Page 1111 – RTO Insider

April 15, 2020March 12, 2025

April Ballot Planned for SOL Standards

By Holden Mann

NERC’s team updating the requirements for determining and communicating system operating limits (SOLs) is preparing for a 45-day comment period and formal ballot to begin April 23 (Project 2015-09).

In a webinar earlier this week, standards drafting team chair Dean LaForest of ISO-NE said the team is hopeful that it has addressed industry objections raised in two previous ballots in 2017 and 2018 on standards FAC-010, FAC-011 and FAC-014. He acknowledged that the SDT’s efforts had not progressed as quickly as hoped over the past several years, due in part to a decision to expand its scope beyond NERC’s original mandate.

Complications from Scope Expansion

SOL Standards ballot — Dean LaForest, ISO-NE | © *ERO Insider*

“Our drafting team was established to modify a succinct set of FAC standards,” LaForest said. “What has ensued since is a realization … that to do so properly seems to also include an alignment of other standards … that deal with SOLs and SOL exceedances.”

The team saw this move as necessary since exceeding SOLs could have impacts across utilities’ operations, but its widening focus troubled industry participants. Along with the original three standards, the proposal eventually involved changes to CIP-014, PRC-002, PRC-023, PRC-026, FAC-003 and FAC-013, and introduced a new standard, FAC-015.

In particular, the team’s last in-person meeting this year focused on criticism of the potential administrative burden of the logging and communication activities required by the proposed standards. (See SOL Project Team Preparing for March Posting.)

Flexibility in Exceedance Communication

The latest proposal includes several modifications in response to these industry objections. Significantly, requirements in FAC-011 were updated to provide a “clear, consistent framework for SOL exceedance determination” and a new method for communicating exceedances between reliability coordinators and transmission operators. Reliability standards TOP-001 and IRO-008 would also be impacted by the changes.

Taken together, the new requirements would enable RCs to set a threshold for communicating exceedances based on the risk posed to the bulk power system, rather than being tied to a specific number. The team hopes this move will provide operators with the flexibility needed to respond to changing local conditions.

“We feel like this really allows the operators to focus on the critical activities of mitigating the SOL exceedance, rather than … [having] to have my operators pick up the phone … to tell someone else about something that happened five minutes ago,” said Stephen Solis of ERCOT. “That has been the focus of the last few months of intensive discussions on this particular subject, and we feel like we landed on a good spot [and] tied it to IRO and TOP standards so that the notification piece [doesn’t] take up a majority of the operator’s time.”

FAC Standard Changes Dialed Back

In another major update, the team decided to drop its proposed new standard, FAC-015 — which would have addressed criteria for determining SOLs — based on industry feedback that FAC-014 already meets this need without requiring a new standard. Instead, SDT members decided to add a new requirement to FAC-014 mandating that planning coordinators and transmission planners use facility ratings, voltage limits and stability criteria that are “at least as conservative as those used in operations.”

In addition to simplifying the SDT’s proposal, the change will also create a more straightforward case for retiring FAC-010, which relates to determining SOLs for system planners.

“As long as they are either more conservative than [those] used in operations, or they describe why they are not, they meet the intent of the requirement, and there is coordination between the limit assumptions used in operations and planning,” said LaForest. “We believe this will allow us to retire FAC-010 and still meet the original intent and purpose for the joint standards issued some 10-plus years ago.”

April 15, 2020

Judge: PG&E Can’t Pay Criminal Fines from Victim Trust

By Hudson Sangree

The judge in the Pacific Gas and Electric bankruptcy case on Tuesday prohibited the utility from paying its criminal fines from a trust fund meant to compensate fire victims. Instead, the company agreed during a hearing that it would pay its fines from interest on a separate escrow account.

The company agreed to plead guilty last month to 84 counts of involuntary manslaughter and one count of unlawfully starting a fire, with special circumstances including causing great bodily injury to a firefighter over the November 2018 Camp Fire. PG&E’s deal with the Butte County District Attorney calls for it to pay $3.5 million in fines and $500,000 to the prosecutor’s office to cover the costs of its investigation. (See PG&E to Plead Guilty to Killing 84 in Camp Fire.)

News that the utility planned to tap the victims fund for the fines caused an uproar among fire victims.

PG&E argued that it was required by the terms of its Chapter 11 restructuring agreements to pay the fines and fees from a $13.5 billion trust it plans to establish for more than 70,000 victims of blazes its equipment started in 2015, 2017 and 2018.

