FERC last week authorized both ITC Midwest and American Transmission Co. to recover all of their “prudently incurred costs” if the Cardinal-Hickory Creek project is abandoned or canceled for reasons beyond their control (ER19-355, ER19-360). Both companies filed for the rate incentive in November.
“We agree that the project faces certain regulatory, environmental and siting risks that are beyond the control of management and which could lead to abandonment of the project,” FERC said.
Cardinal-Hickory Creek line route | ATC
The commission said the $500 million project meets the criteria for the abandoned plant incentive because it had been found to enhance reliability and reduce congestion through MISO’s annual Transmission Expansion Plan.
One of MISO’s 2011 multi-value projects, the 345-kV line will consist of 102 to 120 miles of transmission from southern Wisconsin to eastern Iowa with multiple substation updates. The project is intended to transport wind power and lessen the burden on existing 345-kV and 138-kV lines in the area.
Construction of the line is currently in a holding pattern because of the ongoing partial federal government shutdown. The Wisconsin State Journal reported that six public meetings Jan. 22-29 regarding the line’s environmental impact have been canceled. The U.S. Department of Agriculture’s Rural Utility Service had been conducting an environmental review of the line before the shutdown. The meetings cannot be rescheduled until the government reopens.
Stakeholders Approve Streamlined Generator Interconnection Process
NEW ORLEANS — SPP stakeholders last week unanimously approved changes to the RTO’s generator interconnection process to simplify what had become a burdensome process involving the submission of repetitive data.
The Market and Operations Policy Committee approved a revision request (RR335) that adopts a three-stage study process: thermal and voltage analysis, stability analysis, and facilities study. The RR also changes the amount and timing of security deposits, publishes study models earlier in the process, and allows penalty-free withdrawals when costs increase above certain thresholds.
The task force said the new process will be easier for SPP to administer and for users to understand and navigate, with most upgrades being identified in the first stage. That would allow transmission customers to make an informed decision before committing to a lengthy and costly stability analysis.
The group said reducing the number of withdrawal requests late in the process would reduce restudies and uncertainty. Customers will be able to withdraw after the second of three decision points without incurring financial penalties when assigned upgrade costs increase by at least 35% and $15,000/MW between study stages.
The measure was brought forward by the Regional Tariff Working Group (RTWG), which took up the issue following last year’s dissolution of the Generator Interconnection Improvement Task Force (GIITF). The GIITF was created in 2016 to identify improvements in SPP’s transmission study process, which had become clogged with more than 62 GW of interconnection requests. (See SPP Generator Interconnection Group Wraps up Work.)
Proposed GI study process (3-stage) | SPP
20-Year RR Tabled
The committee tabled a second RR (RR334) that would add the 20-year Integrated Transmission Planning (ITP) economic-only assessment as an eligible study in determining whether projects are eligible to become competitive upgrades.
SPP has not previously issued notifications to construct (NTCs) based on long-range studies, although it is not precluded. Evergy opposed the RR within the RTWG, saying the 20-year assessment is intended to be indicative and that no NTCs should be issued without additional analysis in the annual ITP study. To do so would mean SPP was issuing an NTC for a project without studying its reliability impact on the system, Evergy said.
The MOPC asked staff to return the RR when its language is clarified to make it clear the 20-year-assessment would not result in NTCs being issued without additional study to evaluate its reliability impact and the year the project is needed.
HITT Educates MOPC on its Progress, Learnings
The Holistic Integrated Tariff Team (HITT) conducted an education session before the MOPC meeting formally began, briefing stakeholders on its work and issuing a last request for additional information. The team has been meeting since April on a plethora of presentations and proposals.
SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary, told the committee that a final report will be issued to the Board of Directors in April. The report will include details on which stakeholder groups will be tasked with working out the specifics in the Tariff language, policies, implementation and timelines.
