to short-circuit … the need for some of those questions,” Berner said.
Reliability Upgrades Needed for Nuclear Deactivations
Staff said they completed an analysis on the reliability impact of the retirements of FirstEnergy’s Davis-Besse, Perry and Beaver Valley nuclear plants, which the company announced last month. (See FES Seeks Bankruptcy, DOE Emergency Order.)
While the plants can retire as scheduled, transmission upgrades will be necessary, staff said. All projects that will need to be accelerated have been identified. Staff plan to bring details for all upgrades to next month’s TEAC meeting.
All projects will be classified as “immediate need” so they can be in place by the plants’ planned shutdown by the end of 2021, which means they won’t be competitively bid and will be awarded to FE to build.
VALLEY FORGE, Pa. — PJM’s Market Implementation Committee approved manual revisions reducing the number of virtual bidding locations by almost 90%, a change approved by FERC in February to address uplift (ER18-88). (See FERC OKs Slash in Virtual Bidding Nodes for PJM.)
PJM’s Keyur Patel presented the revisions to Manual 11, which include a link to a list of the eligible locations. The changes reduce the number of bidding locations for increment offers (INCs) and decrement bids (DECs) from 11,727 to 1,563, retaining all hub and interface nodes but eliminating some aggregate and generator nodes. The number of up-to-congestion transaction (UTCs) trading points was reduced to 49 from 418.
Stakeholders approved the revisions by acclamation.
Intraday Offers
PJM’s Susan Kenney discussed other proposed revisions to Manual 11 that staff are trying to move quickly through the stakeholder process to expand the window for submitting generation offers.
Procedures implemented by PJM on April 5 to accept intraday offers limited when generators could submit offers with hourly differentiated minimum run time, notification time and minimum downtime to after the day-ahead reliability run and up to 65 minutes before the dispatch time.
Generators asked that PJM also allow submitting that information before day-ahead offers are due and during the afternoon day-ahead rebid window. PJM plans to make this change by eliminating manual language that restricts the submission timing but also clarifies that those values are used only in real-time commitment and dispatch.
“I appreciate PJM’s efforts to reinstate what I think were some unintended consequences,” NRG Energy’s Neal Fitch said. “The alternative right now is I don’t have an ability to tell PJM this information absent calling them up about every unit.”
Adrien Ford with Old Dominion Electric Cooperative agreed the revisions restore efficiency.
Offer Cap Resolution
Responding to stakeholder reservations about returning to previous language on cost-based offer caps, PJM has developed a new plan that members found acceptable. The Manual 11 revisions, which were approved by acclamation with two abstentions, will cap all offers at $1,000/MWh by default. Generators will be able to submit requests for higher cost-based offers, which PJM will screen and allow if validated.
For price-based offers, generators will have a choice: Either select “Switch to Cost” to exclude price schedules from dispatch — the option that PJM “strongly” suggests — or request the ability to submit price-based offers in line with verified cost-based offers. Kenney cautioned that sellers will be responsible to ensure the price-based offer at each segment remains compliant with verified cost-based offer caps.
Kenney acknowledged that the interaction between cost- and price-based offers is “very intertwined” and that staff are still seeking better ways to help verify offer validity.
Catherine Tyler from the Independent Market Monitor unsuccessfully urged stakeholders to oppose the stop-gap revisions and instead push for a holistic solution that automatically validates offers. She said there were instances during January’s “bomb cyclone” cold snap in which offer rules were violated, and that software options should be explored “to ensure there’s automatic compliance.”
“I think everyone would like to see Markets Gateway [PJM’s offer-submission software] take care of this problem,” Tyler said. “We all want to be in the same place at the end, but we do think there’s a different path forward.”
PJM’s Brian Chmielewski presented staff’s proposed manual language for replacing terminated nodes that are part of financial transmission right paths. An overview of the plan was presented at last month’s meeting but lacked proposed language. (See “Nodal Mapping,” PJM Market Implementation Committee Briefs: April 4, 2018.)
Direct Energy’s Marji Philips, who has repeatedly raised concerns with PJM’s previous plans to address this issue, voiced her approval for the updated plan and thanked PJM for working through it.
Long-term FTR Considerations
Chmielewski also presented PJM’s proposal to change the RTO’s long-term FTRs auction process and modeling practices. The IMM’s Howard Haas called the proposal a “vast improvement” but also offered two proposals that he said “may be better.”
Both of the IMM’s plans would follow PJM’s proposal for the first year forward, but years two and three wouldn’t be biddable. Both proposals would remove the “year all” option that allows bidding on a compilation of all three years. Haas suggested this would give bidders “optionality” should system conditions change unexpectedly because “right now, you can be locked into three years.”
Revenue would be allocated to load in either plan, though FTR volume in the second proposal would only be available through counterflow FTRs.
“The model would start with a net-zero transfer capability on a path, so any created capability for years two and three would have to come from counterflow positions,” Haas said. “In that case, the expectation is that there would be no net revenue available to allocate anywhere, but if there was any, you’d allocate it to load.”
Chmielewski said PJM would have to analyze the IMM’s proposals before deciding whether to support them.
Stakeholders pushed back on the IMM’s proposal.
“I encourage people to take a look at Package A [PJM’s proposal] and consider supporting it,” said Exelon’s Sharon Midgley, who called for preserving the priority rights for load and retaining the term of the existing long-term FTR construct. “The value and the importance of having the financial hedging instrument for market participants with physical generation and customers … is probably equally important to maintaining load’s priority rights, which is why we prefer A. … Firms that have generation and customers, their ability to secure hedges is going to severely limited” in the IMM’s plans, she said.
