CARMEL, Ind. — MISO stakeholders will vote on whether to broaden export limits for its upcoming capacity auction after WPPI Energy called for the RTO to act.
WPPI engineer Steve Leovy said MISO has not been distinguishing imports sourced outside the RTO from those sourced inside in calculating its capacity export limit (CEL), making available transmission capacity appear scarcer than it really is. MISO calculates capacity import and export limits for each local resource zone to assure that cleared capacity can be delivered.
“We have a small amount of excess capacity in Zone 1, so we stand to have an adverse financial impact if the limit binds,” Leovy said at last week’s Resource Adequacy Subcommittee meeting.
Leovy said Zone 1’s CEL is 516 MW, but the zone cleared 613 MW in the 2017/18 Planning Resource Auction. Zone 1 — which covers portions of Wisconsin, Minnesota, the Dakotas and Montana — has more contributing external resources than any other zone in MISO, Leovy said.
“We’re concerned with what we see is improper clearing in the coming Planning Resource Auction,” Leovy said. He asked MISO to calculate “appropriate, accurate” limits for the 2018/2019 auction. His motion, calling for the RTO to ensure alignment between the PRA and CEL calculations, will be voted on in an email ballot through Nov. 15.
MISO was planning to update CELs with the creation of external resource zones, but the proposal is now on hold until the 2019/20 planning year. (See MISO Postpones External Zones Until 2019 Auction.)
Laura Rauch, MISO resource adequacy manager, said the RTO still plans to create new CELs that correspond with any new external zones that MISO designates. “Our concern is moving a piece of this forward without the rest of it,” she said.
Rauch also said MISO’s capacity import limits (CILs) and CELs are linked, and it would be inappropriate to update one without the other.
MISO’s CIL calculation was changed to account for counterflows created by exports to neighboring balancing authorities in response to a FERC order in 2015 (EL15-70, et al.). Leovy said a similar change is needed for CELs.
Some stakeholders said that while they could see others supporting an export limit change, they doubted stakeholders wanted to change CILs and local clearing requirements.
‘Shopped Around’
NRG Energy’s Tia Elliott said Leovy made a motion that didn’t result in action during a similar presentation at a spring 2016 Loss-of-Load-Expectation Working Group. “I’m concerned that maybe that this is being shopped around,” Elliott said.
“Thanks for the reminder that this is something that we’ve been discussing with MISO for quite some time. MISO is aware that this is an issue,” Leovy responded. “All I’m asking for is a vote to the timeline to get this fixed, and I don’t think this is forum-shopping or dodging the stakeholder process.”
Elliott also pointed out that the limits have already been set for the upcoming planning year in MISO’s loss-of-load-expectation study, and said changing them now would complicate the process.
Leovy said MISO may be able to implement a fix that doesn’t involve revising its Tariff, because it defines CELs as the megawatts of planning resources that can be “reliably exported” from a local resource zone. He believes the language supports transmission providers modeling the physical location of load and planning resources, giving MISO enough information to differentiate between external and internal capacity.
“So long as a [transmission owner] provides PJM with all of the required information, PJM studies that information and ensures it can reliably [integrate], then PJM must proceed,” Senior Counsel Jim Burlew said during a special informational meeting Tuesday. “PJM is the only entity to make a determination if a TO can integrate, and that’s based only on reliability.”
RTO officials said that procedure is based on the existing Tariff and Operating Agreement language. But members were not satisfied.
“I think the members have some concerns, and I think that PJM has a bit of an obligation to first of all hear, and second of all address, the concerns that may be raised in this forum,” American Municipal Power’s Ed Tatum said. “Why do they want to join the party?”
CFO Suzanne Daugherty, who chairs the Markets and Reliability Committee, agreed that “PJM has an obligation … to make sure you know what’s going on.” But she said CEO Andy Ott “is authorized to accept” membership applications if they don’t hinder reliability, as is the case with OVEC.
“This is consistent with several other parts of the Operating Agreement,” she said. “It’s an open party; there’s no cover charge.”
Tatum continued to press, saying “there is discretion,” and that PJM would be “well advised” to take in further perspectives from members before deciding. Members are concerned that OVEC’s integration will result in significant upgrade costs and increase the existing generation oversupply without providing more load for PJM generators to serve. Tatum said he is specifically concerned about costs from supplemental projects for aging transmission infrastructure and reliability improvements that could be needed if one or both of OVEC’s generating units retire.
OVEC, which is headquartered in Piketon, Ohio, owns 2,200 MW of generation capacity but will have no load after a U.S. Department of Energy contract ends sometime before 2023. The company was created in 1952 to service a uranium enrichment plant near Piketon that ceased operations in 2001. The department ended the 2,000-MW contract in 2003 but maintains a load that can be 45 MW at its maximum but is generally less than 30 MW.