PG&E trust fund — Mailboxes and charred wreckage were all that was left of a senior-citizens’ mobile home park after the Camp Fire. | © *RTO Insider*

Paying the fines directly, in violation of the agreements, could allow the banks providing billions of dollars in backstop financing to back out of the deal, PG&E lead attorney Stephen Karotkin said during Tuesday’s hearing, which was held via conference call because of the coronavirus pandemic. He argued the company had been unfairly criticized for wanting to pay the fines from the victims’ trust.

“There was no sinister motive,” Karotkin said.

U.S. Bankruptcy Judge Dennis Montali said he couldn’t accept PG&E’s payment plan. Lawyers in the case had been masterful at preserving their clients’ legal rights, he said, “and my right here is to not tell the fire victims, ‘You’re going to pay $4 million to a company that has confessed and killed under the criminal laws.’”

The judge issued a tentative ruling Friday expressing similar sentiments.

“Some things not only have to be right, but they have to look right,” Montali wrote. “Telling fire victims that their money will be used to pay criminal fines and penalties does not look right even if digging through the [restructuring agreement] or the [reorganization] plan would lead to that literal result. Nor does saying to people who lost their homes and their loved ones that $4 million is ‘de minimis.’ This not only looks wrong, it is wrong.”

PG&E’s lawyers agreed that if the judge ordered it, the utility would pay its fines from interest accrued on an $11 billion escrow account it intends to establish for another group of claimants, insurance companies and hedge funds that hold third-party subrogation rights based on the prior payment of insurance claims.

Once the escrow account is funded, it will take about two weeks to accrue $4 million in interest, Karotkin told the judge.

PG&E, one of the nation’s largest utilities, filed for bankruptcy in January 2019 after two years of devastating wildfires. It’s hoping to emerge from bankruptcy by June 30 to avoid a threatened state takeover and to participate in a wildfire insurance fund established under state law.

The company has sent out approximately 250,000 ballots and disclosure statements to fire victims, creditors and others entitled to vote on its bankruptcy reorganization plan. The ballots are due by May 15.

The company has acknowledged its equipment ignited the Camp Fire, killing 84 residents and destroying 18,804 structures in and around Paradise, Calif. An 85th resident who died in the fire was deemed a suicide and not included in the charges.

April 15, 2020March 8, 2024

UPDATED: Michigan Prices Soar in 8th MISO Capacity Auction

By Amanda Durish Cook

[Updated to include MISO comments from conference call April 15.]

MISO’s eighth annual capacity auction marked the RTO’s first clearing price set by its cost of new entry (CONE), as prices in the Lower Peninsula of Michigan rocketed to almost $260/MW-day while all other zones cleared under $7/MW-day.

Zone 7 cleared at the CONE price of $257.53/MW-day for planning year 2020/21, beginning June 1.

The RTO’s CONE is used as the maximum offer and clearing price in the Planning Resource Auction. CONE represents the estimated annualized capital cost of constructing a 237-MW combustion turbine plant in different locations in the footprint.

Since beginning its capacity auctions in 2013, MISO has never experienced prices set by CONE. This year’s capacity prices in Lower Michigan are more than ten times the price of capacity paid in the last planning year.

The RTO said Zone 7 fell 123 MW short of its nearly 22-GW local clearing requirement and had to turn to other zones for capacity procurement, thereby triggering the CONE price. The RTO said only about 1,150 MW of load — 6% of Zone 7’s forecasted peak — must pay the CONE rate because MISO is mostly vertically integrated utilities that procure their own capacity outside the PRA.

“The results also reflect the industry’s ongoing shift away from coal-fired generation and increasing reliance on gas-fired resources and renewables,” the RTO said in a release.

All other MISO capacity zones remained below $7/MW-day, with most around $5/MW-day:

- - Zones 1-6 — which include Minnesota, Iowa, Illinois, Indiana, Missouri, Montana, Wisconsin and the Upper Peninsula of Michigan — cleared at $5/MW-day;
  - Arkansas’ Zone 8 and Mississippi’s Zone 10 cleared at $4.75/MW-day; and
  - Louisiana and Texas’ Zone 9 cleared at $6.88/MW-day.

Additionally, external resource zones cleared between $4.89-$5.00 depending on where they connect to the MISO system.

Last year, all zones cleared at $2.99/MW-day except for Zone 7, which cleared at $24.30/MW-day. (See Most MISO Zones Clear at $3/MW-day in 2019/20 PRA.)

The RTO received 141.5 GW worth of offers in this year’s auction, about 6 GW above the nearly 136-GW reserve margin requirement for June 2020 through May 2021. It expects an almost 122-GW coincident system peak this summer.

