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.)

September 15, 2020

NY Study Highlights Rising Methane Emissions

New York’s greenhouse gas emissions in 2015 were virtually unchanged from 1990 levels, according to a newly published study that highlights upstream impacts and the role of methane under the state’s revised reporting rules.

The study, published in the Journal of Integrative Environmental Sciences, concludes that methane emissions have grown as carbon dioxide emissions have declined, leaving New York’s total GHG emissions in 2015 virtually unchanged from 1990.

The analysis by Robert Howarth, Cornell University professor of ecology and environmental biology, was based on the new emissions reporting rules enacted in the 2019 Climate Leadership and Community Protection Act (A8429), which calls for reporting to include emissions from outside New York if they are associated with energy use within the state. It also requires that methane emissions be compared with CO2 over a 20-year time frame rather than the 100-year time frame still used by virtually all other governments in the world, according to Howarth. Methane is about 80 times as potent at trapping heat as CO2 in the first 20 years but has a much shorter half-life.

New York Methan Emissions — Greenhouse gas emissions by sector and fuel type for fossil fuel energy use in New York state for 2015. Estimates reported by the state are shown on the left (NYSERDA), and estimates calculated using the CLCPA guidelines are shown on the right. | *Journal of Integrative Environmental Sciences*

Calculating Emissions

Howarth’s paper compares emissions based on the CLCPA approach for GHG reporting with the traditional inventory, driven almost entirely by CO2 emissions. As of 2015, the latest state data available for comparison, carbon emissions had declined by 15% since 1990, thanks to an 88% cut in coal consumption and a 27% decrease in petroleum use, he said, while methane emissions increased by almost 30% over the same period, largely from the increased consumption of natural gas. According to the new GHG reporting rules, methane rose from 28% of all fossil-fuel emissions in 1990 to 37% in 2015. (Other GHGs, including nitrous oxide and fluorocarbons, represent less than 4% of total emissions.)

“A robust conclusion is that total emissions have changed remarkably little over the past 25 years, when viewed through the lens of the CLCPA approach,” Howarth wrote.

It is difficult to establish the 1990 baseline greenhouse gas emissions, which the state needs to finalize by December 2020, Howarth said. Next year, the state agencies will determine how to account for contemporary GHG emissions, he said.

“I would prefer they be done together in a combined way … but I think overall, [the state agencies] have done a pretty good job,” Howarth, one of 22 members on the state’s Climate Action Council, told RTO Insider.

The CLCPA’s mandate means “not simply to rely on EPA-packaged emissions estimates, but rather to fall back and use the best available science, including the peer-reviewed academic science,” Howarth said. “They’re not using EPA estimates at all, which is good, because the EPA has systematically low-balled [emissions], particularly methane emissions from the oil and gas industry, for decades and continues to do so. And the peer-reviewed literature is full of papers where that’s been demonstrated time and time again.”

New York state agencies did not do a thorough review of the peer-reviewed literature and are relying on the Greek model, a method developed in Europe for estimating GHG emissions, which doesn’t reflect all the latest and best science, Howarth said. “I would have preferred the DEC [Department of Environmental Conservation] make sure they have the best science in there, but nevertheless, it’s a step in the right direction.”

Including out-of-state emissions in reporting “is a big step forward,” he said, because most methane emissions occur at the site of gas production, processing and storage. “When we use natural gas here in New York, a lot of those methane emissions are occurring in Pennsylvania, West Virginia [and] Ohio, and we should take responsibility for them. The DEC in their draft has included that, but they’ve come up with an estimate of methane that I think is low. It’s not as low as what the EPA would have you believe, but it’s still somewhat low,” Howarth said.

On the other hand, the DEC also included CO2 emissions from out of state that are associated with the mining, processing and transporting of the fuel, whether coal, oil or gas, he said.

“And they came up with a pretty big number for that. I sidestepped that in my paper and said you might want to do it, but I thought it was a pretty big challenge — beyond what I was going to take on,” Howarth said.

Last month, New York officials on the Climate Action Council discussed the DEC’s newly proposed statewide GHG limits of 60% of 1990 emissions by 2030 and 15% by 2050. Administrative Law Judge Molly McBride will conduct two public comment hearing webinar s for the proposed rule on Oct. 20, and public comments will be accepted by the DEC until Oct. 27. (See NY Seeks Comment on Proposed Emissions Limits.)

