MISO’s proposal to put time limits on its alternative dispute resolution process with RTO members is still missing key details, FERC said Monday.
In a deficiency letter issued July 30, the commission asked MISO for multiple specifics on its plan to set limits on the amount of time MISO members have to initiate alternative dispute resolution measures with the RTO over market settlements (ER18-1648).
MISO’s alternative dispute resolution process is used in place of a lawsuit or FERC complaint when parties seek to negotiate contractual disputes over settlements. The RTO’s current Tariff doesn’t contain provisions that “categorically bar settlement disputes raised after a long time,” according to MISO.
MISO has proposed giving members a limit of 90 days to request either an informal or formal alternative dispute resolution and 120 days for MISO and members to resolve settlement disputes. MISO itself would have two years from the operating day in question to make resettlement corrections. Resettlement outside of the two-year cutoff would require MISO and the participant to seek a Tariff waiver with FERC.
MISO’s May Tariff filing provided for a two-year limit for adjustment of “any billing, invoice or settlement statement with respect to any transmission service under the Tariff” and “any settlement statement with respect to any market activity or other service under the Tariff” involving “a system or software error of the transmission provider.”
But FERC has asked MISO to define the terms “system error” and “software error.” It has also ordered MISO to define the meaning of “readily discoverable, one-time MISO errors” and asked if the RTO foresees any short-term errors that are not “readily discoverable.”
The commission is also requiring MISO to clear up when the 90-day timeframe begins and if an “extended delay in the resolution of a settlement dispute or [an alternative dispute resolution] dispute by MISO” could possibly limit the resettlement of incorrect billings under the two-year limit.
FERC also inquired about a hypothetical situation raised by MidAmerican Energy in its comments on the proposal , which said that MISO could violate its two-year correction deadline if a months-long error is discovered and the resettlement period needs to extend to before the operating day or invoice date in question. FERC asked if MISO planned to file an amendment to allow for resettlement for more than two years for such a scenario.
FERC also questioned language in the proposal saying MISO “may make an appropriate adjustment” in “cases involving a system or software error of the transmission provider.”
“The word ‘may’ suggests that MISO is under no obligation to make the ‘appropriate adjustment’ even if a system or software error results in a Tariff customer paying an incorrect amount. Please explain why it is appropriate for MISO to have this discretion,” FERC said.
Lastly, the commission ordered MISO to clarify whether the alternative dispute resolution will apply to both market settlement disputes and transmission service disputes. FERC said certain sections of the proposal indicated it would apply only to market settlement disputes.
MISO lengthened the cutoff periods from the original proposal after stakeholders earlier this year expressed concerns they would need longer than 30 days to research and raise settlement disputes and longer than one year to make settlement corrections. (See MISO Considering Time Limits on Dispute Resolution.) MISO did not propose to place a dollar limit on resettlements. The RTO was aiming to have the deadlines imposed in July.
New York transmission owners will be eligible for full cost recovery when regulated backstop solution reliability projects are canceled, FERC said last week, clarifying a 2017 order (ER17-2327-001).
The TOs asked for clarification or rehearing of the commission’s Oct. 17, 2017, order approving revisions to NYISO Rate Schedule 10, which were intended to expand its applicability for all regulated projects resulting from the ISO’s reliability, economic or public policy-driven transmission planning processes.
| NYSEG
The TOs said they were concerned about the 2017 order’s reference to Order 679, which implemented incentives ordered by Congress under Section 219 of the Federal Power Act and allows a public utility receiving a reliability incentive to recover only up to 50% of prudently incurred costs in abandoned projects.
The commission’s July 25 order clarified that Order 679 did not affect the TOs’ previously established right to 100% recovery on a reliability project if the ISO cancels it as unnecessary or if the project cannot be completed because of the failure to obtain necessary permits.
The commission approved the 100% recovery as part of the ISO’s Reliability Agreement in 2004. “This occurred before the promulgation of FPA Section 219 and the commission’s regulations issued in Order No. 679 implementing Section 219,” the commission said. “New York transmission owners’ right to cost recovery was thus not approved as an incentive under Section 219, nor could it have been.”
The order directed the ISO to remove the abandoned plant recovery provisions to avoid any ambiguity in the Tariff.
VALLEY FORGE, Pa. — Seeing no hope to resolve a nearly two-year standoff on supplemental projects for replacing end-of-life transmission infrastructure, PJM stakeholders are seeking a new tack after voting last week to sunset the Transmission Replacement Process Senior Task Force (TRPSTF).
PJM’s Fran Barrett, task force administrator, provided a report on the group’s recent activity. Factions in the task force have been at odds, and RTO staff attempted to put it on hiatus at its most recent meeting. (See PJM Seeks to Suspend Task Force in ‘Unprecedented’ Move.)