“It’s become obvious to HITT members that technology is rapidly changing and rapidly impacting our industry,” Suskie said. “We always talk about turning the aircraft carrier in this industry. Technology is changing how rapidly the aircraft carrier is turning.”
Nebraska Public Power District’s Tom Kent, who chairs the HITT, said the group has narrowed its high-level policy recommendations to four subjects:
Aligning SPP’s transmission planning processes and stakeholders’ resource adequacy needs with the Integrated Marketplace and Tariff requirements;
Reviewing of existing transmission cost allocation methodologies;
Holistically understanding of the Integrated Marketplace and essential reliability services in the face of the changing generation mix and new technologies; and
Facilitating load-growth opportunities in the footprint.
A stakeholder panel on transmission planning and resource adequacy noted “traditional” planning processes have focused on the reliable delivery of firm capacity resources, while energy markets, public policy initiatives and other incentives have led to the increased development of
Supply Adequacy Working Group Chair Brad Hans of the Municipal Energy Agency of Nebraska said his group is working to ensure SPP maintains the “right type of resources.”
“How much variable energy resources do you allow in the footprint?” he asked. “The way we should look at it is, ‘How much dispatchable resources do you need to keep at all times from a reliability perspective?’”
Arkansas Public Service Commission staffer Cindy Ireland summarized a review of SPP’s cost allocation methodologies by saying, “At the end of the day, load is going to pay.” A member of the Cost Allocation Working Group, Ireland said the group is discussing which is the appropriate load to pay.
The market panel said SPP is considering a ramping product, but as staff’s Gary Cate said, pointing to MISO’s and CAISO’s products and ISO-NE’s exploration of the same, “We’re not breaking new ground with a ramp product.”
1A Task Force’s Fee Schedules OK’d
The MOPC approved four Schedule 1A rate schedules, an effort to recover SPP’s costs from the users of its services.
Members backed a recommendation from the Schedule 1A Task Force, commissioned last July, for:
Planning, scheduling and dispatch;
Transmission congestion rights administration;
Market clearing; and
Markets facilitation.
Evergy’s John Olsen said the group will now draft Tariff language and a white paper, which will be sent through the RTWG. He said the Tariff language would come back to the MOPC in April or July.
Olsen said the group spent much of its time discussing energy billing determinants and debated virtual transactions. He said one concern for the task force is avoiding the creation of discriminatory treatment.
The group has yet to include energy transactions in the rate design.
The measure was opposed by Oklahoma Gas & Electric Services and BP Wind Energy North America. ITC Holdings and Tenaska Power Services abstained.
Proposed new rate structure | SPP
MWG Withdraws 2 Revision Requests
The MOPC approved the Market Working Group’s recommendations to withdraw an RR related to the timing of real-time balancing market submittals. RR329 would have modified the market user interface (MUI) to allow market participants to “systematically” submit certain offer parameters on a continual basis. As designed, the MUI locks out users less than 30 minutes before each operating hour.
SPP’s Market Monitoring Unit said it could not support the RR because it doesn’t include language requiring generators’ parameters be based on physical limitations. The Monitor said it believes that physical parameters included in a resource offer should be based on “true, accurate and verifiable physical capabilities or limitations of the resource.”
The MWG said it was also withdrawing RR337, which calls for the MMU to file an annual review of frequently constrained areas (FCAs). FERC’s acceptance in December of SPP’s revised plan for a timely update of FCAs eliminated the requirement for an annual update. (See “FERC Approves SPP’s Streamlined FCA Process,” SPP FERC Briefs: FCAs, NPPD Complaint, Refunds.)
Staff Reports: MISO Event, Western RC Services
Staff told stakeholders that a FERC inquiry into last year’s emergency event with MISO is expected to be completed by early in the second quarter.
In January, severe cold weather and generation shortfalls in MISO South led MISO to exceed its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. MISO made emergency energy purchases from Southern Co. before operations returned to normal.
The two RTOs have been working since then to improve coordination across their seam.