The company’s two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — are already pseudo-tied into PJM, and its eight “sponsors” can sell their portions of the output into the RTO’s markets. The generation would become internal to PJM following membership, eliminating the pseudo-ties.
“It might be older than Ed Tatum, and although I’m advocating strongly to not be replaced, it might need to be replaced,” Tatum said of OVEC’s transmission infrastructure. “We see major upgrades looming here … and that’s one of the concerns we have. … What we have here is a very unique situation in which you have very little load to allocate to.”
Kyger Creek Power Plant
“Our infrastructure has been consistently maintained for 50 years, meets all NERC requirements and will meet all PJM requirements,” OVEC attorney Brian Chisling said.
OVEC’s representatives didn’t provide many additional details. When Tatum asked about plans for transferring OVEC’s existing load, Chisling said it involved a “feature” of Ohio’s Certified Territory Act and referred him to a proceeding of the Public Utilities Commission of Ohio (15-0892-EL-AEC).
Daugherty explained that any required upgrade would be billed to OVEC’s zone and then distributed proportionally to the eight companies that own OVEC.
PJM’s Mark Sims explained that OVEC is “required to have a plan” for upgrades before it joins but doesn’t need to have upgrades done.
VALLEY FORGE, Pa. — PJM Market Implementation Committee members last week expressed frustration over a proposal from the Independent Market Monitor on price-responsive demand (PRD) requirements, saying they hadn’t been given any time to review it prior to voting on the issue.
Ruth Ann Price of Delaware’s Division of the Public Advocate apologized on the Monitor’s behalf and took responsibility for requesting the late submission, but the measure failed to garner stakeholder backing. The proposal was so unexpected that it didn’t make it into the presentation PJM posted on the issue. It received 28 votes in support, or 15%, far below the 50% threshold for approval.
Two other proposals — one from PJM and the other from Calpine’s David “Scarp” Scarpignato — did receive enough support and will be presented at the Markets and Reliability Committee meeting on Dec. 7. Because of the Thanksgiving holiday, PJM moved the November MRC to the first week of December.
At issue is how PRD will be held to Capacity Performance requirements. PRD was developed before CP existed, but PRD bids cleared the annual Base Residual Auction in May for the first time since the new construct was implemented. PJM has proposed extending annual requirements developed for demand response to PRD and trigger CP penalty assessments during performance assessment intervals when the LMP is greater than the PRD price curve. Scarpignato’s “Proposal C” would make the assessment triggers any performance assessment interval. (See PJM Grilled on Price-Responsive Demand Rule Changes.)
DR provider Whisker Labs had presented another proposal but retracted it in favor of the Monitor’s proposal. The IMM argued that all PRD eligibility and performance should be measured from the participant’s peak load contribution (PLC). Both the planned PRD and the amount finally registered should be measured as the PLC minus the participant’s firm service level (FSL) and performance should be measured as PLC minus the actual load, the Monitor proposed.
“The key difference is that in our proposal, it is based on the total consumption in the summer period,” the IMM’s Skyler Marzewski said.
Carl Johnson, representing the PJM Public Power Coalition, and Dave Pratzon of GT Power Group objected to the proposal’s late inclusion because neither had had a chance to review it and make voting recommendations to their membership.
“It’s tough when totally new proposals come in at the last minute with no explanation,” Pratzon said.
Monitor Joe Bowring explained to RTO Insider in an email following the meeting that his staff provided PJM with its proposal on Oct. 29, more than a week before the MIC, and attempted to present it at a meeting of the Demand Response Subcommittee the following day. He said they were told they could not present on such short notice.
“The IMM’s proposal was included in the posted matrix on Monday prior to the Wednesday MIC meeting,” Bowring said. “The IMM agrees that there was some miscommunication among the IMM, the DRS and the MIC.”
Pratzon requested an explanation for basing all measurements off the PLC. Marzewski said the measurement should reflect how much the participant can reduce from its overall peak demand, not how much it can reduce at that moment. PJM proposed using different peak-demand calculations for summer and winter measurements.
He remained unmoved.
“As of right now, I’m not seeing the justification for the different treatment,” he said.
Gregory Carmean, the executive director of the Organization of PJM States Inc., argued the baseline should be the load that the RTO would have purchased if not for reduction.
“It’s PJM that’s trying to turn this into a seasonal product” by changing the definition of the PRD measurement between summer and winter, he said.
Delaware’s Price, Joe DeLosa of the Delaware Public Service Commission and Greg Poulos, executive director of the Consumer Advocates of the PJM States, also voiced support for the Monitor proposal.