MISO also said the South-to-Midwest transmission transfer limit bound during the auction, causing a $0.25 price separation between the Midwest and South. The last time the transfer limit bound in the capacity auction was in 2016. Zone 9 also experienced a slightly more expensive clearing price than most other zones because of a higher local clearing requirement. MISO predicts zones will hit their summer peaks at different times and assigns separate local clearing requirements.

MISO stressed that it continues to have sufficient capacity in the footprint.

“This year’s results reflect adequate resource availability for the upcoming planning year,” MISO Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said. “The grid’s capability to effectively transfer resources among zones remains strong, and we appreciate our members’ participation.”

“Most of the zones cleared at a relatively low prices, reflecting trends we’ve seen over the last few years. The vast majority are well-positioned to meet their capacity needs,” MISO Manager of Capacity Market Administration Eric Thoms said during a special April 15 conference call to discuss auction results. “That’s indicative of the makeup of the footprint.”

But Thoms said Zone 7 has frequently been “very tight, capacity-wise.”

Thoms also emphasized to stakeholders that CONE is function of MISO’s FERC-accepted Tariff, and most load-serving entities in lower Michigan would not be exposed to the CONE price.

“Per the Tariff, if the zone is short of its local clearing requirement, it’s capped at CONE,” he explained.

Thoms also said Zone 7 was impacted by a new rule this year that prohibits resources from offering into the auction if they will be on outage for longer than 90 days of the first 120 days of the planning year. Thoms estimated that the rule impacted 200 to 300 MW of planning resources in Zone 7.

“Being that Zone 7 was tight on a razor’s edge … the outage policy contributed to the zone not being able to meet its local clearing requirement,” he said.

MISO fully expects to field more questions about Zone 7 at upcoming Resource Adequacy Subcommittee meetings, Thoms said.

“There’s going to be a lot of speculation about what this means for Zone 7 this summer,” Coalition of Midwest Transmission Customers attorney Jim Dauphinais said.

Before this year’s Zone 7 price, the most expensive capacity price ever recorded in MISO was the $150/MW-day in southern Illinois’ Zone 4 during the 2015/16 PRA. The price spurred allegations of market manipulation, a three-year FERC investigation and — five years later — a contested FERC assurance that nothing untoward occurred. (See FERC Shelves Grievances over MISO Capacity Auction.)

MISO said auction results line up with the annual Organization of MISO States-MISO resource adequacy survey, which predicted adequate reserves through 2022 but warned that Zone 7, Zone 4 and Indiana and western Kentucky’s Zone 6 have the greatest resource adequacy risks. Last year’s survey indicated a potential 0.9-GW shortage in lower Michigan in 2020. (See Supply Future Brighter, OMS-MISO Survey Shows.)

The RTO said conventional generation will provide about 80% of capacity this planning year. Coal is set to provide 34% of capacity, while natural gas will provide 38%. Nuclear generation again holds steady at about 9%.

However, MISO said renewable capacity continued to gain market share. It reported 850 MW of solar generation cleared this year’s auction — an increase of 25% from last year — and 3,275 MW of wind generation cleared, a 21% year-over-year increase. Demand-based resources also climbed, providing nearly 16 GW of capacity as compared to last year’s nearly 15 GW.

The RTO said will publish the cleared load-modifying resources to the nonpublic MISO Communications System by May 25.

April 15, 2020March 12, 2025

IPPs, Renewable Groups Seek FERC Carbon Pricing Conference

By Rich Heidorn Jr.

A broad coalition of independent power producers and renewable energy and trade groups petitioned FERC Monday to convene a technical conference on integrating carbon pricing into organized wholesale electric markets (AD20-14).

“Currently, certain FERC-jurisdictional wholesale electric energy and capacity markets are grappling with how to reconcile wholesale markets and state policies related to reducing carbon emissions, which has a bearing on FERC’s jurisdictional scope, such as how these markets function and the prices charged therein,” the group said. “In recognition of the fact that a number of organized markets are considering how to incorporate carbon pricing into organized wholesale electric markets to better align with state and regional carbon pricing mechanisms, the time appears ripe for the commission to convene a technical conference or workshop on these issues.”

Notably, the petitioners include both renewable energy advocates who support renewable portfolio standards and generators who say such state subsidies distort capacity markets. For example, the group includes independent power producer Calpine — whose complaint led to FERC’s December order requiring PJM to expand its Minimum Offer Price Rule (MOPR) to include all new state subsidized generation — and clean energy and renewable groups: Advanced Energy Economy, the American Council on Renewable Energy and the American Wind Energy Association.