Operations Vice President Bruce Rew told stakeholders that SPP’s effort to provide reliability coordination services in the Western Interconnection remains on track to be certified in August. He said the RTO has added about half of the necessary staff and expanded some of its models to incorporate Western entities.
SPP has signed RC contracts with about 12% of Western Interconnection load. It is scheduled to go live with its RC services Dec. 3.
Staff reported that the 2019 ITP process is off to a slow start with a couple of slipped milestones but said that won’t affect the downstream schedule. The study’s economic model and its balancing authority reliability power-flow models are scheduled to be completed in November.
The detailed project proposal window opened Jan. 8 and will close Feb. 6.
At the same time, the 2020 ITP process has just begun. Director of Transmission Planning Antoine Lucas requested stakeholder engagement, saying staff would soon be soliciting information for load and generation profiles.
MOPC Adapts to Leadership, Other Changes
The Jan. 15 MOPC meeting was the first in 18 years without SPP COO Carl Monroe serving as staff secretary. He was replaced by Lanny Nickell, SPP’s vice president of engineering.
“I guess we finally got it right enough, so we can let him step aside,” cracked board Chair Larry Altenbaumer.
The meeting was also the first that stakeholders could access over the Internet.
Staff and members also recognized outgoing MOPC Chair Paul Malone for his “passionate, devoted and conscientious service.” Malone is retiring from NPPD in February.
Among the several changes facing the committee is the newly delegated authority to approve Tariff- or criteria-related changes without sending them on to the board for final approval. Stakeholders can still appeal a MOPC decision to the board but must do so within a week of the decision.
The committee passed two such changes:
Its unanimous endorsement of the 2019 SPP Transmission Expansion Plan (STEP), which lists all transmission projects needed over a 20-year planning horizon. The plan consists of 568 upgrades totaling $5.2 billion and documents the completion of $779 million worth of upgrades and the issuance of 23 NTCs last year.
Its approval of East River Electric Power Cooperative’s sponsored upgrades of a new 115-kV line and a 115/69-kV transformer near Aberdeen, S.D. The project will be a creditable upgrade eligible for incremental long-term congestion rights or cost recovery through Attachment Z2.
Staff Withdraws 4 Mountain West Tariff Changes
The MOPC’s consent agenda included the withdrawal of four RRs related to SPP’s proposed integration of the Mountain West Transmission Group: MWG RR281, MWG RR282, MWG RR284 and MWG RR286.
The RRs were approved by the MWG in April 2018 but were rendered moot by the halt of integration efforts last year.
The 2020 ITP assessment scope’s approval was pulled from the consent agenda because of concerns over its age-based retirement of certain generating units. It was approved separately despite opposition from Southwestern Public Service and Xcel Energy Southwest Transmission.
The consent agenda’s unanimous approval also resulted in a charter revision for the Model Development Working Group, expanding its voting membership to “up to” 24, and in the Event Analysis Working Group’s (EAWG) dissolution. Created in 2017 to review major bulk electric system events, the EAWG was never called into action. Its responsibilities will now be picked up by other working groups.
Approved RRs included:
BPWG RR331: Clarifies and reorganizes interchange tagging business practices for denial of schedules and emergency tags.
MWG RR326: Updates expired language (replacing “bill statements” with “settlement determinant report”) and removes a redundant requirement to create documentation for a miscellaneous charge already included in the asset owner determinant report.
MWG RR341: Aligns the Integrated Marketplace protocols and Tariff to comply with FERC Order 745 by modifying how the net benefits test is calculated.
MWG RR342: Modifies attributes, definitions and names of determinants, and restructures a calculation to be consistent with existing calculations. The changes are necessary to implement automated contingency reserve deployment tests.
RTWG RR330: Changes non-firm daily service submissions to no later than 10 a.m. CT and closes the daily non-firm submission window when the non-firm hourly submission window opens, matching the release of unscheduled firm transmission service to the non-firm market.