Advocates “want residential customers to be able to respond to price,” Poulos said.
Dave Mabry, representing the PJM Industrial Customer Coalition, argued that the purpose of PRD is to get “the customer back to paying for the capacity that he needs.”
“There isn’t a payment that flows back,” he said.
Scarp argued that point, and PJM’s Pete Langbein confirmed the performance is paid as a credit.
“Call that a payment, call that a credit, but that’s effectively what will happen,” Langbein said.
Scarp said “PRD was supposed to get away from” the “hypothetical difference” between what was scheduled to be used and what was actually used.
James Wilson of Wilson Energy Economics, who consults for consumer advocates in several PJM states, disagreed that the proposal increases winter-adequacy risks. PJM’s reserve requirements study always shows zero loss-of-load expectation (LOLE) in winter, he said, and “there’s a huge margin of excess winter capacity before we get anywhere near where that changes.”
Big Support for Jurisdiction Mention in DERS Charter
Stakeholders voted overwhelmingly to include explicit deference to state and local regulatory authority in the charter for the new Distributed Energy Resources Subcommittee. (See “DER Subcommittee Charter Sent Back to MIC,” PJM MRC/MC Briefs 10-26-17.)
FirstEnergy had proposed what it hoped was an uncontroversial amendment, which stated “Market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the relevant electric retail regulatory authority (RERRA).”
DER companies saw it as a potential barrier to market entry.
“The vagueness of ‘respect the … standards and protocols’ concerns us,” said Tom Rutigliano, who represents providers of distributed resources.
“I think it’s just a matter of clarification. It’s motherhood and apple pie — we have to follow these things. I really wonder why there’s the apprehension to having it in there. … I really don’t understand all the pushback,” FirstEnergy’s Jim Benchek said.
Exelon’s Sharon Midgley agreed. “This would give us a lot of comfort moving forward if this is added,” she said.
They got their wish. The original version of the charter received 17% approval, or just 26 votes in favor, while the amended version received 92% approval, or 160 votes in favor.
Seasonal DR Aggregation Registration Rules
EnerNOC’s Steven Doremus presented a proposed revision to PJM’s DR aggregation registration rules, arguing that the current method fails to maximize use of available resources. The proposal accompanied the first read of a problem statement and issue charge.
The current method is to take as the CP capability the lesser of the registrant’s summer or winter capability. The CP capabilities of the registrants are then added together for a total capability, but this leaves a substantial amount of DR undispatchable.
“The problem we see is this is not the most efficient way to register the customers,” Doremus said.
EnerNOC proposed adding up the summer and winter capabilities of all registrants and using the lesser of the two summations at the overall CP capability “to maximize the value.”
“It wouldn’t change the value; it wouldn’t change the annual requirement,” PJM’s Langbein said of the proposal. “It’s just how do we sum up winter and summer capabilities to ensure there’s an annual capability at the [Reliability Pricing Model]-resource level.”
Meetings Reduction
Responding to a request from the Members Committee, PJM staff reviewed the status of all issues assigned the MIC and subcommittees. Of the 23 issues, seven are completed and will be closed. Three others have proposals awaiting endorsement votes.
At the October Members Committee meeting, Vice Chair Mike Borgatti of Gabel Associates announced that the MIC, MRC, Operating Committee and Planning Committee will be directed to determine if any timelines can be relaxed to “free up a little room in the schedule.” The directive came at the request of stakeholders, who have been complaining about the roughly 500 stakeholder meetings PJM conducts each year. (See “Reducing the Workload,” PJM MRC/MC Briefs.)
Adrien Ford of Old Dominion Electric Cooperative thanked PJM for developing the review and taking a “leadership role” in streamlining the issues.
Account Cleanup
PJM will be automatically terminating accounts on its website that have been locked longer than nine months. The terminations will reduce security risks, as well as improve system performance, staff explained.
PJM.com has 141,000 accounts, but 60,000 have already been terminated. Of the remaining 81,000, approximately 37,000 have been locked for more than nine months, or about 46%. Only about 20,000 accounts are actively used.
Accounts can be restored, but account managers at member companies have been notified to review employees’ accounts and delete any unneeded ones.
CARMEL, Ind. — MISO is proposing to once again revise the equation behind its yearly resource adequacy survey issued in partnership with the Organization of MISO States.
The new adjustment for the 2018 OMS-MISO survey adds a “likelihood” weighting to account for the in-service dates of potential new capacity still in the queue, said MISO Resource Adequacy Coordinator Ryan Westphal.
Including queue resources “is a pretty new process, so there’s no history of a success rate yet,” Westphal said during a Nov. 8 Resource Adequacy Subcommittee meeting.
