Page 1044 – RTO Insider

September 16, 2020

NEPOOL Transmission Comm. Briefs: Sept. 15, 2020

The Northern Maine Independent System Administrator (NMISA) is asking New England transmission owners to eliminate through-and-out (TOUT) transmission charges for transactions between it and ISO-NE, similar to the reciprocal discount currently used by the RTO and NYISO.

NMISA CEO Ken Belcher and consultant Steve Garwood of PowerGrid Strategies outlined the proposal to the New England Power Pool Transmission Committee on Tuesday, saying it would eliminate pancaked transmission charges between the two regions, “consistent with FERC’s longstanding policy of eliminating seams issues where possible.”

NMISA, which serves a peak load of about 138 MW in Aroostook, Washington and Penobscot counties, is not directly interconnected with the rest of New England. Its two regions — Versant Power’s Maine Public District (MPD) in the north and the Eastern Maine Electric Cooperative in the south — connect to ISO-NE through the transmission facilities of New Brunswick’s NB Power. (Versant Power was formerly known as Emera Maine.)

Officials said the change would result in a “de minimis” impact on transmission rates for both regions while improving market efficiency and liquidity and increasing generation competition by reducing the costs for Northern Maine to access ISO-NE generation and for the RTO to use the region’s wind resources.

Had the proposal been in effect during 2019, it would have increased the June 1, 2020, regional network service rate by 4 cents/kW-year (0.03%), NMISA said, while MPD would see a 1.3% increase.

Northern Maine currently purchases about 70,000 MWh annually from ISO-NE, producing $67,000 in transmission revenue not subject to the discount. By reducing the seams costs, that could rise to 659,000 MWh, producing non-discounted charges of $633,000, NMISA said.

Increasing south-to-north transactions also would reduce congestion at the Orrington-South interface, potentially reducing curtailments of Northern Maine’s wind power exports to the RTO, the ISA said.

Northern Maine’s renewable exports are currently worth $2.5 million in renewable energy credits. That could increase by $750,000 through scheduling optimization, NMISA said. “Also, there is potential for further development of renewables up to 100 MW in Northern Maine for delivery to New England based on unused existing transmission capacity. Exporting the energy from these new resources to ISO-NE is unlikely to occur absent implementation of the proposed discount,” it said.

In its first presentation on the proposal at the joint Transmission/Reliability committees meeting in August, NMISA said MPD would have lost $164,546 in TOUT revenue had the charge been eliminated in 2019. In response to a question, it acknowledged that the revenue would have been $874,546 had MPD not already been discounting its export point-to-point rate. “However, absent continuation of the discount, it is unlikely that the same level of transactions would occur as occurred during 2019,” NMISA said.

Garwood said Northern Maine will ask ISO-NE’s Participating Transmission Owners Administrative Committee (PTO AC) at its Sept. 22 meeting to issue a notice of intent to eliminate the TOUT.

ISO-NE Proposes Tariff Revision on Transmission Charge Exemption for Storage

ISO-NE shared proposed Tariff revisions it intends to include in its third compliance filing on FERC Order 841 after the commission last month said the RTO had failed to demonstrate that a storage resource that is self-scheduled to charge at a fixed megawatt quantity is providing a service that warrants exempting it from transmission charges. (See FERC OKs Most of ISO-NE 2nd Storage Compliance.)

Jennifer Wolfson, an attorney for ISO-NE, presented the revisions on behalf of the RTO and PTO AC. Addressing FERC’s concern with self-schedules, she said that “a charging self-scheduled” storage dispatchable asset-related demand (DARD) provides similar services as “a charging pool-scheduled” storage DARD.

ISO-NE and the PTO-AC contend that all charging megawatts of a self-scheduled storage DARD supply voltage support and reactive control. “A self-scheduled resource is required to follow ISO dispatch instructions, without delay, to consume at the requested megawatt level; therefore, when it charges it provides real-time balancing of supply and demand and operating reserve,” they say. “A charging self-scheduled storage DARD, in contrast to other load, helps address reliability concerns given that the ISO can dispatch the load off if needed to address a contingency.”

The Tariff revisions state that storage will be exempt from transmission charges only if its charging load does not include station service load or any other load and “is providing one or more of the following services: reactive power voltage support, operating reserves, regulation and frequency response, balancing energy supply and demand, or addressing a reliability concern.”

The Transmission Committee will vote on the proposed Tariff revisions on Oct. 27, with a Participants Committee vote expected Dec. 3.

Last week, RTO officials outlined their plans for responding to two other directives from FERC’s Aug. 4 order. (See “Order 841 Compliance Update,” NEPOOL Markets Committee Briefs: Sept. 8, 2020.)

The compliance filing is due Dec. 7.

September 16, 2020February 19, 2025

FERC Nominees Bob and Weave Through Senate Hearing

President Trump’s nominees to FERC, Allison Clements and Mark Christie, said just enough to satisfy senators on both sides of the aisle during their confirmation hearing Wednesday.