Following the review, American Municipal Power’s Ed Tatum motioned to sunset the TRPSTF because “it doesn’t seem fruitful to continue on.” Old Dominion Electric Cooperative’s Adrien Ford seconded it, but Dominion Energy Marketing’s Jim Davis suggested that any action on disbanding the task force should wait until the D.C. Circuit Court of Appeals rules on ODEC’s request to overturn FERC’s policy of allocating all costs from Form 715 projects to the zone of the transmission owner whose criteria triggered the upgrades. (See FERC OKs Cost Allocation of PJM Transmission Projects.)
LS Power’s Sharon Segner called that case “potentially a gamechanger,” along with a CAISO complaint pending at FERC.
“Those two are the external factors that change the debate here. … My view is that [the TRPSTF] hasn’t been a particularly productive task force,” she said.
PJM and its TOs submitted compliance filings in March in response to a commission ruling that TOs weren’t properly complying with their obligations under Order 890 to provide stakeholders with adequate information on supplemental projects — transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria.
Tatum said approval and implementation of the compliance filings will go on with or without the task force, so putting it on hiatus would remove any chance for all stakeholders to be involved in determining “the meat of what would actually be in those meetings” required by FERC’s order.
Barrett said the task force has been tasked with navigating “a strange intersection between the stakeholder process and a [FERC] directive that’s before the TOs and PJM,” but “we are at the end, and we were gearing up for a vote.”
He confirmed, following an inquiry from Tatum, that no one has voiced an opinion to him either way on whether to continue the task force. Tatum acknowledged it “has been the most unusual stakeholder process I’ve ever been involved in.”
GT Power Group’s Dave Pratzon called the task force “duplicative” and “not a great idea.” He endorsed sunsetting it in favor of developing a way to address the issues on a comprehensive scale.
“We appreciate it and that it has been moving at a good clip and it certainly has slowed down,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS). “Where it goes from here is a question, but it certainly has been useful.”
The motion was endorsed by stakeholders.
Tatum then offered a proposal that would define what information must be presented at each of the meetings required by FERC. AMP’s proposal would attempt to fully use each end-of-life project to address any reliability violations and seeks to define the dispute resolution process for challenging project proposals.
The proposal reflects many of AMP’s proposals in the task force but “softened” some of them so that it “erred on the side of what we think the TOs would say,” Tatum explained.
Pratzon called Tatum’s proposal “totally inappropriate” because it hadn’t been vetted through a lower committee. Several TO representatives agreed. However, load interests continue to be interested in addressing the concerns raised in the task force.
“The issues remain. I don’t feel like we’re to the finish line. Certainly, my members care deeply about these issues,” said Susan Bruce, representing the PJM Industrial Customer Coalition.
PJM staff questioned several of Tatum’s contentions that the proposal wouldn’t adversely impact the delicate timing of the Regional Transmission Expansion Plan process, among them that projects in dispute resolution would not hang in limbo. Tatum agreed to continuing to work with staff and acknowledged that staff do not agree with AMP’s belief that it would work without a hitch.
FERC last week approved a $115,000 civil penalty against Entergy for failing to promptly inform ISO-NE of the inability of its Rhode Island gas-fired generator to meet its capacity obligations because of pipeline restrictions.
The commission’s July 25 order accepted an agreement between Entergy and the Office of Enforcement assessing the civil penalty and requiring reimbursement of $47,084, plus interest over the 2013 incident (IN18-5).
Entergy’s Rhode Island State Energy Center (RISE), a two-unit combined cycle natural gas plant, was paid $1,459,610 a month for 575 MW of capacity during delivery year 2013/14. (The company sold RISE to the Carlyle Group in 2015 for $490 million.)
Rhode Island State Energy Center | Entergy
Enforcement’s investigation found that, despite becoming aware at approximately 9:30 p.m. on Dec. 26, 2013, that it would be unlikely to meet its capacity commitment for the next day because of pipeline problems, Entergy waited until the following morning to contact the RTO about the issue.
RISE had a contract for firm transportation service with Tennessee Gas Pipeline for up to 45,000 Dth/day, which allowed it to bank in its “operational balancing account” (OBA) gas unneeded on a given day for future use.
On the morning of Dec. 26, Entergy offered RISE into ISO-NE’s day-ahead market. RISE received a commitment for 9,900 MWh. Entergy planned to use about 36,540 Dth from its OBA to meet the capacity obligation, which it determined would require 71,540 Dth of gas to produce.
On Dec. 18, however, TGP had issued a “Critical” notice to shippers saying it anticipated potential disruptions in service and that customers should “match physical flow with scheduled volumes.” On Dec. 26, Tennessee issued another notice, warning of restrictions on gas delivery downstream of its compressor station in Agawam, Mass., including RISE.
Despite low gas delivery pressures, Entergy began operating RISE at 2:45 a.m. on Dec. 27. “RISE not only took gas volumes it had scheduled from Tennessee but attempted to pull additional gas volumes from the pipeline,” according to Enforcement’s settlement agreement with the company.
RISE was able to meet its offer and ramp rate for about an hour, but when pipeline pressures continued to drop, Entergy contacted ISO-NE at 5:31 a.m. to advise that the plant could not meet its obligation. With ISO-NE’s approval, RISE operated at a reduced level of 310 MW for the remainder of the operating day, while the RTO dispatched other generators to fill the gap.