A coalition of generators and renewable energy and trade groups asked FERC to hold a technical conference on integrating carbon pricing into wholesale electric markets, saying it should resume the discussion at the commission’s May 2017 conference (pictured). | RTO Insider

Also signing the petition were IPP groups the Electric Power Supply Association (EPSA), the Independent Power Producers of New York and PJM Power Providers Group, as well as several of their members, including LS Power Associates, NextEra Energy, Brookfield Renewable, Competitive Power Ventures and Vistra Energy. The Natural Gas Supply Association (NGSA) and think tank R Street Institute also joined in.

Notably absent was carbon pricing supporter Exelon, whose nuclear plants have benefited from zero-emission credits (ZECs) and would be subject to PJM’s expanded MOPR. Exelon did not immediately respond to a request for comment.

The request suggests the scope of the conference include a discussion of ways in which carbon could be priced and how wholesale market pricing and dispatch could account for compliance costs, including a look at existing constructs such as the Regional Greenhouse Gas Initiative (RGGI) and the California-Quebec cap-and-trade agreement, which last month won a prel i minary ruling in a challenge by the Trump administration.

“We think the commission could grant the request, particularly if other stakeholders welcome the idea of a discussion,” ClearView Energy Partners’ analyst Timothy Fox said in a report to clients. “… If FERC expresses no interest in participating in such discussions, then green-leaning states that have decarbonization of their electric portfolios as a central goal may find the organized markets as presently structured pose an impediment instead of a vehicle to reaching their goals.”

2017 Conference

The groups said the technical conference should “pick up where the commission left off” in its May 2017 technical conference on the interplay between wholesale markets and state policy choices (AD17-11). (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)

Fox said FERC’s June 2018 order that proposed a “carve out” for state-sponsored resources in PJM “appeared to be a solid move” in support of one of five potential pathways discussed by FERC staff at the conference, that of “accommodating” state policies. “However, we think the commission abandoned that path in its December 2019 order” directing PJM to expand its minimum offer price rule to cover all new state subsidized resources, he added.

Since the 2017 conference, NYISO has proposed introducing a carbon price in its wholesale market to accommodate the state’s approval of ZECs for some of its nuclear fleet.

PJM has released a study on how it could implement carbon pricing for a subset of its states, with border adjustments to counteract leakage. (See PJM: Carbon Pricing the Answer to S ubsidy Dispute.)

CAISO implemented a carbon adder in the Western Energy Imbalance Market for bids coming into California from states not subject to California’s cap and trade rules. (See FERC OKs CAIS O Changes to EIM Bid Adders.)

In addition, ISO-NE CEO Gordon van Welie recently expressed his support for carbon pricing. (See ISO-NE: States Must L ead on Carbon Pricing.)

Not Seeking a Rulemaking

The petitioners emphasized that they were not asking the Republican-controlled commission to institute a rulemaking nor suggesting that FERC direct implementation of a carbon pricing mechanism.

“The aim of the technical conference would be to facilitate a dialogue among a broad range of stakeholders and interested parties regarding the opportunities and challenges associated with integrating carbon pricing in the organized wholesale electric energy markets, in recognition that such carbon pricing may be an approach that furthers state policies while preserving the benefits of market-based approaches to electric energy markets.”

Jeff Dennis Advanced Energy Economy | Advanced Energy Economy

Jeff Dennis, managing director and general counsel of Advanced Energy Economy, said in an email that the “set of signatories … suggests alignment on the broad view that implementing carbon pricing in some form would be a good thing for the markets and for achieving decarbonization policy goals.”

” … As the petition notes, the signatories do not necessarily agree on all aspects of the role of carbon pricing in wholesale markets, including the degree and manner in which state policies will evolve in the future as carbon pricing is more broadly implemented in the electricity sector and beyond.”

Other members of the coalition issued statements in support on Tuesday.

Calpine CEO Thad Hill | © RTO Insider

“Calpine’s core principles include support for competition and environmental stewardship,” CEO Thad Hill said. “We believe that placing an economy-wide price on carbon will spur competitive markets to produce the most cost effective and environmentally responsible solutions.”

EPSA CEO Todd Snitchler said, “America’s competitive electricity markets are a success story — and market-based mechanisms such as carbon pricing could be a powerful tool as we write the next chapter.”

“Our hope is that FERC’s willingness to convene a broad stakeholder discussion on carbon pricing will prompt states to seriously consider it as a solution to meeting consumers’ needs and clean energy targets,” said Dena Wiggins, CEO of the NGSA.