Neither nominee gave away how they might decide on the commission’s thorniest issues, including carbon pricing, capacity markets and downstream greenhouse gas emissions from natural gas pipelines. Instead, they both said they did not want to “prejudge” any matters before they are sworn in and repeatedly committed to considering each matter that came before them on a case-by-case basis.

Both Republican and Democratic members of the Senate and Energy Natural Resources Committee were pressed for time because of votes on the Senate floor and did not press the nominees further for more clues. They gave no indication that they would oppose either nominee.

Clements, a Democrat and energy policy adviser for the Energy Foundation, and Christie, a Republican and chair of the Virginia State Corporation Commission, were nominated by Trump in late July. (See McNamee Leaves FERC.)

“Both nominees made multiple references to the need for objectivity, the importance of reliability and resiliency, and the central duty of the commission to ensure just and reasonable rates for consumers,” ClearView Energy Partners said. “We thought both nominees were circumspect in their responses … and steered clear of any remarks that might be construed as potentially prejudging an issue pending before the commission.”

President Trump’s nominees to FERC, Virginia SCC Chair Mark Christie and Energy Foundation consultant Allison Clements, are sworn in before their confirmation hearing Sept. 16. | Senate ENR Committee

Several Republicans, most notably Sen. Cory Gardner (Colo.), did focus on Clements and her previous work for the Natural Resources Defense Council’s Sustainable FERC Project. When Gardner asked her to “name an issue” on which she disagreed with her former colleagues, Clements without hesitation answered nuclear generation, which she said “plays an important role in providing carbon-free, reliable power to the system. That’s a place where many of my very well studied and smart colleagues might disagree with me.”

“Could you name another one, perhaps?” Gardner replied. He tried to get Clements to say whether she disagreed with the NRDC on its “fossil fuel agenda,” but she wouldn’t bite.

Democrats, meanwhile, tried to determine where Christie would side on the GHG dispute, which has caused tension at FERC. Democratic Commissioner Richard Glick has repeatedly dissented from the commission’s approvals of natural gas infrastructure, contending that they ignore a D.C. Circuit Court of Appeals ruling that said it must consider the effects of downstream GHG emissions in its environmental impact statements.

Senate ENR Chair Lisa Murkowski (R-Alaska) | Senate ENR Committee

Christie, however, demurred, telling Sen. Martin Heinrich (N.M.) that he did not “want to prejudge that issue because that is a legal question about what does the law require and what does the D.C. Circuit opinion require.” He often sounded like McNamee, a fellow Virginian, repeatedly stressing the importance of “the law and the facts,” a phrase that the former commissioner often used in his public appearances.

One of the few mentions of the RTOs came when Christie answered to a question about market manipulation from Sen. Maria Cantwell (D-Wash.). Christie acknowledged that Washington has been considering whether to allow its utilities to join an RTO with CAISO and advised that, having “lived in PJM world for the past 16 years, it is absolutely essential that you have an Independent Market Monitor in these RTO capacity markets. … We have an outstanding market monitor in PJM, Dr. [Joe] Bowring.”

Christie was president of the Organization of PJM States Inc. in 2007 when it pressed FERC to separate PJM’s Market Monitoring Unit into an IMM. In March 2008, FERC approved the current monitoring structure, with Bowring as head of his own independent firm.

Committee Chair Lisa Murkowski (R-Alaska) said she hopes to have both nominees confirmed before Congress adjourns at the end of the year. ClearView expects that to happen, albeit most likely after Election Day. “We did not observe any statements by either nominee that would appear to imperil their eventual confirmation,” ClearView said. “That said, we cannot foretell how a potentially contested presidential race could impact the day-to-day functioning of the U.S. Senate in a lame duck session.”

If confirmed, Clements’ term would end in June 2024 and Christie’s in June 2025.

September 16, 2020

MISO, SPP Respond to Monitors’ Seams Studies

MISO, SPP Regulators Mull Seams Recommendations.)

After hearing from MISO’s Jeremiah Doner and SPP’s Casey Cathey, the Seams Liaison Committee (SLC), comprising regulators from the Organization of MISO States and SPP’s Regional State Committee, offered up suggestions on potential SLC actions.

“We need to get serious about starting to prioritize these [recommendations],” said North Dakota Public Service Commissioner Julie Fedorchak, one of the more vocal regulators during the SLC’s web meeting Monday.

Ted Thomas, chair of both the Arkansas Public Service Commission and the SLC, proposed the committee break the recommendations and staff and stakeholder feedback into four buckets: actionable items, further analysis, planning topics and affected-system studies.

MISO SPP seams — SPP’s Casey Cathey (left) and MISO’s Jeremiah Doner participate in a 2018 panel discussion. | © *RTO Insider*

Topping the list of actionable items is market-to-market (M2M) coordination, in which the RTOs’ manage congestion by using least-cost generation redispatch. The grid operators have been engaged in the M2M process since 2015, with SPP piling up more than $93 million in settlement payments for congestion on its system caused by MISO.