Enforcement concluded Entergy’s violations were the result of a “failure to exercise sufficient diligence” to ensure that RISE was able to meet its dispatch obligations but that it did not intend to violate the RTO’s market rules.
FERC said its penalty also reflected Entergy’s cooperation in the investigation and the steps it has taken to prevent repeat violations.
Environmentalists and industrial gas consumers last week challenged a Department of Energy-funded study that concludes U.S. economic growth would be boosted by unlimited LNG exports — even if they double current natural gas prices.
More than a dozen comments were filed by the July 27 deadline in response to the June 7 study, performed by NERA Economic Consulting for the department’s Office of Fossil Energy. DOE said it plans to consider the study in responding to 25 pending applications for LNG exports to countries lacking free-trade agreements with the U.S.
Although there is a consensus that exporting too much domestic natural gas could expose U.S. consumers, industrial users and electric generators to much higher world prices, there is no agreement on what that tipping point is, or how soon the U.S. could get there. (See No Agreement on Tipping Point for LNG Exports.)
The NERA study — the fifth DOE has commissioned since 2012 examining the economics of LNG exports — suggests that policymakers should not worry about any price increases, finding “consistently positive relationships between LNG exports and measures of economic performance” such as gross domestic product and U.S. living standards.
The Natural Gas Act requires DOE to determine whether natural gas exports to countries without FTAs with the U.S. are in the “public interest.” Exports to countries with FTAs do not require such reviews.
The Industrial Energy Consumers of America (IECA) said the DOE study “confirms that excessive volumes of LNG exports to non-free-trade agreement countries is not in the public interest under the Natural Gas Act.”
The group, which represents 3,700 U.S. manufacturing facilities, said it is not opposed to LNG exports. “We are against excessive LNG exports which would result in U.S. prices being dictated by global demand like crude oil is today.”
IECA said the Supreme Court has defined “public interest” under the NGA as requiring “plentiful supplies … at reasonable prices.”
U.S. Henry Hub Prices Across the More Likely Range of U.S. LNG Exports in 2040 | NERA Economic Consulting
“The study’s most likely scenario assumes that LNG exports up to 30.7 Bcfd could increase prices 117% above today’s Henry Hub prices by 2040 and 44% above the [Energy Information Administration’s Annual Energy Outlook] 2018 price (which assumes only 14.5 Bcfd of LNG exports),” IECA said. “Such price hikes plainly threaten the plentiful supply of natural gas at reasonable prices for domestic consumers.”
Other Comments
The American Petroleum Institute said it agrees with the study’s conclusion of a “consistently positive relationship” between LNG exports and U.S. economic performance. “The study thereby confirms what multiple past studies have concluded, which is that U.S. LNG exports are a clear net benefit to the economy and are therefore in the public interest,” wrote Todd Snitchler, API’s director of market development.
The US LNG Association said the study should allow DOE “to grant approvals to all U.S. LNG export applications to non-FTA countries without the need for any further macroeconomic studies” for at least four years.
Environmental groups criticized the study for ignoring the costs of climate change and the growth of renewable energy.
“The study should be adjusted to give much greater emphasis to low demand scenarios that align with the Paris Climate Agreement,” said a coalition of more than 60 groups in the U.S., Canada and Europe, including Food & Water Watch, 350.org and the Center for Biological Diversity. “Even if minimal progress in international climate policy making was a robust assumption, the study fails to assess the real-world trends occurring with renewable energy and the threat they pose to gas demand. The study does not attempt to either account for substantial progress in renewable energy installations and cost reductions made in recent years or assess projections of substantial progress to come.” (See How Long a Bridge for Natural Gas?)
54 Scenarios
The DOE examined 54 scenarios based on four major sources of uncertainty affecting U.S. LNG exports: natural gas supply conditions in the U.S.; natural gas demand in the U.S.; and gas supply and demand in the rest of the world. None of the scenarios limited LNG export volumes.
It found a 68% probability that LNG exports will be between 9 and 30.7 Bcfd in 2040. DOE has approved 21.4 Bcfd of LNG exports to non-FTA countries. The DOE study said there is a 12% probability that exports will reach that level by 2030 and a 63% chance of hitting that level by 2040.
About 80% of the increase in LNG exports would be satisfied by increased U.S. natural gas production, “with positive effects on labor income, output and profits in the natural gas production sector,” the study said.
“The higher world prices that bring forth those supplies improve U.S. terms of trade, so that there is a wealth transfer to the U.S. from the rest of the world equal to the increase in prices received for LNG exports times the quantity exported. The transfers from natural gas related activity to the U.S. economy improve the average consumer’s ability to demand more goods and services leading to higher economic activity,” NERA said.
“These two factors more than make up for the dampening economic effects that are observed in these scenarios, including slightly slower output growth of some natural gas-intensive industries, costs of substituting other fuels for a small fraction of natural gas use in power generation, and infinitesimal reductions in natural gas use by households and other industries.