Last year marked the first time the survey began including in its weighted resource adequacy averages a 35% capacity share of projects in the definitive planning phase of the interconnection queue. But MISO at the time didn’t contemplate adding likely in-service dates into the equation. The RTO is now proposing to weight projects represented within that 35% share based on the likelihood they’ll complete the queue by a certain year.
Under the proposal, next year’s survey will weight according to status — 10% for projects not yet started and in the first phase of the queue, 25% for projects in the second phase and 50% for those in the third phase. All projects with signed generation interconnection agreements will count fully toward offsetting resource adequacy requirements. MISO will also credit new wind and solar resources at 16% and 50%, respectively, of nominal capacity.
The new approach to weighting will result in a far lower forecast of potential resources. In last year’s survey, MISO predicted that 2.2 GW of potential resources in the definitive planning phase would come online in 2019. By applying the new weighting to the 2018 survey, MISO expects only 0.1 GW of potential resources will come online in 2019. By 2020, MISO sees 0.7 GW in operation instead of an earlier prediction of 3.3 GW. The in-service forecast climbs to 2 GW in 2021, but that represents just more than half the 3.8 GW predicted last year.
Comparison of MISO potential resources in OMS-MISO Survey | MISO
Before this year, MISO stakeholders had criticized the survey as being too alarmist for not including any potential new resources without signed interconnection agreements. Inclusion of a portion of those resources in this year’s survey showed MISO will have 2.7 to 4.8 GW of excess resources from 2018 to 2022, a departure from the shortfalls predicted in previous years. (See Capacity Survey Shows MISO in the Black.)
Saying the new survey style could “dramatically” impact some zones, Exelon’s David Bloom asked for a zone-by-zone comparison showing how predictions for potential new generation will change from this year to the next.
“By changing the assumptions from year to year, I think what MISO is doing is changing results,” said Kevin Murray, representing the Coalition of Midwest Transmission Customers. “You’re going to go from reporting a surplus in 2019, to reporting a deficit simply by arbitrarily shifting assumptions.”
Westphal asked stakeholders to keep in mind that the change deals only with potential resources still in the queue, which the survey only began including last year. He said all generation with signed interconnection agreements will continue to be counted.
“Did the queue get worse in the last year? Did a bunch of resources drop out? What happened to lose about 2.1 GW in 2019?” asked Indianapolis Power and Light’s Ted Leffler.
Laura Rauch, MISO manager of resource adequacy coordination, said the 35% of new generation used in last year’s survey was not adjusted for the more realistic in-service dates.
“Last year, we took the in-service dates that owners provided with their queue application. Some of those generators hadn’t been studied yet,” Rauch said. She said updated in-service dates for potential wind resources have the biggest effect on MISO’s numbers.
Madison Gas and Electric’s Megan Wisersky said she was concerned change would spark public concern about capacity shortfalls.
“You look at how the survey gets used and abused out in the public,” Wisersky said. “Two things happen when the survey is released to people who don’t deal with these kinds of things every day. One: I know what happens when you show these types of deficits — things get dicey. Two: [People ask if] the queue process is leading to resource inadequacy. And that’s what I’m worried about when people without knowledge of these get ahold of them.”
Westphal said MISO has time to collect stakeholder advice and refine the survey over the next several months.
BOSTON — Atlantic Canada, New York and New England are one region geographically, and the jurisdictions will be drawn into ever closer cooperation on energy.
That was the consensus among a dozen or so speakers at the 25th Annual Energy Trade & Technology Conference hosted by the New England-Canada Business Council on Nov. 8-9. Speakers also discussed proposed price supports for coal and nuclear generation and how FERC is likely to treat New England states’ contracting for renewables.
Battery for New England
Hydro-Québec CEO Eric Martel said that his company last year exported more than 15 TWh of electricity into New England, about 12% of what the region is consuming now. The company has partnered on six different projects being bid into Massachusetts’ recent clean energy procurement. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)
“Our large reservoirs have a combined annual energy storage of 176 TWh,” Martel said. “Today we are producing for the Canadian people 170 TWh/year [and] we are exporting about 30 TWh, which makes our production today at 200 TWh. But today our limit [on exports] is the number of transmission lines.”
Hydro-Québec began developing non-hydro renewable generation in the early 2000s and has since added 3,500 MW of wind capacity in Québec, Martel said.
“We firm up our domestic wind generation using our hydropower resources, so it’s very important that our source for firming is a renewable resource also,” he said. “We’ve been planning for this energy transition that is taking place, but what needs to happen now is to build those transmission lines. At peak periods, hydropower can be adjusted almost in real time, so Hydro-Québec can be the battery for northeastern America.”