MISO’s Independent Market Monitor, Potomac Economics, said the RTOs could reap up to $30 million in annual benefits by improving congestion management, noting that many changes would be incremental and only require coordination between the grid operators.

Cathey, SPP’s director of system planning, said the RTOs have been working to improve the process and asked for more time to let the changes take hold.

“If we see still lost opportunities … or reliability concerns after those enhancements are in place, we will have to prioritize some of those [IMM] suggestions,” Cathey said. “We absolutely would like to fix some of the issues we see in market-to-market.”

Potomac’s analysis of interface pricing generated more discussion than any other item. The Monitor viewed the RTOs’ current interface pricing mechanism favorably but noted a flaw in how congestion is charged. FERC Orders Tech Conference on MISO-SPP Congestion.)

Doner, MISO’s director of seams coordination, said the grid operators agree improvements can be made to the pricing mechanism’s design and methodology. He said resolving the issue would require changes to MISO’s market systems, which won’t be fully implemented until 2022. SPP plans to address the issue with a couple of projects that won’t begin until that same year.

“There’s a value to evaluating the interface pricing,” Doner said. “At this point, it’s too early to say what that should be.”

“This is a very complex issue. Whatever we do will take a lot of thinking and additional analysis,” Cathey said. With more than 250 tie lines along the MISO-SPP seam, he asked, “How can you properly send the right signal for imports or exports?”

Potomac President David Patton called in to dispute what he was hearing.

“The overall time frame, the complexity … this has been studied for almost 10 years, including a study on unintended consequences,” he said. “This can be done in a simplified form in a much quicker time frame. The flawed interfacing pricing that exists is generating costs. To say we’re going to leave it for three, four or five years … is not an appropriate action.”

Cathey said it’s a misconception that there’s “a lot of money on the table” and “efficiencies to be gained” by fixing the interfacing pricing. He said ramp limits and make-whole payments for exports are among the issue’s barriers. Both he and Doner said they would be happy to work on interface pricing with the monitors.

“Both RTOs are paying for congestion relief on their neighbor’s system. We’re paying transactors to relieve constraints that neither one has a way to recover, and it ends up being uplifted to the customers,” Patton said. “When people transact at inefficient levels, the overall market results are inefficient and that can hurt generators and load. We should be motivated enough to fix it.”

Doner said MISO stakeholders consider coordinated transaction scheduling (CTS), the third item on the actionable list, to be a low-priority item and have placed its implementation in the Integrated Roadmap process’s parking lot. MISO and PJM have been using CTS on their seam since 2017, he said.

“We’re seeing that the volume of transactions that leverage that product is very small,” Doner said. “What we hear from stakeholders and [transmission] customers is that’s because of transmission service charges and the uncertainty [around] that pricing. Transmission service charges on the PJM seam are even smaller than they are on the SPP seam.”

The RTOs said CTS implementation costs could be as high as $10 million, effectively negating the SPP Market Monitoring Unit’s projection of $9.4 million to $11.2 million in benefits.

The SLC’s leadership has suggested that rate pancaking, unreserved use charges and joint dispatch need further analysis. The monitors’ study on rate pancaking and unreserved use focused on real-time transactions, for which both RTOs already offer heavily discounted transmission service. The analysis did not evaluate the effect on long-term transmission service or day-ahead transactions.

“It would be worthwhile to get [the monitors’] response to those things at some point,” Fedorchak said.

The IMM’s study of joint dispatch found few benefits, noting that dispatching two systems that are already optimized separately yields little incremental production cost benefits. The SLC pointed out that the monitors did not analyze other benefits, such as reliability, reduced unit cycling or reduced reserve margins.

The SLC hopes to present a list of recommendations by the end of 2020 on how the RTOs can improve coordination across the seam.

September 15, 2020

MISO, SPP to Conduct Targeted Transmission Study

MISO and SPP on Monday announced a yearlong transmission study to identify projects with “comprehensive, cost-effective and efficient upgrades” after their staffs once again failed to agree on an interregional project this year.

The RTOs said the joint study will focus on solutions they believe will “offer benefits to both [the] interconnection customers and end-use consumers” of their members. The study’s expanded scope will include projects near the RTOs’ seam that support both organizations’ interconnection processes.

MISO SPP transmission — SPP CEO Barbara Sugg | © *RTO Insider*

Cost allocation will be addressed “once there’s a better sense of the types of projects and benefits that might result,” an SPP spokesman said. Previous MISO-SPP studies that have evaluated interregional projects’ cost allocation have failed to produce any new transmission.

“A fundamental issue facing grid transformation is the lack of transmission at requested connection points,” SPP CEO Barbara Sugg said in a statement. “Working together, MISO and SPP can target those areas where there are mutual benefits on both sides of our [seam].”