“Even the most extreme scenarios of high LNG exports that are outside the more likely probability range, which exhibit a combined probability of less than 3%, show higher overall economic performance in terms of GDP, household income and consumer welfare than lower export levels associated with the same domestic supply scenarios,” the study said. “It is also important to note that our analysis also shows that the chemicals subsectors that rely heavily on natural gas for energy and as a feedstock continue to exhibit robust growth even at higher LNG export levels and is only insignificantly slower than cases with lower LNG export levels.”
GDP Increases with Rising Levels of LNG Exports within the More Likely Range of Scenarios in 2040 | NERA Economic Consulting
But IECA President Paul Cicio said the study “lacks credibility due to … the inability of the economic models to determine whether the oil and gas industry is consuming U.S. or imported goods to produce, transport and build LNG terminals, thereby overinflating economic growth and job projections due to LNG exports.”
IECA said the study’s conclusions conflict with that of a 2012 NERA study that acknowledged the difficulty of forecasting natural gas prices and that the new study uses proprietary NERA models that cannot be replicated by third parties.
Trump Administration Promoting Exports
The Trump administration has praised LNG exports as evidence of the nation’s “energy dominance.”
Dominion Energy’s Cove Point LNG terminal is the second operating export facility in the U.S. | Dominion Energy
Last Thursday, Energy Secretary Rick Perry appeared at a ribbon cutting for Dominion Energy’s Cove Point LNG export facility in Maryland, the second in the U.S. Perry noted that the U.S. is exporting natural gas to 30 nations and last year became a net gas exporter for the first time in 60 years.
Also last week, DOE finalized rules to eliminate public interest reviews for “small-scale” LNG exports to non-FTA countries. The rules, effective Aug. 24, apply to applications to export no more than 51.75 Bcf/year.
FERC last week granted AEP Energy Partners’ request to transmit power between ERCOT and Mexico over existing DC tie connections, easing concerns that the Texas grid operator might find itself subject to the federal agency’s jurisdiction (TX18-1).
The American Electric Power subsidiary made the request on behalf of Sharyland Utilities, AEP Texas and Electric Transmission Texas. The DC tie operators asked the commission to allow them to provide transmission service over the ties and to confirm that the ties’ use would not subject ERCOT or any of its market participants to FERC jurisdiction.
Texas officials have expressed unease that a pair of transmission projects along the U.S.-Mexico border could place ERCOT’s freedom from federal jurisdiction in jeopardy.
The ISO’s transmission grid is located solely within the state and not synchronously interconnected with the rest of the U.S. Under the Federal Power Act, FERC has no jurisdiction over transmission lines that cross international boundaries if they don’t also cross U.S. state lines. ERCOT has several synchronous (AC) and asynchronous (DC) ties with Mexico, but energy does not flow between Texas and other states through Mexico’s national grid.
| Mexico Ministry of Energy
Public Utility Commission Chair DeAnn Walker has said the federal agency could exert its jurisdiction over ERCOT through the U.S. Constitution’s Commerce Clause “if the commingling of power between ERCOT and the rest of the United States occurs.” (See Regulators Fear Cross-Border Tx Risks ERCOT’s FERC Exemption.)
Sharyland sister company Nogales Transmission has applied for a presidential permit to build an HVDC interconnection between Arizona and Mexico (OE PP-420). Nogales last year asked the Department of Energy to delay processing its permit until it can obtain “the necessary FERC disclaimer” of jurisdiction.
Further west, Mexico is considering a major project that would link the state of Baja California, which is part of the Western Electricity Coordinating Council, with the rest of the country’s grid and with California.
ERCOT said it was pleased with the FERC order. “[It] alleviates any current or future jurisdictional concerns resulting from new interconnection projects with Mexico and other neighboring states,” spokesperson Leslie Sopko told RTO Insider.
AEP asserted that if FERC granted the parties’ request, the DC ties would become facilities for the transmission and wholesale sales of electric energy in interstate commerce “solely by reason of” a commission order.
“The continuing operation of the ties in compliance with the requested Section 211 order would not cause the tie operators to become ‘public utilities’” as defined by the FPA, the utilities said.
Commission Eases 2006 Requirements on Westar Energy
The commission on July 27 granted Westar Energy’s request to remove mitigation measures and reporting requirements imposed in connection with its 2006 acquisition of a ONEOK Energy Services gas plant (EC06-48).
Westar asked FERC to remove the measures and quarterly and annual reporting requirements, saying that changes in the SPP market since the 2006 acquisition made the decade-old requirements no longer necessary. SPP went live in 2014 with its Integrated Marketplace, which included day-ahead, real-time and financial transmission rights markets, and a consolidated balancing authority that replaced 16 legacy BAs.
In approving Westar’s acquisition of ONEOK’s 300-MW Spring Creek facility and a 75-MW power purchase agreement from the Oklahoma Municipal Power Authority (OMPA), the commission ordered the utility to increase transfer capabilities into its BA to reduce its 42% share of the market.