NB Power CEO Gaëtan Thomas suggested how to connect the region to that huge battery.
“The only way to do that is more transmission,” Thomas said. “Transmission is king; transmission is going to solve these issues. Our vision should be to tie the whole region together and get to net zero [emissions]. That’s the only way we’re going to avoid the hits [caused by climate change] on the Eastern Seaboard. We’re all connected to it; we have that in common.”
DOE NOPR DOA?
Many speakers agreed that the U.S. Department of Energy’s recent Notice of Proposed Rulemaking in support of coal-fired and nuclear baseload generation wouldn’t amount to much, if anything.
But Concentric Energy Advisors CEO John Reed cautioned about being too optimistic.
“If we have one lesson from this administration, if you look at immigration or health care, the answer is, if at first you don’t succeed, tweet, tweet again,” Reed said. “If this doesn’t go somewhere, and if you look at the initiatives that have occurred in Ohio, Illinois and New York to support baseload generation, what is going to come down as the next mandate, the next executive order on these issues? Because I don’t think the administration’s concerns in terms of supporting coal and nuclear and other baseload generation are going to go away.”
“What I would expect — and PJM is already looking into it — is how to price things perhaps differently,” said Avangrid CEO James Torgerson. “And I think the other organized markets will probably be told to do the same thing. I think each RTO and ISO is going to be looking at it from their perspective, and [if there is] an issue in their area that needs to be dealt with. FERC will probably push it back to the different regions to get it resolved on a regional basis, because you can’t just say it’s a national or international problem at this point; it’s in certain pockets.”
Michael Twomey, vice president for external affairs at Entergy, defended nuclear energy’s role as an emissions-free resource. Nuclear power’s contribution to New England’s energy needs has remained generally unchanged because the retirement of Vermont Yankee was offset by upgrades and increased capacity from other units, he said.
“Oil has effectively disappeared from the landscape, coal is reduced significantly, and hydro and renewables honestly haven’t moved that much,” Twomey said. “We’ve seen tremendous gains in carbon emissions reductions in New England over the last 15 years, but that’s mainly been attributable to the substitution of natural gas for oil and coal. Well, the oil and coal is going to be gone — soon — and there’s not going to be any more low-hanging fruit to achieve carbon reductions, so what we’re going to see is probably an increase in carbon emissions from where we are now, going forward, as you see new retirements.”
An Accommodating FERC?
FERC is entering a much more “state-centric” cycle, according to Rob Minter, vice president for government and regulatory affairs at ENGIE.
“Confidence in the markets for maintaining things like fuel diversity to keep nuclear plants alive, to integrate renewables, to achieve public policy goals like carbon reduction does not fit with the market structure that we now have,” Minter said. “Everyone’s trying to build the type of plants they want for their own objectives, for their own fuel reliability, for economic development, to save stranded assets that are uneconomic and underwater but make sense, like a nuclear plant you need to continue to have low carbon. These are not compatible with the current wholesale market that was created in the 1992 Energy Policy Act.”
“You start wondering how much of this [NOPR] is about reliability and fuel diversity versus some of the generators who have coal and nuclear plants aren’t really making as much as they did in the past,” Torgerson said. “So those are things being debated right now.” He predicted FERC will set a technical conference so industry participants can examine the issue more thoroughly.
To implement different state public policies on clean energy requires out-of-market actions that are fundamentally incompatible with the wholesale market design, Minter said.
“You can find a way to price those attributes into the markets, but my god, you end up putting dozens of pricing mechanisms and algorithms into an already complicated market,” Minter said.
He said although he would prefer fully competitive markets, they have “very little chance of success.”
“I would like for it to work; I would like to see fully competitive wholesale markets,” he said. “But regulators are not willing to accept the risk of very high energy prices that happen during periods of scarcity.”
Leo Desjardins, CEO of Conservation Resource Solutions, said the new, fully staffed commission has arrived at an inflection point for markets.
“Massachusetts probably gets its way on Canadian imports [and] FERC figures out how to accommodate regional and state carbon pricing,” Minter said. “And I think you’ll see that [the] large renewable procurements that states want, that end up being out-of-market, get accommodated. Only for so long can a commission like FERC fend off states. If the number of states [asserting their public policy] grows, and as the frustration level grows, they eventually have to cave in and accommodate.”
VALLEY FORGE, Pa. — PJM’s Asanga Perera presented stakeholders at last week’s Planning Committee meeting with a problem statement and issue charge to address issues the RTO sees with its current process for evaluating market efficiency projects.
“We have conducted two cycles to date since FERC Order 1000 was established, and during these two cycles, we recognized various challenges that we think are important to address going forward,” he said.