In doing so, the RTOs tacitly acknowledged stakeholder frustration over their inability to identify joint projects under their Joint Operating Agreement. MISO in August all but admitted the grid operators will once again come up empty after a fourth joint study in six years. (See MISO, SPP Close to Ruling out Joint Projects Again.)

“[Stakeholders] have told us that we need a better solution that prioritizes projects that address these gaps,” MISO CEO John Bear said in a statement. “Collaborating in this way gives us the opportunity to explore potential improvements within our own interconnection processes while informing longer-term regional transmission planning efforts in both MISO and SPP.”

Clean Energy Groups Cheer

The American Wind Energy Association, Clean Grid Alliance and Advanced Power Alliance applauded the RTOs for what they labeled “a game changer.” The organizations released a joint statement that said the study will be a “new milestone” in coordination between the RTOs, their leadership, state regulators and other stakeholders.

“Working together, the two [RTOs] can enable and expedite needed transmission development on their seam and address related generation interconnection challenges,” the organizations said. “This forward-thinking partnership includes an aggressive, but achievable, timetable, and we pledge to provide any assistance necessary to support this effort. Coordinated transmission planning will allow consumers across the country to harness the economic and environmental benefits of renewable energy.”

The RTOs expect the joint study to begin in December and will include opportunities to share information with stakeholders and solicit their input. The grid operators’ respective boards will have to approve any identified projects before they can move forward, as the study will be done outside their tariffs.

Aubrey Johnson, MISO’s executive director of system planning and competitive transmission, told a meeting of the RTOs’ state regulators that some of the study’s details are still being worked out but that its initial focus will be identifying issues that have benefits and should be pursued.

“The effort is an attempt to perform an alternative approach to address the historical challenges in targeted areas of the seam,” Johnson told a meeting of the Organization of MISO States and SPP Regional State Committee’ Seams Liaison Committee. “It’s a little bit different from some of the things we’ve done under the JOA. We’re trying to do this outside all the other work we’ve done.”

SPP Vice President of Engineering Antoine Lucas told the committee that the study “creates some flexibility to see if there are some potential solutions … to get over the hurdles and challenges we’ve had in the JOA studies.”

September 15, 2020

FERC Refuses Complaint over Wabash’s DG Rules

FERC has sided with the Wabash Valley Power Association in a skirmish with a cooperative member over its distributed generation rules.

Tipmont Rural Electric Membership Cooperative must continue to abide by Wabash’s Distributed Generation Policy, FERC ordered Friday. The commission said Wabash’s policy is effective as of June 29 (ER20-1683-001).

The rural co-op in eastern Indiana has taken issue with Wabash’s DG supply contract since 2018, when it requested early termination of its obligations under it. Tipmont earlier this year said that Wabash’s freshly filed Distributed Generation Policy under a new tariff section was anticompetitive because it establishes Wabash as the “exclusive buyer of power from its potential distributed competitors” and limits Tipmont’s energy purchases to distributed resources of 10 kW or less, or up to 25 kW with Wabash’s approval. Tipmont is under an all-requirements wholesale power supply contract with Wabash with the exception of the small, distributed energy allotments through 2050.

FERC batted away the distribution co-op’s complaints over the contract.

“We are not persuaded by Tipmont’s interpretation of its contracts and related arguments about the anticompetitive effects of the Distributed Generation Policy. Tipmont contracted to purchase from Wabash all required electric power to operate Tipmont’s system. As Tipmont executed all-requirements contracts with Wabash, there are no provisions allowing Tipmont to transact with distributed resources,” FERC said.

However, FERC acknowledged that Tipmont is the only one of Wabash’s two dozen members that has neither adopted a resolution agreeing to abide by the DG policy nor authorized Wabash to file an implementation plan under the Public Utility Regulatory Policies Act on its behalf. Because of that, FERC directed Wabash to add language to its contract specifying that the policy only applies to non-qualifying-facility DG. The commission said the upcoming compliance filing should apply to Tipmont and “any other member who has chosen to retain its PURPA purchase obligations.”

Otherwise, FERC disagreed with Tipmont’s claim that Wabash’s distribution supply contracts only stipulate that Wabash supplies Tipmont’s “electrical needs as measured at the wholesale delivery point.” The commission said it found nothing in the contracts to support the co-op’s argument.

“We note that under this interpretation, if Tipmont were able to purchase its total energy requirements from generation located on Tipmont’s distribution system, Tipmont would no longer have any obligation to purchase energy from Wabash. This would undermine the purpose of a long-term, all-requirements contract, in which Tipmont elected to purchase all needed energy from Wabash, and Wabash agreed to fulfill Tipmont’s energy needs by making long-term arrangements,” FERC said.