Westar requested a clarification of the order, committing to not use 225 MW of network integration transmission service during the winter period. The commission granted the request, but OMPA in 2007 requested a rehearing. FERC asserted Westar had asked SPP to move Spring Creek from the Oklahoma Gas & Electric BA to Westar’s, undermining the mitigation alternative. FERC agreed, directing that Westar continue to model the facility in OG&E’s BA.
Westar filed its request in 2016, arguing that SPP’s consolidated BA meant its market share should be measured using the RTO’s entire capacity, rather than that of the utility’s former BA area. It also pointed out that the OMPA contract had expired in 2015.
SWEPCO ROE with East Texas Co-ops Reduced
FERC on July 26 approved a settlement agreement between Southwestern Electric Power Co. and two East Texas cooperatives, East Texas Electric (ETEC) and Northeast Texas Electric (ER18-1560).
The settlement reduces SWEPCO’s return on equity with ETEC from 11.1% to 10.1%, effective Sept. 1, 2017. It also revises the utility’s formula rate templates that govern its power supply agreements with the two co-ops.
VALLEY FORGE, Pa. — PJM’s effort to include variable operations and maintenance (VOM) costs in energy market cost-based offers appears to be on its way to FERC following a long-awaited vote to revise the current rules at last week’s meeting of the Markets and Reliability and Members committees.
Stakeholders rejected five proposals, including one of them twice, after which PJM’s Stu Bresler indicated the RTO might recommend its Board of Managers approve changes anyway. He said his starting point for the recommendation would be PJM’s proposal, which was twice rejected in its original form and also in a revised alternative motion.
Stakeholders said they would keep a close watch on what recommendation staff develop, and Brian Wilkie with Rockland Electric Co. (RECO) called Bresler’s plan “disappointing.”
The initial proposal was sponsored by American Electric Power and would allow use of default U.S. Energy Information Administration calculations for the amount of VOM costs allowed in offers. The proposal was rejected with a sector-weighted vote of 2.28 in favor and 2.72 opposed. Such sector-weighted votes have a threshold of 3.35 to be endorsed.
AEP’s Brock Ondayko had been promoting the proposal as preferable to a proposal from RECO because it used data that were independently developed and published.
“What we have proposed, and what was accepted earlier, is this concept of using data from an independent provider that has no agenda or opinion of PJM’s markets,” Ondayko said. “The point is there’s actual data. … Nothing is hidden from public view. … There’s no data with the potential defaults in the other package.”
PJM’s proposal remained unchanged from past discussions as the only one that would allow units to include fixed costs in their energy offers if they failed to clear in the year’s capacity auction. It was also rejected with 2.86 in favor and 2.14 opposed.
The Independent Market Monitor’s proposal would limit costs allowed in energy offers to “short-run marginal costs,” which would be defined. The proposal was rejected with 1.83 in favor and 3.17 opposed.
“This is about the prevention of market power,” Monitor Joe Bowring had said prior to the vote, noting that PJM’s manuals don’t clearly define several related components.
RECO’s proposal was meant to strike a compromise between generator-friendly and load-friendly proposals to ensure that stakeholders wouldn’t be stuck with the status quo if coalitions stood their ground and those proposals failed to win endorsement, Wilkie said. It would allow generators to recover VOM costs up to limits that would be posted into Manual 15. Almost all unit types would be capped at $3.50/MWh for the costs. Sub- and super-critical coal and biomass would be capped at $4/MWh; nuclear at $3/MWh; and wind, solar and hydro at $0/MWh.
“I agree. They’re not based on data,” Wilkie said in response to Ondayko’s comments. “They’re a compromise between the data the IMM thinks is reasonable and the data EIA thinks is reasonable.”
He said his customers would benefit most from the Monitor’s numbers, but he was particularly concerned with the appearance that generators were simply trying to increase revenues by moving the costs to the energy market as opposed to the capacity market, where they’re currently allowable.
“If it’s just and reasonable for these costs to be in the unit’s capacity offer, then it’s hard to understand how it can instead be just and reasonable for them to be in the energy offer. It can be one or the other, but toggling those costs back and forth based on where generators think there’s going to be the most money doesn’t seem like a sound market design principle,” Wilkie said.
Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS), agreed with that perception.
“I would call that market shopping. … That’s a concern,” he said.
However, Exelon’s Jason Barker said many asset owners agreed RECO’s proposal “parrots” the Monitor’s proposal.
The proposal had a similar voting result with 1.97 in favor and 3.03 opposed.
Stakeholders next voted on an alternative proposed by Adrien Ford with Old Dominion Electric Cooperative. Ford had offered a friendly amendment to the PJM proposal to remove the language that allowed units to include fixed costs in their energy offers if they failed to clear in that year’s capacity auction so that the package aligned with the other three.
Staff wanted to “get a read” on favorability for the package that was originally endorsed at the Market Implementation Committee meeting, so they did not consider it friendly. Because it was the motion endorsed by the lower committee, a stakeholder had to object to the motion being friendly, so Citigroup Energy’s Barry Trayers did so.