Natural Gas Supply Association CEO Dena Wiggins | © RTO Insider

PJM Power Providers Group President Glen Thomas said “the piecemeal carbon policies that are emerging in the PJM footprint are growing increasingly problematic and leading to less efficient markets for consumers. It is time for a regional and national conversation in order to evaluate whether there is a better regional solution out there. We hope that FERC accepts this opportunity to facilitate that conversation.”

Texas-based Vistra Energy “strongly believes that a nationwide carbon-pricing policy, like the [Climate Leadership Council’s] Bipar t isan Climate Roadmap sets forth, is the most effective, achievable and fair solution,” said CEO Curt Morgan. “Our company also holds that regional carbon pricing is a worthy intermediate step and a discussion at FERC could facilitate further discussions at the ISO and regional level.”

April 15, 2020

Monitor Casts Doubts on MISO-SPP CTS Benefits

By Amanda Durish Cook

SPP’s Market Monitor is cautioning that MISO and SPP must rethink some of their fees and practices before rolling out coordinated transaction scheduling (CTS) across their shared seam.

Internal Market Monitor Keith Collins says that introduction of CTS to maximize use of unscheduled transmission capacity could be ineffective unless the two RTOs remove the transmission fees and market charges they impose on each other.

MISO SPP CTS Benefits — SPP MMU Executive Director Keith Collins | © *RTO Insider*

“The benefits are difficult to quantify,” Collins said during an April 13 teleconference of the Seams Liaison Committee (SLC) of the Organization of MISO States (OMS) and the SPP Regional State Committee (RSC).

Collins said he’s collaborating with MISO Independent Market Monitor David Patton on a study to quantify possible benefits, which will likely be finished in early May. The study is part of the Monitors’ joint investigation of seams issues performed at the behest of regulators in both footprints.

“If we leave things as is, I think it’s important to understand that there may be no benefits … There need to be some additional changes in order to unlock benefits,” Collins said.

Collins additionally advised that MISO and SPP must improve the accuracy of their price forecasting to ensure that CTS delivers on its promises. The current approach to calculating forecasted prices “removes all benefits of a CTS product” because both RTOs find it difficult to anticipate price spikes or negative prices, he said.

“Assuming the current market products and market constructs, there is potentially no benefit to implementing CTS. Assuming no transaction costs and perfect knowledge of prices, CTS can likely improve total market welfare,” he said.

Collins singled out SPP for its oft-unstable prices.

“When prices can go up and down several hundred dollars in the space of five to ten minutes, it can erode some of the potential benefits of CTS if you were caught sending power at the wrong time,” he said.

SPP will soon file with FERC for approval of a ramping product designed to address its price volatility, which Collins said should help facilitate use of CTS.

MISO and PJM launched CTS across their shared border in late 2017 to allow market participants to schedule economic transmission transactions based on forecasted energy prices. PJM reported in November that CTS transactions accounted for about 19 MW per interval from June to September 2019.

M2M Efforts Proceed

Meanwhile, MISO’s IMM is wrapping up a study of the effectiveness of a MISO-SPP effort to coordinate the management of congestion on market-to-market (M2M) flowgates when one RTO is able to provide relief for a constraint.

Patton said he estimates that M2M congestion “would fall by $35 million annually if the M2M processes were administered perfectly.” The two RTOs combined rack up a little more than $184 million per year in M2M congestion due to delays or failures in testing for M2M flowgates and delays in activating them for monitoring.

To maximize flowgate management, Patton said, the RTOs should seek out, test and activate as M2M constraints the shared transmission most prone to binding. He said MISO and SPP could “accelerate” their testing and activation efforts.

The IMM will release final study results and more pointed recommendations in May.

Unsurprisingly, SPP’s Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border again weighs in as the most expensive based on preliminary numbers, costing MISO nearly $13 million in M2M settlement payments to SPP over the past two years. The flowgate has routinely been cited as the most expensive between the RTOs. (See SPP Briefs: M2M Payments from MISO to SPP Eclipse $32M.)

MISO and SPP said they are working together to estimate the congestion costs for each RTO for the top 10 most expensive flowgates in each direction. RTO staff said they would present the congestion cost estimates of the 20 flowgates at the SLC meeting in May.

April 15, 2020

Align Tool Set for 2021 Rollout

By Holden Mann

NERC’s Align software project is now set to be released in the first quarter of 2021, after the rollout date for the tool was revised last year from September 2019 to the second or third quarter of this year. (See Align Rollout Delayed to 2020.)

Align — formerly known as the CMEP (Compliance Monitoring and Enforcement Program) Technology Project — is intended to improve and standardize compliance monitoring and reporting processes across the ERO Enterprise.