September 15, 2020January 17, 2024

ISO-NE Challenged on Wind, Solar, Storage Revenues

New England Power Pool stakeholders proposed changes to Forward Capacity Market (FCM) parameters and rules regarding the timing of delist bids during a marathon Markets Committee meeting Sept. 8-10.

Several of the proposed changes concerned ISO-NE consultants’ estimates of the revenue potential of wind, solar and storage resources. Others concerned the inputs for the calculation of the net cost of new entry (CONE).

The committee will vote on the parameters and proposed amendments next month, but the votes are advisory under sections 8 and 11 of the NEPOOL Participants Agreement.

Abigail Krich and Alex Worsley of Boreas Renewables presented RENEW Northeast’s critiques of the revenue figures proposed by Concentric Energy Advisors (CEA) and Mott MacDonald, two consulting firms hired by ISO-NE to update the FCM parameters for the 2025/26 capacity commitment period.

The key parameters — net cost of new entry (CONE) and offer review trigger prices (ORTPs) — can determine whether certain resources are competitive in the auction. Net CONE estimates the capacity revenue a new generator needs in in its first year of operation to make it economically viable; it is based on a “reference unit” — the most profitable commercially available generation technology for new entry in New England — currently General Electric’s 7HA.02 gas-fired combustion turbine.

ORTPs are estimates of the low end of competitive offers for other classes of technology. New supply offers above the ORTP are presumed to be competitive and not an attempt to suppress the auction clearing price. An offer below the price is subject to a unit-specific review by the Internal Market Monitor to verify the resource’s cost.

Offshore Wind

Krich told the committee Wednesday that the consultants’ estimates of offshore wind costs are “totally outside and above the range of other estimates.”

The RTO proposed using $5,876/kW (2019$) for the overnight capital cost for offshore wind, resulting in an ORTP of $32.31 to 32.51/kW-month, almost double the highest clearing prices on record and well above $2 to $7.03/kW-month range for the five auctions since 2016.

Krich said the assumption “is significantly higher than commercial expectations,” based on RENEW’s analysis of executed OSW contracts in New England and other publicly available data.

The RTO “used a bottom-up methodology for determining the capital cost assumption but has not presented cost-based benchmarking that supports any element of that analysis or the final capital cost assumption,” she said.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

One reason the RTO’s estimates are too high is because its $70 million interconnection cost “does not align with cost estimates in completed ISO-NE interconnection studies for projects almost identical to the proposed project,” Krich said.

She noted that the average interconnection cost for the 13 OSW projects studied by ISO-NE is $35.5 million, with only three of the projects having costs of $70 million or more, she said.

“Choosing the highest costs for projects studied by ISO-NE is not representative of what developers will typically face and should not be used in the determination of an ORTP,” she said.

Krich also challenged the RTO’s $4.2 billion engineering, procurement and construction cost estimate for an 800-MW OSW project, saying it should be closer to $2.1 billion.

RENEW will ask stakeholders to reduce OSW’s capital cost assumption to $2,900/kW (2019$). At that cost, Krich said, OSW shows an almost $4/kW-month surplus based on its energy revenues and renewable energy credits, meaning it doesn’t need capacity revenue to cover its costs and should have an effective ORTP of $0.

“Prices have been dropping really precipitously” in the last few years, she said. “We honestly don’t understand where the higher numbers from ISO New England come from.”

Deborah Cooke, ISO-NE’s principal analyst for market development, who presented the RTO’s proposed on net CONE and ORTP calculations, declined to comment on the discrepancies between RENEW’s and the consultants’ estimates.

Operating Lifetime

Krich also challenged the RTO’s proposed 20-year asset life for all generation technologies in its ORTP model, saying lifetime expectations for wind and solar have increased beyond 20 years since the last ORTP recalculation.

“This leads to higher ORTP values, unnecessary review and potential mitigation simply because [the RTO] is not recognizing the full life expectancy of these technologies,” she said. “If certain technologies’ expected revenues beyond 20 years are being neglected in the [minimum offer price rule] implementation, the capacity auction could clear at prices higher than equilibrium.”

Battery EAS Revenues

Krich and Worsley said CEA was overly conservative in estimating batteries’ energy and ancillary service (EAS) revenues.

ISO-NE proposed using $1.87 to 2.67/kW-month (2019$) in energy and reserves revenue, which RENEW contends “underrepresents what a competent battery developer could earn in the New England markets” and fails to follow the guidelines the External Market Monitor recommended in December 2019.

RENEW proposed an ORTP value of $4.53 to 4.86/kW-month, compared to the RTO’s $4.92 to 5.78/kW-month.

Worsley said the RTO’s estimate shows no effort to optimize dispatch using available data at the time of dispatch, such as day-ahead market prices, and that its assumed charging timing is often suboptimal. It assumes no ability to respond to forecasted market conditions or to change strategies through the year, making it unable to capture daily, monthly or seasonal market changes, he said.