Meeting the CLCPA’s 2030 emissions target will require major reductions in natural gas use in the residential and commercial sector and similar cuts in petroleum use in transportation, Horwath said. “To date, the state has focused little attention on GHG emissions from these sectors and has instead prioritized reducing the use of fossil fuels to produce electricity.”

Converting from natural gas heating to modern heat pumps will reduce GHG emissions even if the heat pump is powered by electricity generated from fossil fuels, Howarth said. “Similarly, electric vehicles reduce overall emissions compared to gasoline- and diesel-powered vehicles, even if fossil fuels are used to produce the electricity, because of the greater efficiency of the electric vehicles. Consequently, to reduce overall GHG emissions for New York state, electrification of heating and transportation systems must proceed as quickly as possible, even if this precedes reduction of fossil fuels to produce electricity.”

September 15, 2020

NERC Planning Lessons Learned on COVID-19 Response

NERC is preparing a Lessons Learned report on the electrical industry’s response to the COVID-19 pandemic to help utilities prepare for future emergencies.

Speaking during a meeting of the Event Analysis Subcommittee (EAS) on Monday, Richard Hackman, NERC senior event analysis adviser, said the idea of compiling the industry’s experiences with the pandemic started in March, when utilities began to adjust their business practices to reduce the risk of losing critical personnel while still providing full service to customers.

Real-world Test for Contingency Planners

“I remembered that back in 2006, there were a whole lot of entities out there creating business continuity plans for all sorts of disasters,” Hackman said. “Pandemics [were] one of the things they tried to cover in that: how would they handle it if they had to operate in a pandemic environment, keep their controllers safe from disease carriers, segregate shifts … provide supplies to them while they are continuously on site and all sorts of issues that might come up.”

The Lessons Learned report, which will be produced by the EAS and the Operating Reliability Subcommittee, will compare these plans with their real-world test during the COVID-19 outbreak. NERC noted earlier this year that the arrival of an actual pandemic had exposed vulnerabilities that many in the industry had not anticipated — for example, in the increased risk from cyberattacks after many employees started working remotely. (See Pandemic Poses Long-term Reliability Challenges.)

The unexpected duration of the pandemic will also be explored by the groups; as Hackman acknowledged, even utilities that had contingency plans specifically for pandemics rarely anticipated the emergency to last longer than a few months. As a result, many companies had to adjust their plans on the fly to ensure they could remain in their emergency stances indefinitely. Utilities could study the effectiveness of these improvisations as they re-evaluate their plans following a return to normal operations.

Team to Probe Regulatory Response

In light of the relaxation of remote work postures by some utilities, the subcommittees hope to evaluate the effectiveness of companies’ plans for ending their emergency policies (though many industry participants, including NERC itself, plan to keep their offices closed for the foreseeable future). (See NERC Offices to Stay Closed Through December.) In addition, the subcommittees plan to examine the actions that regulatory agencies and policymakers took in response to the outbreak and how they helped to keep the grid stable.

“There were some things that are schedule-related that FERC, NERC Relax Compliance in Light of COVID-19.) “Are there other things that they could have used some regulatory relaxation on, and [can we] establish a list of such things, prior to the next time we’re brought into such an event?”

The subcommittees are seeking volunteers to participate in the drafting process. Once the team is formed, it will solicit notes and other information from utilities that could be helpful in creating the report. The subcommittees plan to begin work on the draft report by the end of October.

In response to a question about the protection of sensitive information, Hackman confirmed that the team will be careful to safeguard not only specific entities’ confidential data but also information that could point to more general weaknesses in the wider grid.

“We can communicate lessons learned in a generic fashion. There is some specific information in those notes that we might want to either genericize or leave out. … We don’t want to … provide a [path] to the bad guys on how to screw up a business plan,” he said.

September 14, 2020

WECC Board Approves New Chair, Long-term Strategy

“This year is our special first, and hopefully only, virtual meeting,” Kristine Hafner, (now former) WECC board chair, declared as she opened the regional entity’s annual meeting Thursday.

The meeting, typically part of a larger multiday affair hosted at a hotel in a Western city that also includes individual member class forums and a Board of Directors meeting, was this year transferred entirely to the Web in response to the ongoing COVID-19 pandemic. (See No ‘Hiccups’ for West’s RC Transition.)

ERO Insider tuned in for much of the event. Following is some of what we heard.