One of the issues, Perera explained, is that PJM’s benefit-to-cost calculations beyond 10 years are extrapolations, not more accurate simulations.
“We have discovered, in certain instances, we may end up either overstating benefits or understanding benefits, especially on a longer horizon,” he said.
PJM also must address modeling issues, timing of the proposal-window process, interregional analysis and project re-evaluation, Perera said.
Sharon Segner of LS Power applauded the focus on the process but asked if it could go further.
“This is a great discussion in terms of some of the challenges that the market efficiency window is facing,” Segner said. “Is there anything missing?”
PJM staff resisted suggestions to include a review of cost calculations, saying that’s being handled elsewhere.
Segner also warned against making any retroactive changes.
“It’s important to not undermine the work of the past, because that’s going to create a lot of regulatory uncertainty,” she said.
If the initiative is approved, the work would be assigned to a task force, Perera said.
PJM has compiled some data to begin updating parameters for modeling light-load conditions. PJM’s Mark Sims presented the data.
“There’s definitely plenty of activity happening out there to draw some conclusions,” he said.
One focus is comparing high-voltage alarms with instances when high-voltage emergency procedures were taken. The alarms, which require generators receiving them to take action, precede emergency procedures that PJM takes.
“The alarm data is a good proxy to use moving forward to look for statistical values to develop parameters” for a test, Sims said.
PJM is also considering how to address the lag between recognizing an issue and compiling all the information to address it effectively.
“Between it happening and us fixing it, it could be a couple of years,” Sims said.
Mild weather meant load never came close to reaching the peak summer forecast, PJM’s John Reynolds said.
The summer peak of 145,331 MW on July 19 was 5% below the forecasted peak of 152,999 MW and 4.4% below the 2016 peak of 151,945 MW. “The champ still reigns,” Reynolds said, referring to PJM’s all-time peak of 166,876 MW on Aug. 2, 2006.
There were 0.4 MW of load management July 19, he said, and there have been anecdotal accounts of a “significant amount” of peak shaving this summer.
The decline in weather-normalized load won’t mean an immediate drop in load forecasts.
“That would be an assumption that people should not make,” Reynolds said. “It will take time for that to work its way in full.”
The call for patience confounded Calpine’s David “Scarp” Scarpignato.
“I don’t want to wait 18 years to get the forecast right,” he said.
ARR Analysis IDs Constraints
An analysis of Stage 1A 10-year auction revenue rights found “infeasible facilities” both within PJM’s footprint and in market-to-market interactions with MISO, Perera said.
The internal constraint will be addressed by a project (b2774) in the Regional Transmission Expansion Plan, which is expected to be in service in 2020. Of the remaining nine M2M constraints, one will be addressed by a MISO Transmission Expansion Plan project that is expected to be in service this year. Three others have projects under consideration, two will be included in a future targeted market efficiency project proposal window and three are pseudo-tie flowgates.
Asked specifically about lines connecting to the Ohio Valley Electric Corp. — which is attempting to join PJM as a transmission zone — Perera said no new issues were identified. A project between OVEC’s Clifty Creek Power Plant and the Trimble County substation is one of nine M2M constraints under consideration.
PJM’s markets were competitive in the first nine months of the year and energy prices were up $1/MWh compared to the same period last year, the Independent Market Monitor found in its quarterly State of the Market Report.
“Energy prices in PJM in the first nine months of 2017 were set, on average, by units operating at, or close to, their short-run marginal costs, although this was not always the case during high-demand hours,” the report said. “This is evidence of generally competitive behavior and resulted in a competitive energy market outcome.”
Quarterly total price and quarterly inflation adjusted total price ($/MWh): January 1, 1999 through September 30, 2017 | Monitoring Analytics
The load-weighted, average LMP in PJM was 3.5% higher in the first nine months of 2017 than during the same period in 2016, rising to $30.36/MWh. The Monitor said the increase was “primarily” due to higher fuel prices.
Coal and natural gas costs rose faster than electricity prices, undercutting generator revenues. Average energy market revenues decreased by 51% for new gas-fired combustion turbines, 28% for new combined cycle units and 17% for a new coal plant, while increasing 6% for nuclear units, the Monitor said.
Coal units’ dominance has dipped over time, while gas has risen. In 2008, coal represented 75% of the marginal resources and gas 20%. In the first nine months of this year, coal stood at 32.5% and gas rose to 52.9%, the Monitor said.
Monitoring Analytics
Wind continued to depress prices as the marginal unit. In the first nine months of 2017, 74.1% of the wind marginal units had negative offer prices, 18.9% had zero offer prices and 6.9% had positive offer prices.