TWG RR237: Removes duplicative or unnecessary language in the SPP criteria to make it consistent with NERC Standard TPL-001-4’s requirements and account for the differences between NERC’s requirements and SPP’s Tariff.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
1. PJM Manuals (9:15-9:35)
Members will be asked to endorse the following manual changes:
C. Manual 14B: Regional Transmission Planning Process: Minor changes to ensure consistent terminology; revision to Section 1A on critical energy infrastructure information (CEII); Attachment C revisions concerning changes to load deliverability procedures; and updated generator and long-term deliverability procedures.
Transmission owners will compete with load interests and merchant transmission operators for stakeholder endorsement of proposed manual revisions to address end-of-life facilities in the PJM planning process.
American Municipal Power’s proposed changes to Manual 14B: Regional Transmission Planning Process, which were seconded by Old Dominion Electric Cooperative at the July 27, 2018, MRC meeting, will be considered the main motion. PJM’s proposed revisions, which were moved by FirstEnergy and seconded by Public Service Electric and Gas at the Dec. 20, 2018, MRC meeting, will be the first alternate motion. (See PJM MRC Briefs: Dec. 20, 2018.)
AMP would add language in section 1.5.4 to require sufficient information for stakeholders to replicate TOs’ results on the need for proposed supplemental projects. It also would strike the word “useful” in references to “end of useful life.”
PJM said its proposal provides additional transparency to the Regional Transmission Expansion Plan process and incorporates most of the AMP/ODEC-proposed changes along with input from TOs.
LS Power has proposed a friendly amendment to either proposal that would limit the ability of supplemental projects — which are developed by TOs based on their own criteria — to supplant competitively bid projects accepted by PJM to address regional reliability violations or other criteria.
The main motion will be voted first. If it fails, the alternate motion will be brought to a vote.
3. Energy Price Formation (10:30-11:30)
Members will be asked to endorse one of four packages of energy market rule changes from the Energy Price Formation Senior Task Force (EPFSTF). The Board of Managers told members last month that it will make a unilateral filing with FERC if members do not reach consensus on a package by Jan. 31.
The rule changes will affect shortage pricing; reserve products; synchronized reserves; secondary reserves; and the alignment of the day-ahead and real-time reserve markets.
PJM’s proposal would replace the current stepped operating reserve demand curve (ORDC) with a sloped curve; the first horizontal segment would represent the minimum reserve requirement, with the downward sloping curve based on the probability of reserves falling below the minimum reserve requirement (PBMRR) in real time based on uncertainties.
The D.C. Office of the People’s Counsel proposed a similar ORDC, except that the downward sloping curve would take into account the regulation requirement.
The Independent Market Monitor’s proposal would leave the ORDC unchanged and reduce the current two-step penalty factor ($850 and $300) with a single penalty factor equaling the safety net energy offer cap of $1,000/MWh. If PJM approves a cost-based offer above that price, the penalty factor could increase in $250/MWh increments to a maximum of $2,000/MWh.
The PJM proposal would increase the price for the initial horizontal segment of the curve to $2,000/MWh and replace the second step of the curve with a downward sloping segment valued at $2,000 times the PBMRR.
Calpine supports the PJM proposal except that it would eliminate PJM’s proposed transitional mechanism to the energy and ancillary services (E&AS) revenue offset. PJM proposed the transition to reflect expected changes in revenues in the determination of the net cost of new entry. (See Monitor Sees Problems with PJM Reserve Pricing Plan.)
Votes at the EPFSTF meeting Wednesday will determine the breadth of support for the proposals and how they will be considered at the MRC.
4. Incremental Capacity Transfer Rights Clarifications (11:30-11:45)
Members will be asked to endorse revisions to section 234.2 of the Tariff to require new service customers to request incremental capacity transfer rights (ICTRs) calculations during the facilities study phase. Customers can include up to three locational deliverability areas in the request.