‘Gently Powerful’ Hafner Steps Aside as Chair

Friday’s board meeting featured a changing of the guard, as the term-limited Hafner yielded her position as chair to former Vice Chair Ian McKay, while Richard Campbell replaced McKay.

Hafner said it had been a “privilege and pleasure” to serve as chair since 2017 and that she looked forward to continued collaboration with the board.

WECC Board — WECC CEO Melanie Frye and board members Kristine Hafner and Ian McKay at WECC’s last in-person board meeting in March. McKay on Sept. 11 took over as board chair from Hafner, who had served in the role since 2017. | *Chad Coleman/WECC*

McKay said he could describe Hafner’s leadership style by borrowing a term he had heard elsewhere: “gently powerful.”

He noted that Hafner had led the board through a series of challenging issues, including the untimely passing of Director Armando Perez in 2017, a “sweeping” change of WECC’s bylaws, the hiring of a new CEO and — most recently — the pandemic.

“I found your leadership to be extremely effective because of your calming demeanor,” Director Richard Woodward said.

“It’s a big job, but it’s fascinating; it’s challenging; it’s such a learning experience,” Hafner said.

Future Focus

The board on Friday approved WECC’s proposed long-term strategy (LTS), which is built on the foundation of NERC’s ERO L ong-T erm S t rategy while offering a specific Western slant. (See WECC Seeks Western Bent on Strategy Plan.)

“It really acts as our guiding star for what we aspire to be,” Jordan White, WECC vice president of strategic engagement, told members and directors during the meeting Thursday. White joined WECC early this year after serving on the Utah Public Service Commission.

“The challenges on the bulk power system have never been greater,” White said.

During Thursday’s meeting, WECC staff elaborated on each of the five focus areas of the LTS.

Speaking about focus area 1 — “innovate and expand risk-based focus in all standards, compliance monitoring and enforcement actions,” Senior Vice President of Reliability and Security Oversight Steve Goodwill said WECC’s intent is to work with registered entities to move beyond mere compliance to focus on creating “a culture of risk identification and mitigation.” The RE wants to identify and address grid risks in ways that best reflect the “uniqueness” of the Western Interconnection, and it hopes a key outcome of the focus area is that the Western viewpoints are represented and incorporated into NERC reliability standards, he said.

Branden Sudduth, vice president of reliability planning and performance, said focus area 2 zeroes in on WECC’s “core mission” of assessing and mitigating known and emerging risks.

“This focus area is meant to really ensure we’re directing our [attention] in the right area,” Sudduth said. Success in this area, he said, would mean high precision in the models WECC uses to assess risk on the BPS and exploration of different ways to assess reliability.

White said focus area 3 covers WECC’s efforts to maintain and expand relationships with “key partners” and elevate its “relevance” in the region.

“It lets the rest of the West know about the amazing work that goes on at WECC,” White said, adding that the organization should become the “gold standard” for reliability expertise in the region. “I’d really love to see public service commissioners … start asking the question, ‘What does WECC have to say about this?’”

CFO Jillian Lessner said focus area 4 is “all about effective day-to-day business operations at WECC” and keeping it fiscally sound. Lessner said WECC seeks to be a “nimble” organization, citing its ability to quickly pivot to home-based working as an example.

CEO Melanie Frye called focus area 5 — building a “capability and culture” to deliver on the reliability mission — the “cornerstone” of the LTS.

“If we really sit back and think about what WECC does, we don’t make electricity; we don’t buy or sell. The value that we add to the interconnection is all about what we can create with the resources we have, and that is our people,” Frye said.

She said WECC needs to attract the “right talent” and that she wants the organization to be considered an “employer of choice.”

“The second piece of [the focus] is putting in the energy to build partnerships with experts in the industry,” Frye said, adding that WECC will “measure our success by how we’re respected as a partner.”

COVID-19 Response

WECC will continue its “work-from-home posture” for the foreseeable future and will not provide a target for return “because we’ve had to keep extending it,” Frye told board members Friday.

“Our first priority is the health and safety of our employees,” including mental health, she said, noting that WECC works to keep in contact with staff and hold regular webinars through its employee-assistance program to help them avoid a sense of isolation.

While Frye thinks WECC has been largely successful in completing its work since the onset of the pandemic, she wanted “to emphasize that we don’t think this is a permanent solution.”

“I think we all look forward to the future when we can safely travel and reconnect again,” she said.