Ford then offered it as an alternative motion, but it too was rejected, receiving 2.65 in favor and 2.35 opposed.
American Municipal Power’s Steve Lieberman motioned for a revote of the original PJM proposal, which was seconded by Trayers, but that was also rejected, receiving 2.93 in favor and 2.07 opposed.
Following the vote, Bresler informed stakeholders that PJM may not be satisfied with retaining the status quo and might consider making its own recommendation to the Board of Managers. He said he would “start” with PJM’s proposal as the basis for the recommendation.
Susan Bruce, representing the PJM Industrial Customer Coalition, promised “robust oversight” of staff’s development of the potential recommendation.
Wilkie called Bresler’s announcement “disappointing.”
Asked to opine on PJM’s rules for such situations, CEO Andy Ott said he felt the board being informed of stakeholders’ voting record on the issue would provide enough evidence of their preferences so that the board would be properly informed before considering staff’s recommendation.
At the Members Committee meeting that followed the MRC, stakeholders voted to adopt the MRC votes so that the board would be informed.
VALLEY FORGE, Pa. — PJM stakeholders at last week’s meeting of the Markets and Reliability and Members committees unanimously endorsed proposed revisions for aggregating seasonal resources.
PJM’s Andrea Yeaton presented the revisions, which would allow for dispatching resources individually based on their seasonal ability but account for them cumulatively for the purposes of Capacity Performance. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Independent Market Monitor Joe Bowring reiterated a request that the rules be amended to explicitly state that PJM has the authority and ability to call on resources without calling all resources in a zone and does not have to schedule the dispatch a day ahead.
“I think it’s less than clear” in the current language, Bowring said.
Default Details
PJM’s Suzanne Daugherty announced that the RTO submitted a request to FERC for waiver of rules requiring staff to liquidate “the large [financial transmission rights] portfolio of a recently defaulted PJM member.” The waiver would “reduce [PJM’s] liquidation of GreenHat’s portfolio to only the portion of the FTR portfolio that is about to become effective for the next calendar month, for each monthly auction for the period from the FTR auction conducted in July until the FTR auction conducted in October” (ER18-2068).
Staff had planned to liquidate the FTR positions in a way that minimizes the resulting burden on all other market participants, who will end up covering the remaining defaulted amount. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)
However, PJM said in its filing that it “has encountered adverse pricing effects of attempting to maximize the liquidation of this portfolio irrespective of price,” specifically in the most recent auction that closed on July 27.
“For periods with less liquidity … this large portfolio in combination with PJM’s obligation to offer a price designed to maximize the likelihood of liquidation, irrespective of a price floor, would essentially cause the prices to significantly diverge from the expected day-ahead price outcomes,” PJM said. “An unbounded liquidation of a large FTR portfolio for periods with less liquidity can and will cause a market disruption event and result in distorted market outcomes that may be unjust and unreasonable.”
The waiver “will provide PJM with time to further communicate with stakeholders regarding the concerns of the current Tariff-imposed liquidation process given the significant default allocations that will be incurred under the current liquidation process and to discuss any alternative liquidation process the PJM members may prefer be applied after the FTR auction conducted in October.”
Fuel Security
Because the MRC and MC ran late, a special MRC meeting scheduled to follow the meetings was postponed. A meeting of the now-sunset Transmission Replacement Process Senior Task Force was scheduled for July 31, so staff moved the fuel security session to that time slot. Staff plan to announce they have almost completed the base case for studying the impacts on the system from several fuel-security related contingencies, such as extreme cold weather or gas pipeline interruptions.
Manual Revisions Approved
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 14A: New Services Requests Study Process and Manual 14G: Generation Interconnection Requests. PJM sought to split out part of Manual 14A into a new Manual 14G to better organize interconnection information. (See “Interconnection Procedure Split,” PJM PC/TEAC Briefs: June 7, 2018.)
Revisions to the Reliability Assurance Agreement and Manual 18 associated with changes developed by the Demand Response Subcommittee to address issues identified with atypically low customer load during the winter peak load (WPL) calculation period. The Market Implementation Committee endorsed the changes in June. The proposal would use measurement and verification processes that already exist for a similar process and minimize administrative adjustments. It would define “low usage” days as less than 35% of the five-day WPL average and allow the exclusion of up to two such days from the WPL calculation. The measure was also endorsed at the MC via the consent agenda. (See “Now is the Winter of Our Discontent (with DR Rules),” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
Tariff revisions to implement a 10-cent/MWh minimum monthly credit requirement for FTR bids submitted in auctions and cleared positions held in FTR portfolios. Staff announced they will move the effective date up from October to Sept. 3. The measure was also endorsed at the MC via the consent agenda. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)
Problem statement and issue charge setting black start fuel requirements, which include pushing the anticipated start date for the stakeholder group back a month to December. Staff also added “critical non-fuel consumables” to the list of requirements to develop and minimum tank suction level to compensation-related issues to hash out. The measure was unanimously endorsed, but several stakeholders voiced concerns with adding another issue to the agenda when many have already expressed concerns about overscheduling. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: July 10, 2018.)