NERC Align Tool — NERC CEO Jim Robb | © *ERO Insider*

Speaking to the Member Representatives Committee’s (MRC) premeeting informational conference call on Wednesday, NERC CEO Jim Robb attributed the further delay to development of the Secure Evidence Locker. This security feature was originally intended to be included in an update but was added to the initial release at the request of registered entities when the project was delayed for the first time last summer, because of concerns over the software provider’s ties to a Hong Kong-based private equity firm. (See NERC Investigating Chinese Tie to Software Vendor.) [NOTE: An earlier version of this article incorrectly said the feature was added at the request of regional entities.]

The ongoing development delay has caused the cost of the project to rise beyond its original estimate by up to $2 million, according to Andy Sharp, NERC’s interim CFO. Approval for the expenditure will be requested during the MRC conference call scheduled for May 14, with the funding expected to come from NERC’s operating contingency reserves for 2021.

Upfront costs for the project of $3.8 million, which were not included in NERC’s budget for this year, will also require a variance to be filed with FERC, Sharp said. The organization expects to fund the investment with a projected $1 million surplus from the operating contingency reserves for this year, in addition to debt financing of $2.8 million.

Sharp told attendees that he is pursuing a 60-month term for this loan rather than the typical 36 months, as the current low interest rates mean overall servicing costs will be the same or lower than previous projections of debt service for this year.

“The costs of delay and implementation of these sorts of projects are significant, and they will increase if there is further delay,” NERC Board of Trustees Chair Roy Thilly said. “So what we need to do is move carefully, effectively and expeditiously at the same time to resolve these matters.”

Robb Delivers COVID-19 Update

Robb also provided listeners with an update on NERC’s response to the COVID-19 pandemic. The organization has now confirmed three cases of the coronavirus among its staff, including the first case reported in March. (See NERC Employee Tests Positive for Coronavirus.) However, all have either fully recovered or are recovering well, and Robb said there is “no evidence of any community spread through the NERC ecosystem.”

The ERO is presently in a “full remote work posture,” which it plans to maintain through July 4, though its offices are expected to formally reopen by May 25. In addition, all external meetings through June have been either canceled or converted to conference calls. Events previously scheduled for July and August are expected to undergo similar changes.

GridSecCon, the annual security conference sponsored by the Electricity Information Sharing and Analysis Center scheduled for Oct. 20-23, has also been canceled this year, while the inaugural Electric Power Human Performance Improvement Symposium, planned for Sept. 29 to Oct. 1, has been delayed to next spring.

NERC said earlier this month that the industry has “[taken] aggressive steps” in response to the pandemic, with most utilities either having a written response plan or currently developing one, and a majority pledging to support mutual aid requests from others involved in a pandemic emergency. (See Industry Pandemic Prep Encouraging, NERC Says.) The organization issued a Level 2 alert in March and has activated its Business Continuity Plan.

April 15, 2020

MISO Begins Bid to Merge Tx, Queue Planning

By Amanda Durish Cook

MISO staff will commence work on a project to better align generation interconnections and transmission planning after stakeholders retired the task team charged with suggesting ways to bridge the two processes.

Stakeholders created the Coordinated Planning Process Task Team in November to probe how MISO could increase coordination between the separate studies underpinning the RTO’s Transmission Expansion Plan (MTEP) and its generator interconnection queue process.

The team in February forwarded MISO’s Planning Advisory Committee and Planning Subcommittee a list of topics to address. (See MISO Committees Tackle Queue, Tx Planning Disparities.) With the task list in hand, the PAC on Wednesday voted to retire the team during a teleconference.

MISO will now examine the two study processes as a first step in possibly unifying them. Senior Manager of Expansion Planning Edin Habibovic said the RTO would begin with “an in-depth review of MISO planning study objectives, methodologies and assumptions.”

“MISO believes it is prudent to review MISO’s planning processes, identify correlation and document rationale for any disparities between them,” Habibovic said during a Planning Subcommittee teleconference Tuesday.

Habibovic said the review will occur in planning meetings and special meetings scheduled through August.

MISO renewable proponents and some state regulators have repeatedly contended that the RTO unfairly relies on interconnection customers to finance increasingly expensive new transmission capacity under the pretext of network upgrades and may be neglecting its responsibility to get major projects approved in its transmission packages. Renewable advocates have questioned why interconnection studies show the need for expensive transmission upgrades when studies performed under the MTEP do not.

Stakeholders have suggested MISO better align the timelines of interconnection and MTEP planning and ensure the studies draw on similar data, including dispatch assumptions. The synchronization effort could have the RTO approving more transmission projects by MTEP 2021. (See MISO Seeks Ideas for Streamlined Tx Planning.)