Total energy uplift charges decreased $16 million (15.7%) to $86.3 million during the nine-month period. Demand response payments also decreased by $167.2 million (31.1%) to $370.6 million, while congestion costs fell $366.8 million (44.6%) to $455.4 million.
The impact of FERC’s ruling on balancing congestion — rejecting the notion that financial transmission rights are only intended to benefit load — was also evident this year. Revenues from auction revenue rights and FTRs offset 98.1% of total congestion costs for load during the 2016/2017 planning period, but only 79.7% of those costs for the first four months of the 2017/2018 planning period. In January, FERC accepted PJM’s compliance filing in response to the commission’s requirement that the RTO develop a method for allocating ARRs that doesn’t consider extinct generators. Under the new rules, PJM assigns balancing congestion to real-time load and exports and regularly updates its ARR allocations to reflect generator retirements. (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)
FERC last week opened a fresh settlement proceeding to determine the fairness of DTE Electric’s decreased revenue requirement for reactive power services, an issue already under scrutiny by the agency (ER17-2465).
DTE in April asked the commission to approve an $11 million annual revenue requirement for reactive supply in the ITC transmission pricing zone, down 14% from the current $13 million requirement (ER17-1414). The Detroit-based utility submitted the revised request in September to account for an additional $118,000 decrease stemming from the Nov. 14 retirement of St. Clair Unit 4, an aging coal-fired generator. The first request had been under settlement proceedings for four months by the time of the second filing (EL17-71).
St. Clair Power Plant | Inland Mariners
The company cited seven retirements, increased investments in generation units that provide reactive service, and the replacement of its total revenue requirement with unit-specific revenue requirements as reasons behind the rate decrease.
FERC said preliminary analysis shows that DTE’s rate schedule may still be unreasonable even with the $118,000 decrease, and consolidated the newly opened settlement proceeding with the existing one under a new docket, EL18-23.
“Because DTE Electric is proposing a rate reduction, but a further rate decrease may be appropriate, we will institute a Section 206 proceeding,” FERC wrote.
FERC last week approved SPP’s proposal to change the way it prices regulation and operating reserves but said the RTO should respond to complaints that it overuses out-of-market procedures to avoid scarcity pricing.
The ruling, effective May 11, 2017, finalized a tentative approval granted by FERC staff in August before the commission regained its quorum (ER17-1092).
The changes were in response to FERC’s June 2016 ruling (Order 825) requiring RTOs and ISOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period. (See FERC Issues 1st RTO Price Formation Reforms.)
SPP previously set a single administrative scarcity price for each reserve product regardless of the severity of a shortage. Under the new rules, the RTO will use segmented demand curves with higher degrees of scarcity resulting in higher prices. It is also renaming its operating reserve demand curve as the contingency reserve demand curve.
In approving the changes, the commission rejected a complaint from Golden Spread Electric Cooperative that the regulation demand curves should begin with a steeper slope to incentivize units to provide regulation earlier.
“We find that SPP has supported the structure of the proposed contingency reserve demand curve, which is based on NERC requirements for SPP to carry reserves to protect against loss of the largest online resource in its footprint and based on the contingency reserve the [Reserve Sharing Group] procures to protect against the loss of half of the second largest online resource in the SPP footprint,” FERC said.
However, it directed SPP to add to its Tariff definitions and other details of the new rules, which the RTO had planned to include in its Marketplace Protocols. “The commission has found that provisions that are used to calculate a rate should be included in the Tariff because they significantly affect rates, terms and conditions of service,” the order said.
The commission also rejected Golden Spread’s complaint that SPP has prevented the implementation of shortage pricing by overusing out-of-market actions such as reliability unit commitments and manual commitments.
Golden Spread Electric Cooperative complained that SPP’s shortage pricing rules are insufficient, depressing prices for plants that can respond quickly to scarcity conditions. Its Antelope Station, near Abernathy, Texas, can reach its full 168-MW output in five minutes. | GSEC
Although the commission said Golden Spread’s call for market design changes regarding such actions was outside the scope of the proceeding, it said the cooperative had “raised an important issue that SPP should consider exploring through its stakeholder process.”
“We understand that there may not be sufficient data available to stakeholders to facilitate these discussions, as the commission noted in its Notice of Proposed Rulemaking in Docket No. RM17-2,” the commission said, referring to its January 2017 proposal to reduce uplift, allocate it more accurately and increase transparency. (See FERC Seeks More Transparency, Cost Causation on Uplift.)
“While further commission action in Docket No. RM17-2 may result in additional transparency, we encourage SPP to work with its stakeholders and provide them with the data necessary to aid in any discussions about this issue.”
CAMP HILL, Pa. — Pennsylvania, which was among the first states in the U.S. to abandon cost-of-service electric regulation, now finds itself at ground zero of a debate that could largely reverse the process. So last week’s 7th Annual Pennsylvania Energy Management Conference couldn’t have been more timely.