Align a ‘Huge Undertaking’ and ‘Opportunity’

WECC faces a “huge undertaking” in having to train 400 registered entities on NERC’s Align software, which is now slated for release in the first quarter of 2021 — a year and a half later than originally expected. (See Align Tool Set for 2021 Rollout.)

Formerly known as the Compliance Monitoring and Enforcement Program Technology Project, Align is intended to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise.

“We really see the adoption of Align as a key corporate activity for 2021,” Goodwill told the board.

WECC wants members to be “very satisfied” with its work on the project, he said. “We see that as an opportunity in building our relationship with the registered entities.”

Blackout Talk

California’s recent rolling blackouts and the ongoing concern about future resource shortages in the West were among the hot topics of discussion at Friday’s board meeting. (See Theories Abound over California Blackouts Cause.)

Frye recounted that the heat wave precipitating the Aug. 14-15 blackouts drove temperatures to 15 to 30 degrees Fahrenheit above normal throughout much of the West, hindering the ability of neighboring states to export energy to California because of the need to meet their own high demand. Additionally, California’s wind generation fell off sharply, and a key gas-fired generator went offline unexpectedly.

“The California ISO was very proactive in dealing with this, making calls to other utilities,” Frye said. “I know the CEO [Steve Berberich] was getting engaged in making those calls at the CEO level to identify as many megawatts as possible [and] issuing public appeals for load reduction.”

Frye said the success of those efforts were evident during another heat wave occurring over the Labor Day weekend, when California was able to avoid load shedding despite getting to a Stage 3 emergency. (See California Avoids Blackouts amid Brutal Heat, Fires.)

“The public appeals for peak shaving were very effective, but at the end of the day, these are not the kinds of situations that we anticipate, and I don’t think any of us see this as an acceptable solution,” she said.

Frye noted that WECC will perform its own analysis of the events, “working very closely with the entities involved, as well as NERC, to identify the specific situation … and identify what can be done to improve this in the future.” (See CalCCA Seeks ‘Objective’ Review of Blackout Report.)

“It does highlight the conversation that we’ve been having in the West for the last year or so around resource adequacy, and that there does need to be a broader view of the issues,” she added.

“I was really struck by the incident itself,” Director Gary Leidich said. “I understand the weather situation and the imports, but the fact that this was during a pandemic over a weekend really causes a bit of an alarm bell to go off in terms of, ‘What’s the outlook?’

“While it’s always very interesting to talk about 2038 and long-term forecasts and such, I would really appreciate a brief summary on the outlook for the next three to five years in California, because I’m not sure it’s going to get a whole lot better,” Leidich said. “People are going to come back to work. We’re going to be in a Monday-through-Friday load picture. We’re going to shut down two units at Diablo Canyon and continue to retire thermal units, so the ramping capability will be challenged even more, I suspect.”

Vice Chair Campbell asked whether there was “any movement at NERC at all” in re-examining the assumptions in its Western long-term reliability assessment (LTRA).

“Wouldn’t NERC be interested to look at their data limitations in light of the West having to do its own thing, because we find their LTRA not sufficient and how it completely missed on this California event?” Campbell asked.

“We’ve had some conversations about the recent summer assessment that we published a few months ago, and how it did or didn’t reflect the conditions in California,” Sudduth responded. “I think the simple answer to your question is that we are definitely having those conversations and identifying ways to improve the process, and I think all of us are starting to understand some of the limitations of the data assumptions and the different types of analysis that go into the LTRA.”

Peak Windfall

The board also voted to authorize WECC to accept a $3.8 million donation from Peak Reliability, representing money left in the former reliability coordinator’s accounts after it settled obligations in the wake of its dissolution last year.

Peak’s bylaws required it to donate any leftover funds to a nonprofit, Goodwill explained to the board. The RC, formerly part of WECC before bifurcation separated the two in 2014, chose to turn over the largesse to its former parent organization.

While FERC must still approve WECC’s acceptance of the money, Goodwill encouraged the board to approve the transfer before filing to obtain permission to accept the funds and determine how they can be spent.

Goodwill said FERC could authorize WECC to treat the donation as statutory funds (with money directed for the RE’s core operations) because it had provided Peak with about $7.8 million in start-up funds to facilitate bifurcation. He said WECC would set aside up to $300,000 of the money to cover any trailing requests for payment from Peak.