Philips endorsed PJM’s request for quick action on the proposal, urging stakeholders to “not let the perfect get in the way of the good.” She hoped to have the revisions in place for the upcoming FTR auction in June.
“If we go the method of using counterflow to provide liquidity in the auction, we’re actually going to reduce liquidity,” Vitol’s Joe Wadsworth said, noting that use of counterflow to match prevailing flow resembles how the over-the-counter market works. “There’s not much liquidity in the over-the-counter markets.”
He also voiced concerns about losing transparency. “I fear that if we go the route of relying on counterflow in order to get prevailing flow in an auction, we would lose a lot of the transparency that exists today,” he said.
ODEC’s Ford said she favored PJM’s proposal since the IMM also endorsed it, even if it thought it had a better idea, American Municipal Power’s Steve Lieberman said, “any of these packages is preferable to the status quo.”
FTR Forfeitures
Midgley and Mike Borgatti, representing NextEra Energy, proposed sensitivity tests for analyzing PJM’s FTR forfeiture rule to determine if it’s overly restrictive and foreclosing legitimate trading. Exelon won MIC endorsement in March for a problem statement and issue charge to analyze the rule. (See “Exelon-backed Analyses Approved,” PJM Market Implementation Committee Briefs: March 7, 2018.)
Borgatti and Midgley argued that an overly restrictive forfeiture rule might cause competitive suppliers to add a “risk premium” to customer costs and could reduce the value of load’s auction revenue rights (ARRs) if market participants bid less for affected FTRs.
“You can’t efficiently hedge off the cost of load in the energy market, and so the result of that FTR forfeiture is inefficiency that’s going to show up ultimately as an additional cost to consumers as a risk premium,” Borgatti explained.
“We’re trying to become better educated on why we’re seeing the market outcomes [of increased forfeitures] that we’re currently seeing,” Midgley said. “We’re not really sure exactly what is wrong. I know that my firm is being impacted, and we’re seeing significant levels of forfeitures that we’ve never seen before. And it’s preventing us from using INCs and DECs and FTRs to manage legitimate business risks.”
The stakeholders proposed doing sensitivity analyses to test components of the forfeiture procedure. Borgatti compared it to determining school-zone speeds that are both safe for pedestrians and equitable for drivers.
However, IMM Joe Bowring argued that the rule is curbing behavior as it’s intended to. He offered to discuss with individual market participants how the rule was applied to their portfolio and pointed out that forfeitures have declined since the introduction of the new rule as participants have come to understand it better.
“Simply the fact that somebody is doing something doesn’t make it legitimate. The fact that somebody is managing risk doesn’t make it legitimate,” he said.
Bowring also questioned whether the intent of the initiative is to figure out how to bypass the rule.
Midgley and Borgatti denied that motivation. “I don’t think it’s either of our companies’ intent to create a cookbook for how to game the rule,” Borgatti said.
Chmielewski said PJM remains confident in its compliance filing to address FERC’s January 2017 ruling on the issue, though the commission has yet to rule on it (EL14-37, ER17-1433). (See FERC Orders Portfolio Approach for PJM FTR Forfeiture Rule.)
Stakeholders approved manual changes supporting the compliance filing in September. (See “Stakeholders Endorse Manual Revisions,” PJM MRC/MC Briefs: Oct. 2, 2017.)
Despite that, he said PJM is willing to consider alternative perspectives. He presented an analysis that showed changing the rule’s sensitivity for its virtual test from 0.1 MW to 10 MW — or 10% of the line’s day-ahead binding limit if it’s greater — would have cut forfeitures in half and eliminated forfeitures for 12 of 67 market participants penalized. Forfeitures for September 2017 would have been reduced by half, from roughly $2 million to roughly $963,000.
“Really what this trigger is doing is if you’re looking at any binding constraint in the day-ahead market with a 100-MW limit or less, you’re basically saying it has to have a 10-MW or more impact, which may or may not make sense depending on how you look at it,” Chmielewski explained.
Under questioning from stakeholders, he acknowledged that the issue could benefit from further analysis.
“If 10 MW is too high, what’s too low? Is 0.1 too low?” he asked.
He said he couldn’t determine whether there would be any market resettlements if the rule is changed again, but that “it’s possible.”
Balancing Ratio
PJM’s Pat Bruno reviewed the RTO’s proposal to address concerns with calculating the balancing ratio (B) used in the default market seller offer cap (MSOC). The calculation became an issue after PJM was unable to determine a MSOC for 2018 and was forced to implement a stop-gap number. (See “Balancing Ratio Study Changed,” PJM Markets and Reliability Committee Briefs: April 19, 2018.)
PJM’s proposal would calculate average hourly balancing ratios from as many performance assessment intervals (PAIs) as have occurred within the past three years and supplement them with estimated hourly balancing ratios from as many of the remaining peak hours as is necessary to meet the required number of hours of PAIs. Currently, that number is 30. The balancing ratios would be averaged together for a final balancing ratio for the year.
PJM argues the proposal is straightforward, reasonable and able to be completed within the necessary amount of time.
Bowring suggested in his proposal that the balancing ratio can be estimated using a forward-looking model of performance assessment intervals.
“If there are no performance assessment [intervals], there is no B and we don’t need to make one up by inventing various weird ways of pretending there really was one,” Bowring said. “It’s still possible to get to an offer cap. … Let’s not make things up. Let’s actually do a model … based on PJM’s current modeling to determine what we expect to happen.”