A D.C. Circuit Court of Appeals panel on Friday declined to review FERC’s approval of plans to expand capacity on the Algonquin Gas Transmission natural gas pipeline.
The court also dismissed a petition from a group of elected Boston officials for lack of standing.
Circuit Judge Sri Srinivasan filed the opinion (Case No. 16-1081) for the three-member panel July 27, denying petitions from the Town of Dedham, Mass., Riverkeeper, and a coalition of other environmental groups that said the commission should have evaluated three separate Algonquin expansion projects in a single environmental impact statement.
The court noted that FERC approved the Algonquin Incremental Market (AIM) project in March 2015, that Algonquin submitted the application for the Atlantic Bridge project in October 2015 and that the company has yet to file its application for the Access Northeast project.
| Algonquin Gas Transmission
“The projects thus were not under simultaneous consideration by the agency,” and thus not improperly segmented, the court said. It also found FERC reasonably concluded that the projects were not interdependent, as they each had separate timelines for approval and commencing service.
The petitioners also contended that the commission failed to consider sufficiently the cumulative environmental impacts of the three projects. But the court said FERC took into account the AIM project’s EIS when evaluating Atlantic Bridge’s, and that Access Northeast is too early in development.
“The adequacy of an environmental impact statement is judged by reference to the information available to the agency at the time of review, such that the agency is expected to consider only those future impacts that are reasonably foreseeable,” the court said.
Indian Point Proximity
The $972 million AIM project includes about 5 miles of new pipeline, the West Roxbury Lateral, which would run adjacent to a quarry outside Boston, and larger-diameter replacement pipeline next to the Indian Point nuclear plant on the Hudson River in New York.
The petitioners questioned FERC’s reliance on testimony from the Nuclear Regulatory Commission and Indian Point owner Entergy that AIM — which will lay pipeline 2,370 feet from the plant’s security barrier — posed no increased threat to the nuclear plant.
| Algonquin Gas Transmission
“We disagree,” the court said, ruling that FERC had “permissibly decided to credit the NRC’s expert conclusions, and to accept that NRC’s ‘extensive formal responses’ had adequately addressed the opposing experts’ concerns.”
The court also said it lacked jurisdiction to consider petitioners’ contention that the third-party contractor preparing the project’s EIS, Natural Resource Group, had a conflict of interest, as they had not raised the issue with FERC.
Not Really Boston
Although the commission did not initially contest the Boston delegation’s standing, Algonquin raised the issue as an intervenor in the case, which led the court to address the issue. The delegation consisted of nine elected representatives from Boston, including the mayor, a congressman and two state legislators.
The delegation’s claim of injury for standing purposes rested on the West Roxbury Lateral’s allegedly adverse safety, health and environmental effects on the city. The delegation staked its standing primarily on the mayor’s participation in the petition, claiming that effectively made the city a party.
“We are unpersuaded by the delegation’s theory,” the court said. “While the city of Boston could in theory bring an action, the mayor does not act as the city when he files a lawsuit in his own name.
“The city code specifies the process by which a lawsuit is initiated on behalf of the city of Boston. … That process did not take place here.”
ERCOT stakeholders and staff last week discussed several alternatives to market price investigation announcements, following a July 20 market notice that raised anxiety levels during the height of the recent Texas heatwave.
The grid operator sent the market notice following discovery of inaccurate definitions of two double-circuit contingencies in its market systems. According to the notice, staff had begun “an investigation of market prices.”
The market’s shadow price at the time was $20/MWh, when it should have been around $24/MWh.
Reliant Energy’s Bill Barnes | Admin Monitor
“It happened at a very heightened time in the market. There was high anxiety when this was noticed,” Reliant Energy’s Bill Barnes said during the July 26 Technical Advisory Committee meeting. “I appreciate the market notice … but we were surprised to see how small the change in price was. Why the fire drill?”
Staff explained there is no threshold for issuing a market notice on price investigations and that they were only following protocols.
“There’s a tradeoff of me sending something out as soon as we’re investigating,” said Kenan Ogelman, ERCOT’s vice president of commercial operations. “If I try to understand what’s going on, there could be some delay.”
Citigroup Energy’s Eric Goff suggested staff could have sent an initial notice that a contingency had been found but that it wasn’t related to the market’s operating reserve demand curve.
July’s ERCOT TAC meeting. | Admin Monitor
“[The notice] just said a price correction without the details,” Goff said. “That caused some uncertainty as we moved into high-priced periods.”
ERCOT sent the notice following the discovery of an error in the definition of two double-circuit contingencies east of Dallas. Only one of the contingencies was part of a binding transmission constraint that lasted only four hours.