MISO is currently juggling 10 separate queue cycles among its four planning regions, with five additional cycles set to begin over the next year. Senior Manager of Economic Planning Neil Shah said the unusually high number of queue cycles being processed in unison will be an obstacle to aligning timelines with MTEP.

April 15, 2020

MISO to File 1st COVID-19 Queue Waiver Request

MISO will ask FERC to waive a specific generation interconnection queue requirement to assist developers whose projects face construction preparation delays in the face of the COVID-19 pandemic.

The RTO will request a “limited FERC waiver” of its June 25 deadline for developers to demonstrate site control for projects entering MISO South’s 2020 interconnection cycle, Manager of Probabilistic Resource Studies Ryan Westphal told listeners on a Planning Advisory Committee call Wednesday. MISO has settled on a 60-day extension of the deadline.

MISO COVID-19 Queue Waiver — Ryan Westphal, MISO | © *RTO Insider*

Westphal said the chief concern of most interconnection customers is how they will meet deadlines to show exclusive land use for generation projects during the pandemic. MISO’s next site control deadline doesn’t occur until September, when the 2020 MISO West batch of projects enter the queue.

“There’s still uncertainty of when some states and localities will lift restrictions,” he said. “We’re looking at the near future and can go back to FERC to extend waivers as necessary.”

Westphal said the request specifically applies to the site control deadline and would not affect other queue deadlines. However, he said, additional waivers “are on the table” if the pandemic wears on and groups of interconnection customers encounter similar obstacles. (See MISO Considers COVID-19 Queue Waivers.) “At least” two interconnection customers have reached out to MISO to discuss special circumstances affecting their projects, he said.

MISO will not hold a call to discuss the finalized filing with stakeholders and will file in the “next two weeks,” Westphal said.

Social distancing efforts have been skewing MISO load and planned outages since mid-March. (See COVID-19 Transforming MISO Load, Outage Schedules.)

— Amanda Durish Cook

April 14, 2020

Methane Levels Hit All-time High

By Rich Heidorn Jr.

Emissions of heat-trapping methane hit a new high in 2019, according to preliminary data from the National Oceanic and Atmospheric Administration.

The agency reported globally averaged atmospheric methane levels hit 1,874.7 parts per billion in December 2019, an increase of almost 0.5% from a year earlier and the second-largest annual increase in the last 20 years. NOAA cautioned that its analysis was preliminary; final numbers are expected in November.

Methane is emitted by cows, sheep, microbes in wetlands, and oil and gas wells. While it remains in the atmosphere for only about a decade, much less than CO2, it absorbs much more energy than CO2. Thus, EPA says methane’s g lobal w arming p otential (GWP) is about 30 times that of carbon dioxide.

After almost leveling off between 2000 and 2005, methane emissions have increased sharply since 2006, a period in which U.S. natural gas production has increased by more than 70%, according to the Energy Information Administration.

Methane emissions from the oil and gas sector totaled almost 80 million tons in 2017, 6% of global energy sector greenhouse gas emissions, according to the International Energy Agency.

Because methane is valuable, IEA says almost half of the emissions from drilling could be captured at no net cost.

“Emissions remain high despite initial industry-led initiatives and government policies announced recently,” IEA said. “Implementing abatement options quickly and at scale remains a real challenge.”

ExxonMobil Field Trials

ExxonMobil announced last week it is conducting field trials of eight methane detection technologies, including satellite and aerial surveillance monitoring, at nearly 1,000 sites in Texas and New Mexico.

“The field tests are evaluating effectiveness and scalability of a range of next-generation detection technologies that, in addition to satellites, use drones, planes, helicopters, [and] ground-based mobile and fixed-position sensors. All technologies and deployment methods will be used to detect leaks and identify potential solutions that can be shared with other oil and gas operators,” the company said.

“We are already seeing the benefits of some of these technologies,” said Staale Gjervik, president of ExxonMobil subsidiary XTO Energy. “Through the trials, we have discovered methane sources that would otherwise not have been detected as efficiently or quickly under the current methods prescribed by regulations. The company is committed to immediately investigating and fixing methane emissions that are detected during the trial.”

The company said it reduced emissions by almost 20% in its U.S. unconventional operations between 2016 and 2019. It has made a corporate-wide commitment to reduce methane emissions by 15% and reduce flaring by 25% by the end of 2020.

In March, ExxonMobil proposed a regulatory model for reducing emissions.

The Trump administration in 2018 reversed proposed regulations to reduce leaking, venting and flaring of methane at drill sites on federal and tribal land and a requirement that companies monitor and repair methane leaks.