Quadrennial Review of VRR Curve
Stakeholders asked PJM to justify its recommended revisions to key parameters for the annual capacity auction following its quadrennial review of the demand curve. PJM reviews the calculation of its demand, or variable resource requirement (VRR), curve every four years and makes recommendations based on an analysis of the curve’s performance. (See PJM to Consider Revisions to Demand Curve Design.)
Among PJM’s more controversial recommendations is that stakeholders ignore the recommendation of the Brattle Group, which performed the performance analysis, and continue to base the VRR curve on the cost of new entry (CONE) calculations for a gas-fired combustion turbine. Brattle recommended changing to the CONE for a combined cycle unit, which it said is cheaper.
“This curve has proven over the past years to be reliable and robust,” Bruno said in defense of the CT-based curve.
“I really expected some evaluation of the shape of the curve … and there wasn’t any of that,” said James Wilson, who consults for several consumer advocates within the RTO’s footprint.
Bruno argued that Brattle reviewed the curve’s shape, as the Tariff requires.
AMP’s Lieberman asked why PJM thought it was appropriate to shift the curve right four years ago based on Brattle’s recommendations — increasing the expense to consumers and profits to generators — but not back when they recommend it four years later. ODEC’s Ford echoed the concerns.
Calpine’s David “Scarp” Scarpignato said he wasn’t “convinced” that the curve reduces excess capacity.
“There are a lot of barriers to exit going on. … I don’t think you can study the curve in isolation like that,” he said.
PJM is not recommending a change in the cap, so it would remain 1.5 times net CONE or 0.7 times gross CONE.
Order 844 Revisions
PJM briefed the MIC on its response to FERC’s April order requiring RTOs to submit monthly reports detailing their uplift payments and operator-initiated commitments (Order 844, RM17-2). PJM has until Sept. 7 to make its compliance filing implementing the changes, which have to go into effect by Jan. 7. (See FERC Orders RTOs to Shine Light on Uplift Data.)
RTOs/ISOs are required to report:
total uplift payments for each transmission zone, separated by day and uplift category;
total uplift payments for each resource monthly; and
megawatts of operator-initiated commitments in or near real time and after the close of the day-ahead market, broken out by transmission zone and the reason for the commitment.
In addition, the order requires PJM to add to its Tariff the transmission constraint penalty factor values used in market software; the circumstances under which the penalty factors can set LMPs; and the procedures for temporarily changing transmission constraint penalty factor values.
A discussion on the topic is planned for a special MIC meeting May 10.
VALLEY FORGE, Pa. — The PJM Operating Committee last week unanimously approved revisions to Manual 14D to tighten the notification rules for transferring the ownership of generation units.
Generation owners and PJM staff hammered out the language over the past month after owners expressed concerns over an earlier proposal. (See “Gen Transfer Vote Postponed,” PJM Operating Committee Briefs: April 3, 2018.)
PJM’s Rebecca Stadelmeyer presented the revised proposal, which sets deadlines on how long prior to the sale the buyer and seller must provide the RTO with certain information. Sellers must now simultaneously provide PJM with the application they submit to FERC to change ownership, which starts a clock on several other submissions.
At least five days before closing on the sale, sellers must provide PJM with information including the name and W9 form of the buyer, and a list of its current officers.
GT Power Group’s Dave Pratzon, who organized generation owners’ engagement on the issue, said the result addresses owners’ concerns about commercial realities and the need for flexibility that earlier drafts did not.
PJM’s Eric Endress presented proposed Manual 11 revisions that would change how the RTO estimates the synchronized reserve maximums for Tier 1 units. The revisions would set a unit’s maximum at the lesser of the economic maximum or synchronized reserve maximum, though an owner could submit a request for a synchronized reserve maximum less than the economic maximum if a physical limitation exists. The economic maximum can be updated intra-hour as necessary.
PJM is targeting a July 1 implementation of the changes.
Carl Johnson, who represents the PJM Public Power Coalition, was one of several stakeholders who voiced concerns about “moving the earth under our feet” while several other larger issues related to the topic are being debated in other stakeholder forums — notably the Energy Price Formation Senior Task Force and PJM’s initiative to increase grid resilience.
He acknowledged that the proposal “makes sense” but cautioned that “we may be changing this entirely.”
Pratzon asked staff to analyze how the different initiatives overlap because they could “benefit from better coordination.”
PJM’s Chris Pilong acknowledged the concern but urged stakeholders to “make sure we don’t just sit on our hands” and not implement a solution to the issue. The RTO has been analyzing stakeholder concerns about significantly overestimated Tier 1 reserves. (See “Changing Tier 1 Reserve Estimates,” PJM Operating Committee Briefs: March 6, 2018.)
“In the interim, I think we still need to make sure that the reserves are accurate,” Pilong said.
PJM’s Eric Hsia confirmed that a “very limited amount of resources have a spin max greater than [its economic] max.” The RTO agreed to Johnson’s request to provide comparisons of units’ spin max versus economic max for all operating states, not just during synchronized reserve events.
Later in the meeting, PJM’s Becky Davis explained that the RTO uses the synch reserve ramp rates that units specify if they’re greater than specified energy ramp rates. However, generators aren’t required to provide either of those. If neither is specified, PJM uses the default ramp rate.
She noted an analysis of events over the past two years that showed 10% of units with synch reserve ramp rates greater than their energy ramp rates met or exceeded PJM’s Tier 1 estimate. The RTO contacted the other units to either remove the synch reserve ramp rates, match them with the energy ramp rates or justify why it should remain higher by submitting actual unit performance following a synch reserve event.