Section 234.2 requires PJM to determine in the system impact study the increase in capacity emergency transfer limit resulting from an interconnection, merchant transmission facility or customer-funded upgrade.
The change is in response to a FERC order that found PJM had not been following section 234 for assigning ICTRs. PJM had clarified the procedure in Manual 14E, but FERC said it must also be added to the Tariff (EL18-183).
The MRC and MC will also be asked to endorse the changes on their first read so they can be filed with FERC by Jan. 31.
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to approve a revised definition of “on-site generators” in the market participation rules in the Tariff and Operating Agreement. The changes will affect distributed energy resources located behind a customer’s meter participating as demand response to reduce load and as generation to inject power.
The committee will be asked to approve a new mark-to-auction component for financial transmission rights credit requirements, a change prompted by the GreenHat Energy default.
Although a decline in market value can indicate increasing FTR risk, current rules do not provide for a collateral call when an FTR portfolio’s value is deteriorating.
Proposal G-1 would consider the difference between the FTR purchase price and most recent market price. It was endorsed by the MRC by acclamation, with one objection, in December. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)
2. Energy Price Formation (1:40-2:40)
The committee will be asked to approve revisions to the energy and ancillary market rules to improve price formation. (See MRC item 3 above.)
3. Incremental Capacity Transfer Rights Clarifications (2:40-3:00)
Members will be asked to endorse revisions to section 234.2 of the Tariff to require new service customers to request ICTR calculations during the facilities study phase. (See MRC item 4 above.)
4. Opportunity Cost Calculator (3:00-3:30)
The committee will be asked to endorse revisions to Manual 15: Cost Development Guidelines governing generators’ use of the Monitor’s calculator as an alternative method of calculating energy market opportunity costs.
Members also will be asked to approve related revisions to Schedule 2 of the OA. (See “Opportunity Cost Calculator Vote Deferred,” PJM MRC/MC Briefs: Oct. 25, 2018.)
FERC last week refused to budge on its decision to revoke the license of a small hydropower plant in Michigan over the owner’s longstanding noncompliance with safety measures.
The commission on Jan. 17 denied rehearing on Boyce Hydro possibly restarting operations at the 4.8-MW Edenville Dam, which was ordered closed in October over insufficient spillway capacity. (See FERC Upholds Michigan Dam Closure over Safety Fears.)
Edenville Dam spillway
“In multiple orders, the commission has set forth a history, going back to 2004, of Boyce Hydro’s failure to comply with its license for the Edenville project, the commission’s regulations and commission orders. Of particular concern has been the project’s inability to pass the probable maximum flood due to inadequate spillway capacity,” FERC repeated in its latest order on the issue (P-10808-064).
Boyce and the Sanford Lake Association sought rehearing of FERC’s decision to revoke the license, arguing the commission didn’t consider how the revocation could negatively affect a potential transfer of the license. Acquiring a new license, the two said, is an expensive, uncertain and drawn-out process. In addition to the Sanford Lake Association, the Wixom Lake Association and the Saginaw Chippewa Tribe have expressed interest in taking over ownership of the dam.
Boyce said that a new license to replace the 20-year-old license “would require environmental, recreational and other study information required in contemporary licenses.” It pointed out that obtaining a new license could be further complicated by the dam’s inadequate spillway capacity and the fact that the water quality on the original license had been waived.
But FERC wasn’t swayed: “It is not in the public interest for the commission to delay action addressing a licensee’s long history of noncompliance with dam safety regulations out of concern that such action may affect the possibility (based mostly on speculation) that some third party might accept transfer of the license and promptly bring the project into compliance.”
FERC said the process of acquiring a new hydroelectric license can be expedited with certain procedural requirements waived. The commission also said the lake associations’ meetings over the dam are too preliminary in nature to persuade it to change the license revocation into a license suspension, as requested by the Sanford association. The meetings, FERC said, “do not provide any certainty as when the Edenville project’s public safety and environmental deficiencies would be remedied.”