The issue affected the July 18 real-time operating day and the July 20 day-ahead operating day.
| ERCOT
Corrected day-ahead prices were published on July 23. Staff will have to ask the Board of Directors for approval to resettle the real-time prices during its Aug. 7 meeting.
| ERCOT
Staff said ERCOT is making “procedural changes” to ensure the error doesn’t happen again.
“I think there is a better answer out there,” Ogelman said. “We appreciate the conversation. We want to eliminate [that problem].”
TAC Endorses Long-Delayed Governing Amendments
The TAC unanimously endorsed proposed amendments to ERCOT’s articles of incorporation and bylaws, ending a monthslong series of delayed votes and redline exchanges.
“We’ve ended up with a very, very good work product,” said ERCOT Assistant General Counsel Vickie Leady.
The amendments include identifying the Public Utility Regulatory Act as the source for the board’s mandatory composition, and using Public Utility Commission rules to govern the distribution of assets and winding up provisions in the event ERCOT is decertified as an independent organization.
The amendments will be presented to the Human Resources and Governance Committee on Aug. 6, and then to the board Aug. 7. Staff plans to use an email vote to seek approval from its nearly 300 corporate members, and then file the amendments for the PUC’s approval in mid-September.
The ISO hopes to have the amendments in place by January.
Staff have created a website to store the different versions of the proposed changes. The amendments are the first updates since 2000.
New Leadership Confirmed to ROS
The committee confirmed new leadership for its Reliability and Operations Subcommittee.
Golden Spread Electric Cooperative’s Tom Burke will become chairman, replacing Oncor’s Alan Bern after he stepped down from the role in June. Tenaska’s Boon Staples will replace Burke as vice chair.
Committee Endorses 17 Revision Requests, Changes
The committee unanimously approved new language in a remanded Nodal Protocol revision request (NPRR) incorporating an intraday or same-day weighted average fuel price into the mitigated offer cap.
The TAC unanimously cleared NPRR847 in May, but the Board of Directors sent it back in June over concerns that the calculation of blended fuels was “vague and confusing.” (See “Board Approves 8 Change Requests,” ERCOT Board of Directors Briefs: June 12, 2018.)
Staff told stakeholders the original language did not define the calculation correctly, using the total fuel volume twice.
The NPRR is meant to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.
The committee also unanimously approved 16 other changes, clearing a backlog produced by the cancellation of its June meeting: seven NPRRs, a revision to the Nodal Operating Guide (NOGRR), two changes to the Planning Guide (PGRRs), three revisions to the Retail Market Guide (RMGRRs), an update to the Resource Registration Glossary (RRGRR), a system change request (SCR) and a change to the Verifiable Cost Manual (VCMRR).
NPRR856: Clarifies that for day-ahead make-whole settlement purposes, the “offline but available for SCED deployment” status is considered an online status and will be considered an offline status after system implementation.
NPRR862: Incorporates a number of revisions addressing recent changes made by the PUC’s rulemaking related to reliability-must-run service (Project No. 46369).
NPRR866: Addresses two objectives related to mapping registered distributed generation and load resources to transmission loads in the network operations model by codifying the existing process for mapping a load resource or an aggregate load resource to its appropriate load point in the model; and by outlining how to map a registered DG facility to its appropriate load point in the model.
NPRR873: Outlines expectations for posting information pertaining to intra-hour wind power and load forecasts on the Market Information Systems public area. The NPRR also proposes two new definitions and acronyms for the intra-hour wind power and intra-hour load forecasts (IHWPF and IHLF, respectively).
NPRR874: Changes the net allocation to load settlement stability report by breaking out the load-allocated congestion revenue rights monthly revenue zonal amount from the other load-allocated charges, and by providing dollars per megawatt-hour by congestion management zone.
NPRR875: Adds clarifying language to sync the protocols with NPRR864, which modifies the reliability unit commitment engine to scale down commitment costs of fast-start resources with less than one-hour starts.
NPRR877: Allows for the use of actual metered interval data for initial settlement of an operating day for electric service identifiers that currently require BUSIDRRQ load profiles.
PGRR061: Includes locations for registered DG facilities in the annual load data request process.
PGRR062: Proposes new processes, communication and document sharing and storage requirements to be included in the new generation interconnection or change request application.
RMGRR152: Changes the cancellation method from the MarkeTrak cancel-with-approval process to the 814_08 cancel-request Electronic Data Interchange transaction.
RMGRR153: Removes references to Sharyland Utilities, which no longer operates as a distribution service provider in the retail market, and updates American Electric Power contact information.
RMGRR154: Removes references to the Lite Up Texas discount, which ended in August 2016.
RRGRR017: Supports NPRR866 by providing a process for mapping registered DG facilities to their appropriate load points in the network operations model.
SCR796: Modifies the Market Management System’s validation rules for bids and offers to exclude resource nodes within a private-use network site as valid settlement points for day-ahead market energy-only offers and bids, and for point-to-point obligation bids.
VCMRR022: Directs ERCOT to contract a coal index price with a fuel vendor and includes a methodology for calculating the quarterly fuel adder for coal-fired and lignite-fired resources based on that index.