In response to a question from Pratzon, Davis said that most generators’ reserve rates match their energy rates.
Black Start Fuel Assurance
PJM’s David Schweizer presented proposed fuel-assurance requirements that will be required of black start units starting next year. The requirements would go into effect at the end of the year following the finalization of PJM’s current black start request for proposals and be in place for any incremental solicitations and the next RTO-wide RFP in 2023, he said.
Units would have to show one of the following:
Dual-fuel capability with onsite fuel storage for a 16-hour run-time at its rated black start output;
Onsite fuel storage for a 16-hour run-time at its rated black-start output for units that can store fuel, such as pumped hydro, batteries or oil;
Connection to multiple interstate gas pipelines with primary firm transportation contracts on at least two lines. This wouldn’t include local distribution company lines, which don’t offer firm service; and/or
That run-of-river hydro units can run at their black start rating for 16 hours.
Existing units would be entitled to a five-year transition plan starting in delivery year 2020/21. Units would be allowed to include the capital costs in the incremental black start capital cost component in their costs and would convert to the base formula rate after capital costs have been recovered.
Schweizer suggested that addressing previous concerns about the minimum tank suction level (MTSL) might be “more relevant” now. David Mabry, who represents the PJM Industrial Customer Coalition, agreed and requested a concrete proposal from PJM, but Calpine’s David “Scarp” Scarpignato argued against rehashing the issue. Prompted by the Independent Market Monitor, stakeholders spent several months earlier this year debating revisions to the MTSL calculation but eventually decided there were other issues of potentially greater significance to address. (See “MTSL ‘Not Going Away,’” PJM MRC/MC Briefs: Oct. 2, 2017.)
Pratzon asked if existing black start units that begin but don’t complete upgrades required by the new rules would have to voluntarily cancel the black start contract or if PJM would cancel it. He said his concern is if the difference will affect whether such units are able to recover their costs fully. Staff weren’t prepared to respond definitively; Pratzon asked that it be determined “sooner rather than later” so generators can make decisions about participating in the current RFP. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: April 3, 2018.)
Base Becomes CP
All capacity resources will be subject to Capacity Performance requirements at the beginning of the new delivery year on June 1. PJM’s Susan Kenney provided a preview on what changes regarding unit-specific parameters those resources will experience.
She noted that parameters will be updatable from May 25 through 10:30 a.m. on May 31 and that updates will transfer through to following days. Any parameters that don’t comply with new limits will be rejected by the system, she said.
Kenney also reviewed real-time value reporting procedures.
Souder said staff will analyze the grid under “stressed conditions” that include an extended cold spell, nuclear and coal retirements and the lack of availability of dual-fuel or onsite storage.
The plan has created concern on all sides of the industry.
Joe DeLosa, who represents the Delaware Public Service Commission, voiced “major concerns about the amount of time that’s going to be able to be devoted to this over the next year.”
“End-use customers especially have communicated to PJM their lack of a desire for criteria in the resilience field. I think that’s been pretty unanimous from customers, as well as substantial discussions about competing priorities in the stakeholder process,” he said.
“My mind’s racing,” FirstEnergy’s Jim Benchek said. “You’ve already got CETO/CETL [capacity emergency transfer objective/capacity emergency transfer limit] constraints. … It sounds like you’re planning to put an additional layer of constraints on the system.”
Later, PJM’s Brian Fitzpatrick explained the progress in staff’s analysis of gas-pipeline risks. The analysis is part of PJM’s ongoing effort to prepare for potential interruptions on the pipeline system. (See “Additional Reserves Needed?” PJM MRC/MC Briefs: March 22, 2018.)
Staff have held five meetings with pipelines within its footprint and have three more planned. While PJM had initially identified 63 contingencies that mostly involved potential compressor failures, pipeline companies said those were lower risk and recommended focusing on the ends of lines and laterals connected to main trunk lines.
“Right now, we have about seven [contingencies], so really, really decreased that list quite a bit,” Fitzpatrick said. “And that number will change because we’re still meeting with pipelines.”
Additional analysis will occur over the next six months.
PJM’s Augustine Caven said conditions during January’s “bomb cyclone” cold snap hit triggers to evaluate the need for any contingencies but that none were necessary. Caven also explained PJM’s plan to add detail to its operational parameters for gas units. The expanded parameters will help support automating PJM’s response to contingencies.
PJM is also planning to expand its ability to track units’ limitations on run time, including fuel inventory, emissions limitations, and supplies of demineralized and cooling water. PJM’s Natalie Tacka explained plans to add ways for units to report “hours remaining” for specified time windows and for RTO dispatchers to keep track of those potential restrictions. PJM is seeking generation owner input and asks those interested to let it know by May 11.
PJM’s Aaron Baizman explained a plan to automate the dispatch of resources onto the system. The current procedure involves calling the generator directly, but PJM plans to have that notification and verification process become electronic.
The transition will start with combustion turbines through a pilot planned to begin at the end of the year and ramp up in 2019. PJM plans to expand it to all units but has not yet set a target date.
Baizman said the plan is similar to programs at ISO-NE, CAISO, SPP and MISO.
CIR Questions
PJM wants to switch from using average to median capacity factors to calculate units’ unforced capacity. The RTO says the median is closer to units’ actual performance but acknowledges it will reduce units’ capacity injection rights (CIRs). (See “CIR Revisions,” PJM Operating Committee Briefs: April 3, 2018.)