Dry natural gas production grew by 10% to a record 92.2 Bcfd in 2019 but is expected to drop slightly in 2020 and 2021 because of low prices, EIA said last week in in its Short-Term Energy Outlook. The agency also said its forecasts are “subject to heightened levels of uncertainty” because the impacts of the COVID-19 pandemic on energy markets are “still evolving.” (See related story, EIA: Renewable Capacity to Grow in 2020.)

The economic shutdown caused by the pandemic could reduce global carbon dioxide emissions by more than 5% this year, according to the Global Carbon Project. It would be biggest reduction since the end of World War II.

April 14, 2020

New Pa. Generator Hedging Gas Prices with Ethane

By Michael Yoder

The Marcellus Shale formation has turned Pennsylvania into the nation’s No. 2 natural gas producer and made it a favorite spot for new gas-fired electric generation. Natural gas’s share of the state’s electric production more than doubled to 36% from 2010 to 2018.

But there is something different about the state’s newest generating plant. If natural gas prices rise from their current low prices, Competitive Power Ventures’ 1,050-MW Fairview Energy Center near Johnstown can add up to 25% ethane into its fuel mix — the first generation facility of its size in the world with that kind of flexibility, according to CPV.

CPV’s Fairview Energy Center | *Competitive Power Ventures*

Located on an 86-acre former brownfield site in Jackson Township, Cambria County, the General Electric-designed combined cycle plant successfully completed ethane testing in March and went into full combined operation this month.

Bill Lawson, senior engineer for new products at GE Gas Power, said customers have been seeking the ability to burn an array of gases to respond to fluctuating commodity prices. Lawson said GE began looking several years ago at shale gas and its byproducts, including ethane, that could serve in power generation.

“GE saw this trend developing early and focused technology development to broaden our fuel flexibility,” Lawson said.

Price Trends

Ethane, commonly referred to as a natural gas liquid, is a hydrocarbon that can be found underground in shale and coal beds. In addition to being burned as a fuel, ethane also is used to produce ethylene, a chemical used in the manufacturing of plastics, automotive antifreeze and detergent.

According to the Energy Information Administration, ethane prices tracked crude oil spot prices until 2008 but began to diverge as U.S. production growth from shale gas and tight oil formations overwhelmed ethane consumption by the domestic petrochemical industry. By 2012, ethane prices closely tracked natural gas prices, staying within $1/MMBtu of the Henry Hub natural gas spot price on a heating-value-equivalent basis.

Since late 2017, EIA says, ethane demand has been growing because of increased petrochemical use and ethane export capacity. “As a result, ethane prices began to move away from their link to natural gas prices, and they are now bracketed by propane at the top and natural gas at the bottom of the range,” EIA said.

Ethane spot prices fell 17% from January to March this year — while natural gas prices dropped 11% and international crude oil fell about 46% — because of the economic slowdown from the COVID-19 pandemic.

Nearby Pipelines, Transmission

Natural gas for Fairview comes from the Enbridge Texas Eastern Transmission gas lines, about 1 mile north of the plant site. The ethane comes from Mariner East pipelines located on site. The plant also is adjacent to a 500-kV circuit that delivers its output to PJM, enough for 1 million homes and businesses.

CPV, which has ownership interests in 4.2 GW of generation in the U.S, partnered with Osaka Gas on the plant.

Jeff Ahrens, vice president of engineering and construction for CPV and the director of the $1 billion project, said the company wanted to incorporate ethane from an early stage in the plant’s development. While CPV had experience with the equipment and engineering needed for natural gas generators, adding ethane presented new challenges.

“It’s the first of its kind on this scale, so it required a lot of patience to make sure we did it right, make sure everything was designed correctly and look at all the different scenarios that the system needed to have to be reliable and safe for us,” Ahrens said. “Every step was somewhat new.”

Fairview was Ahrens’ second project for CPV, following the St. Charles Energy Center, a 745-MW combined cycle plant in Waldorf, Md., that went into operation in 2017.

Ahrens said one of the biggest challenges was that ethane comes to the plant in liquid form and requires vaporization to mix with the natural gas.

Natural gas is more buoyant than ethane, Ahrens said, so designs had to be created to find the right way to mix the two. The result was a GE vaporizer as large as a truck to mix the two fuels.

Fairview took nearly three years of development before construction began, requiring a team of hundreds of GE and CPV engineers, manufacturers, logistics exports and transportation workers.

“It required a lot of research, understanding [and] getting the right team members together who either had some experience or knew people who had experience, like petrochemical guys in the oil and gas industries,” Ahrens said.