Using the EMM “continuous information” approach, Worsley said, the batteries would have 52% higher energy and reserve revenues than assumed by CEA. RENEW recommended the RTO adopt a more conservative calculation by the Massachusetts Attorney General’s Office, which would result in a 41% increase.

“A competent [energy storage resource] owner should be assumed to use publicly available information known prior to dispatch,” he said. “These are common and not difficult to implement, and we believe [they] should have been appropriately within CEA’s scope of work.”

Ben Griffiths, an energy analyst for the attorney general, said the deterministic spreadsheet model CEA used resulted in “materially lower” EAS revenues than the basic linear optimization model he used. “It’s the wrong modeling tool for batteries,” he said of CEA’s choice.

The CEA model assumed the battery charges only during fixed windows, rather than when prices are expected to be lowest, Griffiths said. It also assumes it discharges when prices reach a fixed threshold — not adjusted for time-of-day or season — that often misses higher values later in the day. It also limited cycling to once-per-day, even if when it would be advantageous to cycle more than once, he added.

“EAS revenue estimates for ORTPs should not be based on the rosiest of predictions, but neither should they [be] based on the assumption of bumbling incompetence,” Griffiths wrote in a memo summarizing his research.

Inputs for Reference Unit Net CONE Calculation

Bruce Anderson of the New England Power Generators Association (NEPGA) identified several changes the group wants ISO-NE to make to input variables for the reference unit net CONE calculation.

Anderson called for using a historical premium on intraday gas costs during those hours when the reference peaker unit is dispatched in real time, as well as including the costs of firm gas delivery and sellback costs and imbalance charges for gas nominated but not consumed.

He also challenged the RTO’s proposal to use the lower heating value (LHV) for the nominal heat rate, saying it should use the higher heating value (HHV), on which gas prices are based. (HHV is the total heat obtained from combustion of a specified amount of fuel at 60 degrees Fahrenheit. The LHV is the HHV minus the latent heat of the water vapor formed by the combustion of the hydrogen in the fuel. HHV is typically about 11% higher than the LHV.)

NEPGA said the RTO’s proposal that the reference unit be located in New London County, Conn. — within 2 miles of both the Algonquin interstate gas pipeline and a 345-kW transmission line — is unrealistic because there are no greenfield sites permitted for industrial use that meet the criteria. It said it should extend the lateral and radial lengths to 5 miles to reflect the difficulty in finding suitable parcels.

Anderson also said the RTO improperly assumed there would be no compression or lateral upgrade costs to ensure gas delivery.

NEPGA also disputed the monetization of bonus depreciation, saying the proposed net CONE value is insufficient incentive for a sale lease back financing agreement or other tax equity financing. It also asked for a lower debt/equity ratio than the 55/45 proposed by ISO-NE to reflect merchant market risk and the inclusion of “reasonable estimates of owner’s cost and contingency,” which were omitted by the RTO.

LS Power’s Mark Spencer complained that Mott MacDonald had failed to provide information he said he had been requesting for three months regarding several of the company’s inputs and assumptions.

“We’re looking to have a vote next month, and the questions are still unanswered, so I don’t know what else to do other than to register an objection that it doesn’t seem like the information is forthcoming,” Spencer said.

Calpine’s Brett Kruse predicted the disputes over the assumptions will result in litigation before FERC and potentially federal court.

“They’re going to have to stand on their data as opposed to hiding behind the cloak of secrecy here. … My hope is that the ISO and Concentric are really riding herd on Mott MacDonald. Quite frankly, I have not been impressed with what I’ve seen from them.”

CEA’s Danielle Powers, who led its presentation s on CONE and ORTP calculations, declined a request to respond to the criticism.Mott McDonald referred a request for comment to ISO-NE.

Change to Delist Bid Threshold

Sigma Consultants President Bill Fowler presented a proposal on behalf of Calpine and Vistra Energy, and Vistra’s Dynegy unit, to address the disadvantage he said is faced by resource owners having to lock in static delist bids four months before the Forward Capacity Auction.

The IMM is proposing that the dynamic delist bid threshold (DDBT) be set equal to its expectation of the next auction clearing price. All delist requests above this level must become static bids.

Fowler said locking in prices for statics is much riskier and more expensive than a dynamic bid, creating a disincentive to offer at prices only slightly above the DDBT. “Failing to recognize this will bias offers and may lead to clearing prices below competitive levels,” he said.

The lock-in means resource owners cannot account for market and regulatory changes that occur between October and February, including the installed capacity and local sourcing requirements, waiver requests, and state and federal regulatory actions, including FERC action on FCM questions, Fowler said.

Resources making static delist offers will add a risk premium to account for these costs and risks, Fowler said. If the resource’s competitive price is greater than the DDBT but less than the DDBT plus the margin, he said, resource owners are incented to not bid the competitive price, and instead bid the DDBT minus 1 cent.

“The resource owner has to hope that his offer to exit at DDBT minus 1 cent clears. If it doesn’t, the resource is stuck with a CSO [capacity supply obligation] at a price it didn’t want.”