The proposal has created concern among some stakeholders, and PJM’s plan to address the unease has only created additional concerns. PJM’s Jerry Bell outlined the current plan, which gives generation owners until Aug. 31, 2024, to notify the RTO that they plan to convert the CIRs that will be lost into incremental deliverability rights (IDRs) that they will use in an interconnection queue project within one year of the notice to PJM. The CIRs will convert to IDRs on Sept. 1, 2024. The plan is like the procedures already in place for reusing CIRs from retiring generators.
Initially, after stakeholders questioned the value of CIRs without a project, Bell suggested they could be sold at the point of interconnection, used to expand the existing project or allocated to a new project in the same area. However, he eventually conceded that “I don’t know what you’d do with them.”
Stakeholders also questioned why PJM would want to force generators to purchase less transmission capacity than they otherwise would. Bell said he’d have to come back later with an answer.
30-Minute Reserves Target Set
PJM has determined that it should secure roughly 3,800 MW of 30-minute reserves in real time, PJM’s Vince Stefanowicz said. The determination comes after analyzing how other RTOs/ISOs handle such longer-term reserves. Stefanowicz noted that ISO-NE, NYISO and the Tennessee Valley Authority all have a similar requirement.
Staff came to the number by considering several factors and making some assumptions. First, they assumed the largest unit would be about 1,500 MW and determined that the appropriate reserve should equal 200% of that. They added the load, wind and solar forecast errors for each season and came up with a value for each season. They averaged to 3,784 MW.
The number would be recalculated annually, and Stefanowicz said it’s often already online much of the time. PJM’s emergency management system calculates 30-minute reserves and found that, over the past four years, the system has been below 5,000 MW of reserves less than 10 hours total.
“We don’t expect this to come into play a lot,” he said. “In reality, the number we’re proposing is not overly aggressive. It’s realistic to what we’ve seen. … We have those reserves on the system normally, through our normal scheduling processes today.”
He noted that resources with a start time of less than 30 minutes could qualify.
PJM’s synchronized reserve requirement is 100% of the largest energy contingency and the primary reserve target is 150%, but the 30-minute “operating” reserve is currently undefined. Stefanowicz said the proposed calculation produces a number like the 30-minute reserve that PJM procures in day-ahead and is comparable to the calculations other RTOs/ISOs make.
“Each area has a different set of numbers, but a very similar methodology for securing their reserves,” he said.
Mabry asked why the target requirement wasn’t dynamic based on the largest unit online at the time. Stefanowicz said they would consider that.
PPL last week said it expects to need to raise only about $2 billion from equity sales through 2020, which would enable the company to come in near the top of its projected 5 to 6% compound annual earnings growth per share over that time.
During its first-quarter earnings call, the company also said it expect calls for nationalization of electric utilities in the U.K. to fade and that it isn’t interested in fully or partially divesting its business there.
PPL CEO Bill Spence says his company is looking for organic growth. PPL expects to need raise $2 billion in equity sales through 2020. | PP&L
PPL earned $452 million ($0.65/share) on revenue of $2.13 billion in the first quarter, as opposed to $403 million ($0.59/share) on revenue of $1.95 billion in the first quarter of last year. Its adjusted earnings were 74 cents/share, beating the Zacks consensus estimate of 66 cents. The difference stemmed from a one-time impact of 9 cents/share from foreign currency hedges.
PPL expects to use its “at the market” offering program for most of its equity sales. CFO Vincent Sorgi said the company has a shelf offering that would allow it to sell up to $3 billion in stock.
The company isn’t looking to perform acquisitions, but rather to pursue organic growth, with midsized transmission projects such as Project Compass being the kind of opportunities it envisions after 2020, according to CEO Bill Spence.
Exelon’s plans for its generation subsidiary rely heavily on a push for new legislation and market rule changes that ensure profitability for plants the company is threatening to close, officials said last week.
During a first-quarter earnings call last week, CEO Chris Crane said Exelon plans to push for subsidies for its nuclear plants in Pennsylvania similar to the zero-emission credit (ZEC) programs in Illinois and New York, and the one recently passed by the New Jersey Legislature but not yet signed by Gov. Phil Murphy.
Crane also said he expects Exelon’s generation business to benefit from PJM’s adoption of new price formation rules and FERC’s resilience initiatives.
Although Crane didn’t mention it, Exelon’s Pennsylvania nuclear plants could also earn subsidies from a New Jersey plan that takes into account how plants affect the state’s air quality, regardless of where they’re based. (See Izzo: Nukes Outside NJ Likely Eligible for State ZECs.) Efforts to enact nuclear subsidy programs in Pennsylvania have so far failed to gain much traction.
Crane also said Exelon will work with ISO-NE to develop market reforms allowing it to keep open the four units of its Mystic Generating Station in Charlestown, Mass., that it said it would close in June 2022.
Exelon CEO Chris Crane says his company will work with ISO-NE on market reforms. Exelon has said it will close the Mystic Generation Station without market reforms.
The company is “going to look to get to the right reforms to make these assets more economic in the future,” Crane said. He noted that ISO-NE “put out a study recently saying that there were five assets in New England needed to ensure reliability into the future, one being the Everett Marine Terminal and the others being the Mystic [units].”
On the same day it said would close Mystic, Exelon announced it was buying the Everett Marine Terminal, an LNG import facility in Everett, Mass., which provides Mystic and other power plants in the area with fuel.
ISO-NE last week asked FERC for permission to waive certain Tariff requirements to allow the RTO to retain Mystic Units 8 and 9 to maintain fuel security, following up on a plan the RTO outlined in an April memo. (See ISO-NE Moves to Keep Exelon’s Mystic Running.)