FERC Chief of Staff Anthony Pugliese, who grew up just a few miles from here, praised the Department of Energy’s Notice of Proposed Rulemaking to support struggling coal and nuclear generators, while promising it would not destroy PJM’s competitive market.
And PJM Independent Market Monitor Joe Bowring, who shared a panel with Barron and NRG’s Abe Silverman, continued his attack on the RTO’s proposed alternative. (See related story, NOPR Reply Comments Bring More Criticism of PJM Proposal.)
Stranded Costs
Pamela C. Polacek, an attorney with McNees Wallace & Nurick, one of the conference’s sponsors, joined in the criticism. Her firm has long represented industrial customers and was central to Pennsylvania’s move — following California and Massachusetts — to customer choice in 1996.
Pennsylvania consumers paid $12.3 billion in stranded costs to Exelon’s PECO Energy and other nuclear plant owners between 1996 and 2010 as part of the bargain to unbundle generation from distribution. Polacek said subsidies for all of Pennsylvania’s nuclear plants could cost $1.2 billion per year — raising the annual electric bill for a small industrial user (12 million kWh/year) by more than $100,000, and that for a steel mill (330 million kWh/year) by $2.8 million.
“We can’t afford this in Pennsylvania,” she said. “We rank 48th in manufacturing job creation. … We can’t continue to pile costs onto our industrials. Right now, our average industrial electric rate is about the middle [of the states]. But remember, we did this [retail choice] back in 1996 to get competitive advantage, not just to be in the middle.”
Polacek said Three Mile Island Unit 1, the only planned nuclear retirement in Pennsylvania, doesn’t deserve a rescue.
“As Joe has said, other Pennsylvania nuclear plants continue to clear the [capacity] auction. For the most part, they are not at risk of retirement.”
Investment
She acknowledged that as a single-reactor plant (following the partial meltdown of Unit 2 in 1979) TMI does not have the labor economies of scale of multi-unit plants. But she said saving TMI’s 750 workers would cost jobs in manufacturing because of higher electric rates.
“Three Mile Island didn’t really take the opportunities to do upgrades that other Pennsylvania-based plants did. So those plants were looking at investing in their infrastructure to expand their capacity, to be more efficient. And Three Mile Island didn’t do that.”
Barron disputed Polacek’s claim of underinvestment. “I can tell you we continue to invest very heavily in Three Mile Island, having replaced the steam generator … and [made] other investments,” she said.
She cited a Brattle Group study that predicted early retirement of the state’s nine nuclear generators would increase prices by $788 million per year, a 5% increase.
Resilience
The two also sparred over nuclear power’s value to the grid’s resilience.
“Looking at the idea of having onsite fuel supply as being something that is going to help us if all four gas pipelines serving the Northeast go down, I have to ask: Well if the terrorists do that, what’s going to stop them from also targeting the nuclear plants, which would seem to be a pretty attractive, World Trade Tower-type targets?” Polacek said.
Barron said nuclear plants’ defenses against terrorists are second to none. “We are so heavily regulated by a number of regulators, including the [Nuclear Regulatory Commission], on this specific point, on the amount of security we have to have in our plants and the ways that we need to protect them,” she said. “There are more people who [are carrying] guns than people who are operating the plant. … We do not have anywhere near that kind of protection on the natural gas supply system.”
That is beside the point, responded Bowring, saying the vulnerabilities of gas pipelines also apply to electric transmission. “It doesn’t matter what the fuel type is if the transmission grid is not there,” he said. “So, you have to be careful how far you extend this argument.”
NRG’s Silverman said that he agreed with the DOE on the need for price-formation reforms. But he said zero-emission credits for nuclear plants are not a good solution. ZEC prices in New York and Illinois will produce half as much carbon-free electricity as equivalent spending on renewables, he said.
“It completely ignores the energy market response. Completely ignores the power of competition to find cheaper solutions and drive down the price,” he said.
“We have these price-formation initiatives at FERC that have now been pending, in some cases, for four or five years. They need to be acted on. I mean come on guys, yes or no.”
And he said the issue is broader than price formation. The challenge, he said, is creating incentives for what NRG calls the “four-product future,” which envisions renewables providing most energy, supported by storage, controllable demand and fast-ramping gas. NRG says it will reduce the carbon emissions from its generation 50% by 2030 and 90% by 2050.
“A [gas-fired] power plant built today is already going to be lasting until 2050 and [will] be emitting too much carbon” to address climate change, Silverman said. “So, we end up with this long-term stranded cost environment where today’s gas plants are tomorrow’s coal plants.”