It also means the Monitor and market will never see the true competitive offer; the resource may take on a CSO it doesn’t want; and the FCM may clear at an uncompetitive level, he added.

Fowler noted the RTO’s analysis of the new DDBT method found it misses the actual clearing price by 25%. At a $2 clearing price, a 25% margin equals 50 cents; at a $4 clearing price, it is $1.

As a result, Fowler said the DDBT should be set at a “reasonable margin” — 50 cents to $1/kW-month — above the expected clearing price. “A margin of this size would help address this inaccuracy,” he said.

September 15, 2020

MISO Market Subcommittee Briefs: Sept. 10, 2020

Stakeholders would prefer MISO use RTO-specific data as much as possible as it considers whether and how to update its value of lost load (VoLL), Michael Robinson, principal adviser of market design, told the Market Subcommittee on Thursday via teleconference.

MISO’s VoLL is currently a flat $3,500/MWh and is used to set the upper value of the operating reserve demand curve and LMP cap. It essentially determines at what price customers would prefer interruption to paying the marginal cost of service. The RTO has been considering how it can vary the value to account for differences in season, time of day, region and load type, among other factors. (See MISO Revisits Scarcity Pricing Rethink.) Robinson opened the discussion with a lengthy analogy about trying to find the right type of ax for felling a tree, but only having other types of axes.

The RTO proposed several options for refining the VoLL. Robinson said stakeholders showed little to no interest in using previous studies that did not use Midwest-specific data, including one done by London Economics on ERCOT’s VoLL.

Rather, they prefer that any analysis use the most recent data available out of MISO, including the possibility of doing a completely new study. This approach, however, would likely take up to a year and a half, Robinson said, and be “extremely expensive to conduct.”

Customized Energy Solutions Ted Kuhn asked whether the effort would be “a waste of time.”

Independent Market Monitor David Patton chimed in, saying updating the VoLL is “as far from a waste of time as any [effort] I can think of.” He said MISO needs to ensure the value of reliability is embedded in its prices and that scarcity prices “are not close to being right.”

“This is critically important work,” Patton said.

MISO will continue to narrow down its potential approaches based on stakeholder feedback, which is due Sept. 30, and further discuss the issue at the subcommittee’s meeting next month.

Fall Seasonal Outlook

MISO expects adequate resources for the upcoming fall season, though planned generator outages are expected to rise this year because of delays related to the COVID-19 pandemic.

The National Oceanic and Atmospheric Administration is predicting higher-than-usual temperatures for MISO South and parts of the RTO’s eastern footprint this fall, Eric Rodriguez, resource adequacy coordinator, told the subcommittee. The RTO’s preliminary expected peak load for the season is 113 GW, compared to an expected 152 GW of available capacity.

Planned outages are expected to peak in mid-October, as they usually do, but MISO expects them to be slightly higher this year, as generators rescheduled their spring maintenance during the height of the pandemic, Rodriguez said. Still, the highest risk for a maximum generation event is in September, when a worst-case scenario of higher-than-expected forced outages and demand could lead the RTO to narrowly exceed its 14.6 GW of available load-modifying resources and operating reserves.

September 15, 2020

Texas PUC Rejects Call to Reprice Error

The Texas Public Utility Commission last week dismissed a complaint asking that ERCOT be required to reprice a 2019 dispatch interval after a pricing error sent wholesale prices to their $9,000/MWh cap (49673).

Houston-based energy trader Aspire Commodities last year asked the commission to make generators repay the ERCOT market an estimated $18 million for what it called a “fictitious spike price” in May 2019. Calpine later admitted it had mistakenly notified ERCOT that it had taken about 4 GW of generation capacity offline when, in actuality, it was still operating. (See ERCOT Asks PUC to Dismiss Trader’s Complaint.)

In agreeing with an administrative law judge’s proposal for decision, the commission said ERCOT’s protocols don’t mandate a price correction when an interval’s pricing is affected by a market participant’s “erroneous telemetry.” At the same time, they suggested the grid operator work on a change request to make sure it better defines the process in the future.

PUCT reprice error — Commissioner Arthur D’Andrea listens to the discussion. | *PUCT*

“We shouldn’t wait for there to be a really huge event to be having this discussion and this fight,” PUC Chair DeAnn Walker said during the commission’s open meeting Thursday. “ERCOT does have to rely on the input given by the market participants. There’s no way to do it other than that, so when the market participant provides something that is wrong, ERCOT’s left in a position not knowing what to input to get whatever is right.”

“In this case, ERCOT applied the protocols correctly,” said Commissioner Shelly Botkin, who joined the commission after serving as the grid operator’s director of corporate communications and government relations. “I would like a conversation with ERCOT to see if there’s a different way to do these things.”

ERCOT staff last year said they would seek to strengthen telemetry data and work with stakeholders to evaluate alternatives.