Crane, along with Joe Dominguez, the company’s vice president of governmental and regulatory affairs and public policy, also addressed a PJM plan announced April 30 to help ensure fuel security. (See PJM Seeks to Have Market Value Fuel Security.)
Dominguez said Exelon would like to see PJM incorporate environmental impacts associated with different fuel mixes, pointing out that during the cold snap last winter, New England had to rely heavily on oil to produce power.
“In 2018, emissions need to be going down,” he said. “And any resolution of this issue that results in emissions going up is going to continue to create incentives for state actions and, indeed, for other federal actions to correct the flaws in those market.”
Crane said that while consumers have benefited from low-cost gas, the industry needs to either build redundancy into the gas delivery system or limit its dependency on gas to make the power production and delivery system more secure.
Exelon had net income of $585 million ($0.60/share) on revenue of $9.69 billion in the first quarter, down from $990 million ($1.06/share) and $8.75 billion in revenues a year earlier. The company’s operating earnings were 96 cents/share, beating the Zacks consensus estimate of 93 cents.
Crane said the company plans to target a 7.4% rate base growth for its utilities and 6 to 8% earnings per share growth through 2021.
Exelon is still on the prowl for acquisitions, if it can find smart ones, according to CFO Joseph Nigro.
“To the extent we can add something that we think will be accretive to the bottom line and fits with the value proposition that we’re trying to bring both to our shareholders and our customers, we’re going to be aggressive with doing that,” Nigro said.
FERC last week denied Bayonne Energy Center in New Jersey a waiver of several NYISO Tariff provisions, which the plant said it needed to enter the ISO’s monthly installed capacity (ICAP) auction in June.
NYISO clusters project developers that have achieved similar milestones into a “class year,” and evaluates the cumulative impacts of all of the projects in a given class year through an interconnection facilities study. The ISO recently adopted process changes authorizing it to bifurcate a class year in order to minimize delays for project developers unaffected by additional upgrade studies, allowing those developers an earlier “exit ramp” from the interconnection process.
Bayonne Energy Center | Direct Energy
Bayonne last month asked FERC permission to waive 11 provisions and add two new natural gas-fired units with approximately 120 MW of summer capacity to its existing 512 MW of capacity in time for the June ICAP auction.
The plant said that its 2017 class year study, originally scheduled for completion in December, was now slated to be completed in April. Bayonne would then be potentially subject to an additional 30-day delay while the ISO determined whether it needed to bifurcate the class year, jeopardizing the ability of the new capacity to participate in the June auction. Bayonne contended that it was not seeking waiver of any substantive requirements, but of the timing of certain requirements to allow for timely participation.
The commission’s May 4 order (ER18-1301) found that, in seeking waiver of 11 Tariff provisions, “Bayonne’s waiver request is not limited in scope,” and that granting the request could possibly harm third parties by delaying the ISO’s completion of the class year 2017 process for other projects. The commission also pointed out that “it is unclear whether Bayonne will even need waiver of these provisions given that it is not clear yet that whether class year 2017 will bifurcate.”
“We also note that Bayonne assumes, without support, that both NYISO and its Market Monitoring Unit can expedite their processes if the commission grants the waiver request,” the commission said. “In this way, it is unclear whether granting the waiver request would even provide Bayonne the relief it seeks.”
While the wildfires that ravaged California last year have long burned out, the financial implications for Pacific Gas and Electric are just beginning to surge as the utility works to reduce the impact on shareholders.
PG&E last week reported first-quarter profits of $468 million ($0.91/share), compared with $544 million ($1.06/share) in 2017, falling short of expectations of Wall Street analysts. The utility reported $21 million in wildfire-related costs in the quarter under “items impacting comparability.”
Central to PG&E’s woes is the legal concept of “inverse condemnation,” which makes a utility potentially liable for wildfire-related property damage caused by utility equipment even in cases when that equipment has passed inspections and utility negligence isn’t proven.
During an earnings call and presentation Thursday, PG&E CEO Geisha Williams said the current treatment of the company’s wildfire responsibility is “a strict liability approach that presumes a commensurate cost recovery path for investor-owned utilities that just isn’t true.” She said that utilities cannot raise rates without regulatory approval, so applying inverse condemnation to utilities “undermines the premise” of the concept.
California’s courts have set a precedent of applying the state’s inverse condemnation provisions to IOUs, and a state trial court last week denied PG&E’s challenge of inverse condemnation related to the 2015 Butte Fire.
Aerial view of fires in Napa and Sonoma Counties, October 2015
The state’s IOUs have banded together on the wildfire issue, pressing on legislative, regulatory and legal fronts to change the approach to inverse condemnation. Newly introduced legislation would revise wildfire liability provisions by allowing utilities to recover wildfire costs through rates if they conform to state-regulated safety plans. (See Calif. Legislation Shields Utilities from Wildfire Costs.)
Fitch Ratings downgraded PG&E’s stock in February because of wildfire risk. Utility liability for wildfires over the last 10 years has created worries among state lawmakers and the California Public Utilities Commission over the potential for IOU bankruptcies. (See Picker Seeks Guidance on IOUs, Aliso Canyon.) PG&E awaits other legal rulings regarding inverse condemnation associated with the 2017 fires, and the utility says climate change is playing a larger role in the conditions that led to the massive blazes.
The utility said that is has been working to harden its systems against wildfires, increasing its spending on vegetation management to $440 million in 2017 from $190 million in 2013, increasing inspections in high fire risk areas and acquiring two helicopters to assist in wildfire response, with plans to acquire two more. It plans to add 200 new weather-monitoring stations this year.
Williams also discussed the growth of community choice aggregators (CCAs), which has left remaining bundled customers to foot the costs for legacy contracts. The issue is becoming more prevalent as CCAs grow. She said the California energy landscape is in a period of “dynamic change,” mentioning climate change, CCA growth, increasing use of electric vehicles, and growth in carbon-free and renewable energy resources.
NiSource is seeking rate hikes across multiple states to cover hefty infrastructure investments after the company delivered a 13% increase in earnings during the first quarter.
The Merrillville, Ind.-based utility last week reported first-quarter earnings of $259.7 million ($0.77/share), compared to $230.6 million ($0.71/share) over the same period in 2017.
“Our systems performed well throughout the prolonged winter heating season, and we’re on pace to deliver on our earnings, capital investment and customer commitments in 2018,” CEO Joseph Hamrock said during a May 2 call with investors and analysts.
NiSource filed several rate hike applications with different regulators during and after the quarter, hoping to recoup the approximately $1.8 billion it plans to spend on infrastructure this year.
“The biggest driver of our strong financial performance continues to be the impact of our long-term infrastructure modernization investments, supported by solid regulatory outcomes and established infrastructure trackers,” CFO Donald Brown said.
Hamrock said NiSource expects to continue to invest $1.6 billion to $1.8 billion in its utility infrastructure every year until 2020. The investments should boost operating earnings 5 to 7% per year, he said.
Subsidiary Northern Indiana Public Service Co. filed a settlement last month in its pending base rate case with the Indiana Utility Regulatory Commission. Brown said the request is NIPSCO’s first natural gas base rate increase in more than 25 years and will improve pipeline safety and reliability (44988). If approved, the settlement would result in an annual revenue increase of $107.3 million through fixed charges on customer bills. NiSource expects a commission decision in the second half of this year.
NIPSCO employees finish a substation project in March in Northern Indiana | NiSource
NIPSCO also filed a seven-year gas infrastructure modernization plan with the IURC in early April that proposes $1.25 billion of investments through 2025. The program would recover the costs of modernizing underground natural gas infrastructure through a customer bill charge (44403). NiSource similarly expects a ruling in the second half of 2018.
NiSource subsidiary Columbia Gas of Pennsylvania also has a $47 million per year rate increase request on file with the Pennsylvania Public Utility Commission as of mid-March.
Brown said the case would “provide the company with an opportunity to earn a fair return on its infrastructure capital investments and enhance pipeline safety.”
In late April, the Public Utilities Commission of Ohio approved a rate increase allowing NiSource-owned Columbia Gas of Ohio to begin recovery on about $207 million of infrastructure investments made in 2017. Columbia Gas of Massachusetts also filed a request with the Massachusetts Department of Public Utilities to increase revenues by about $24 million annually in an effort to recover costs incurred from regulatory mandates and gas distribution infrastructure upgrades. The DPU on April 30 also allowed the Massachusetts subsidiary to recover $84 million of capital investments in its rates. Finally, Columbia Gas of Maryland is seeking a $6 million per year rate hike with that state’s regulators as of April 13 for make pipeline upgrades.
Hamrock said corporate tax cuts at the beginning of the year helped to lower its rate hike requests in Indiana, Pennsylvania, Maryland and Massachusetts, as well as the rate request for its gas infrastructure replacement program in Ohio.
Eversource Energy said Wednesday that it will seek to support earnings growth through offshore wind contracts from its Bay State Wind partnership and a new rate plan in Connecticut that increases the average customer’s electricity bill by 3.8%.
The company reported first-quarter earnings of $269.5 million, compared with $259.5 million in the same period a year ago.
Eversource’s transmission unit earned $107.4 million in the quarter, up 11.4% from a year earlier because of additional investment in its electric transmission system.
The company’s electric distribution and generation business earned $104.2 million in the first quarter, down 6.5% from last year primarily because of the sale of generation assets, as well as higher depreciation, property tax, and operations and maintenance expenses, which were partially offset by higher electric distribution margins. Exceptional storm-related costs drove O&M expenses higher.
CFO Phil Lembo said in an analyst call May 3 that “we had significant storm activity in March this year, very significant, particularly in eastern Massachusetts, as a result of a series of nor’easters that hit us over an 11-day span.”
“The vast majority of the restoration costs, about $150 million, was deferred under regulatory mechanisms for future recovery,” Lembo said.
Regulatory Updates
Lembo noted the “good news” of a FERC administrative law judge’s March 27 ruling that municipal utilities and commission staff failed to prove that the New England Transmission Owners’ (NETOs) base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable. (See ALJ Rules New England Tx Owners’ ROEs not Unjust.)
FERC last October rejected a bid by NETOs, including Eversource, to increase their ROE to the levels in place before being reduced by a 2014 commission order that was vacated by an appellate court early last year. The commission said it would address the actual rate in a later remand order but has yet to do so (ER15-414, EL11-66).
Executives also discussed the New Hampshire Site Evaluation Committee’s (SEC) March 30 decision to formalize its rejection of Northern Pass, a joint venture between Eversource and Hydro-Quebec for a 1,090-MW transmission line to bring up to 9.4 TWh of Canadian hydropower to New England each year. Massachusetts had chosen Northern Pass, but in light of the rejection selected as an alternative a transmission project proposed by Avangrid subsidiary Central Maine Power. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
Lee Olivier, Eversource executive vice president for business development, said the SEC has scheduled a May 24 meeting to hear Eversource’s request to reconsider the rejection. If rejected again, “the next step would be to appeal to the New Hampshire Supreme Court,” Olivier said.