In other action, the PUC approved adjusted energy efficiency cost recovery factors (EECRF) for Oncor (50886) and Texas-New Mexico Power (50894). The commission set Oncor’s 2021 EECRF at $64.8 million and TNMP’s at $5.9 million. Both companies reached unanimous settlements with all parties involved.

September 15, 2020

NYISO ICAP/MIWG Briefs Sept. 14, 2020

NYISO analysis of reserve pickup (RPU) performance for winter 2019/20 shows that 76% of the time, resources provided more than 90% of total energy expected.

Control Room Operations Manager Jon Sawyer tol d the Installed Capacity/Market Issues Working Group on Monday that from November 2019 to April 2020, 16 RPUs occurred, and there were 93 unique instances in which a resource was asked to convert reserves to energy.

For gas turbines, total energy provided was measured at the 11th minute after the start of the RPU. For all other resources, total energy provided was measured one minute after the end time of the RPU.

This graph shows that 76% of the time, resources provided more than 90% of total energy expected. | *NYISO*

One stakeholder asked how aggregated data used in the analysis can account for single generating units that fail to perform adequately, and whether the ISO can provide such breakout data for the upcoming RPU report for summer 2020.

Sawyer said the ISO cannot divulge unit-specific data, but that it has a process for generators that do not pass a performance audit and is working through the same process for RPU performance.

The process involves the same tight tolerances used in an audit. As soon as a unit fails, there is immediate communication through the transmission owner to the generator that it did not pass, and the Market Mitigation and Analysis Department starts follow-up immediately, Sawyer said.

If a resource does not perform, or performs poorly, it will fail the audit, upon which NYISO may derate the resource’s response rates and possibly the resource’s upper operating limit. For a gas turbine that fails to start during the audit, there would be a derate down to 0 MW.

It’s expected that the generator would respond with the cause of the failure and what has been done to mitigate it, Sawyer said. The ISO would perform another audit of the same generator within 48 hours.

New Business

NYISO acknowledged that, as part of the ongoing demand curve reset, it has proposed a revision to the logic of the model used to estimate net energy and ancillary services revenue earnings for the hypothetical peaking plant. The revision addresses a misalignment of natural gas prices with actual delivery date associated with such prices.

One stakeholder asked if the ISO has looked back to see whether the same thing happened in the model in use for the past three and a half years.

Michael DeSocio, the ISO’s director for market design, said they are still investigating that issue and will have results in a week, or earlier if possible.

Another stakeholder asked about fast-start pricing revisions, which the ISO is supposed to be implementing by the end of this year.

DeSocio said that the software is in development and that the ISO expects to wrap it up in a couple weeks and move to testing, still on time for implementation by year-end.

September 15, 2020

AEP Becomes 4th Utility to Join Nasdaq

American Electric Power on Tuesday announced it will become at least the fourth major U.S. utility to switch its stock listing from the New York Stock Exchange to the Nasdaq Stock Market, joining Exelon, Xcel Energy and Alliant Energy.

The move to Nasdaq’s Global Select Market will be effective with the market’s opening bell on Oct. 1. The company’s stock will continue to trade under the “AEP” ticker symbol.

AEP Nasdaq — AEP CEO Nick Akins | © *RTO Insider*

In explaining the move, AEP CEO Nick Akins said, “Nasdaq’s tradition of innovation aligns well with our company’s strategic goals.”

“As AEP transitions to a cleaner energy future, we’re harnessing the power of technology to create new solutions for our customers while bringing value to our shareholders,” he said.

Nasdaq claims it has won 76% of all switches among U.S. equity exchanges since 2005, saying “stocks listed on Nasdaq experience less volatility, tighter spreads and more depth.” It also says it is the only exchange in the Dow Jones North America Sustainability Index. Among the companies that have switched to Nasdaq are PepsiCo, T-Mobile, Kraft Foods and AstraZeneca.

Xcel, which switched from the NYSE effective Jan. 2, 2018, said it was the first Fortune 500 utility listed on Nasdaq. Alliant moved in late December 2018, noting its “shares will be listed on the same exchange as some of the world’s largest technology companies.”

Exelon, which made its move on Sept. 25, 2019, issued a press release saying it made the move to join “leading climate-focused innovators.”

“Nasdaq is the platform that many of the world’s leading innovators call home and — importantly — shares our commitment to a low-carbon economy and reducing greenhouse gas emissions,” Exelon CFO Joseph Nigro said in announcing its move. “We believe that moving to Nasdaq provides us the most cost-effective channel to connect with investors efficiently through technology.”

In recent years, Columbus, Ohio-based AEP has taken several actions to back up its mission of “redefining the future of energy and developing innovative solutions.” The company has an aspirational goal of zero emissions by 2050 and has said it believes it can cut CO2 emissions by more than 80% by 2050 from its 2000 levels. (See AEP Ups its Emission-reduction Targets for 2030.)