Offshore Wind Hopes
Eversource partnered with Orsted to form Bay State Wind for a offshore wind solicitation in Massachusetts, and in December the company proposed a 400- or 800-MW wind farm 25 miles off New Bedford to be paired with a 55-MW battery storage facility.
Olivier said Massachusetts officials delayed by a month the date to select projects for negotiation, to May 23, 2018, now to be followed by submission of contracts to the Department of Public Utilities by July 31.
Connecticut is also conducting a request for proposals for offshore wind, and the company bid approximately 200 MW last month, Olivier said. A winning bidder is expected by midyear, he said.
Olivier said Bay State Wind can produce up to 2,500 MW of wind energy from its 300-square-mile lease area south of Martha’s Vineyard and interconnect it to surrounding states and Long Island, even extending over land to New York City with relatively minor upgrades to existing infrastructure.
“We’ll also have returns on these assets, transmission-like returns,” Olivier said. “Clearly once you get in, if you’re one of the first selected, you’ll have a first-mover advantage in every other solicitation.”
CARMEL, Ind. — The Reliability Subcommittee’s effort to explore how MISO should address increasingly uneven availability of resources could revive a discussion on developing a capacity market divided by season, stakeholders learned last week.
MISO kicked off its “resource availability and need” effort last month with a white paper on changing availability and an announcement that it would devise specific rules to counter the effects of increasing generation retirements, poor outage coordination, growing volumes of emergency-only capacity and the rising use of intermittent resources. (See MISO Looks to Address Changing Resource Availability.)
During a May 3 RSC meeting, MISO Executive Director of Market Operations Jeff Bladen said the new effort has prompted some stakeholders to ask the RTO to revisit its 2015 proposal to create seasonal capacity auctions, a move that was put on indefinite hold last year after stakeholder pushback.
At the time, seasonal capacity auctions seemed like “a single point solution to a broader set of issues that called for a more holistic approach,” Bladen said, noting that the new effort wasn’t intended to preclude a re-examination of the possible need for the auctions.
Near-term Solutions
Bladen also said several stakeholders urged MISO to focus on near-term solutions to ensure that an adequate amount of resources is at the ready, including improving outage coordination, modifying the rules of emergency-only resource types and creating forecasts that provide a better picture of resource availability in the footprint.
A utility’s cash flow influences the lumping of outages, Bladen said, with fleet operators grouping outages when they expect low energy prices, especially in spring and fall.
“When prices are low, operators tend to take outages. It’s expected,” he said. “This is not as simple as, ‘well, everybody takes outages throughout the year.’ It’s much more complicated than that.” MISO said that most of its planned outages are scheduled less than a week before they are taken.
MISO might turn to a solution that requires more accountability from operators, Bladen said.
“Maybe there’s some expectation for generators to replace themselves [during an outage]? That’s pretty extreme,” Bladen said, stressing that MISO has not seriously discussed that measure.
Bladen said MISO could examine its existing load-modifying resource contracts to include staggering availability times and provide incentives to resources that offer during emergencies outside of summertime.
“Does it make sense to expect non-summer participation when it’s not compensated like in summer?” Bladen asked.
He pointed out that this summer, MISO faces an 80% chance of entering emergency conditions. (See MISO: Summer Reserves Adequate, but Emergency Likely.) He also said that a reduction in zonal resource credit offers has reduced the number of uncleared zonal resource credits in capacity auctions since the 2014/15 planning year.
“While we don’t think the platform is burning, the temperature is certainly rising,” Bladen said. “I want to be clear. The system is not unreliable. There’s just a better chance of emergencies.”
Storage Mentions
The Advanced Energy Management Alliance and other stakeholders called out MISO’s white paper for not explicitly mentioning the help energy storage could provide during tight operating.
Bladen said the omission was deliberate in order to remain technology- and resource-neutral.
“I would say that was intentional. We didn’t intend to reference technologies, but rather we were recognizing the resource availability profiles without going to where solutions could be found,” Bladen said.
Nevertheless, Bladen said MISO must consider the impacts that FERC’s Order 841 may have on its resource availability.
DTE Energy and the Organization of MISO States also asked the RTO to consider revising its loss-of-load expectation (LOLE) study process to include more availability risks associated with its resource mix.
Bladen said MISO envisions more stakeholder discussion before proposing changes to the LOLE study. He said altering study methods could produce a larger planning reserve margin requirement.
“It raises the prospect of socializing the risk by requiring everyone to procure more capacity,” Bladen said. “That’s a choice we can make as a community, but we have to be completely transparent about that choice.”
Consumers Energy’s Jeff Beattie cautioned MISO against risking some of its value proposition to its members by creating an insurance-sharing pool.
Bladen agreed that MISO needs to carefully consider balancing the sharing of resources in the footprint. “I’m glad you raised it because that’s something that needs to be front and center in the conversation,” he said.
He also said the RTO must also investigate shifting loss-of-load risk as part of resource availability. A recent renewable integration study by MISO found that as more intermittent renewable resources join the fleet, the loss-of-load risk becomes shorter but steeper, occurring later in the day after sundown. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
Developing solutions to MISO’s resource availability issues could stretch well into 2019, Bladen said, and he expected that parts of the solution will be handled by the Market Subcommittee and Resource Adequacy Subcommittee as well as the RSC. He asked for more stakeholder opinion on what approaches the RTO should take.