The commission reiterated that Boyce has been on notice that its noncompliance could lead to license revocation since “at least June 2017” and that the company and interested buyers have had “ample opportunity to investigate the option of license transfer.” It added that it received no indication that a third party was ready to assume the project. Further, Boyce never provided the commission with a timetable for increasing spillway capacity when “continuing required work would have been wise,” FERC said.
Boyce and the Sanford Lake Association also argued that the license revocation could negatively impact public safety because, absent income from electricity generation, the spillways won’t be repaired or upgraded. FERC said dam safety enforcement will fall to the Michigan Department of Environmental Quality, which can instigate civil action.
The commission also rebuffed the argument that its order would disrupt a state-mandated lake level, saying nothing in its license revocation is stopping Boyce or a third party from operating the project as a non-generating facility to maintain water levels.
“For over 14 years, the commission has gone to great lengths to compel compliance with the license requirements, and Boyce Hydro has delayed, disregarded its responsibility and claimed that it was not financially capable of meeting such requirements. Meanwhile, Boyce Hydro continued to benefit from the revenues generated by the project,” FERC said. “There is no evidence that allowing Boyce Hydro to maintain its project license will result in a different outcome or that the longstanding compliance issues will be remedied.”
Finally, the commission noted that Boyce failed to put money into escrow to fund necessary spillway improvements, as it promised in 2008. The company also never followed up on a promise to provide FERC with a list of its financial assets.
“A licensee’s lack of financial capacity does not excuse years of noncompliance with important license conditions,” FERC said.
SACRAMENTO, Calif. — CAISO market participants and companies that do business with Pacific Gas and Electric could end up paying a hefty price for the giant utility’s financial collapse.
Other CAISO members are worried that PG&E, which plans to file for bankruptcy on Jan. 29, could default on its payments to the ISO and the Western Energy Imbalance Market, leaving other members to foot the bill.
PG&E’s financial collapse is being managed from its headquarters at 77 Beale St. in San Francisco.
PG&E’s troubles also have fueled talk of a wide-ranging ripple effect, particularly regarding the renewable power generators from which the utility has contracted to buy billions of dollars worth of electricity.
CAISO has tried to relieve members’ concerns about a potential default, saying PG&E has enough collateral to cover its debts and future payments.
“The California ISO has received inquiries relating to the financial status of Pacific Gas and Electric Co. in light of recent media reports,” it said in a Jan. 11 market notice. “The ISO wants to assure market participants that PG&E has posted collateral with the ISO to cover its outstanding and upcoming obligations.”
But one market participant, a major player in the West, told RTO Insider it could end up paying hundreds of thousands of dollars a month to the ISO if PG&E defaults. The representative spoke only on the condition of the utility’s anonymity.
In response to an inquiry from RTO Insider, the ISO said it couldn’t reveal the amount or type of PG&E’s collateral, calling the information confidential. CAISO officials declined an interview request. “We have shared all we can on this subject,” an ISO spokeswoman wrote in an email.
PG&E did not respond to a request for comment.
Scott Miller, executive director of the Western Power Trading Forum (WPTF), said he thought there was little chance PG&E would default on its CAISO payments.
“When it comes to CAISO charges, you’ve got to be concerned,” Miller said. “But because it’s necessary for the grid to operate, and PG&E wants to emerge from bankruptcy as a going concern … I suspect that would be the last thing they wouldn’t pay.
“Defaulting on the CAISO charges could cause all sorts of financial shortfalls in CAISO, and that has reliability implications,” he added. “I just don’t think PG&E would not pay its CAISO charges.”
Scott Miller, executive director of the Western Power Trading Forum, says PG&E is unlikely to default on its CAISO obligations. | WPTF
Miller served until 2017 as a senior market adviser in FERC’s Office of Energy Policy and Innovation where he worked on RTO credit reforms. He said RTOs and ISOs have assumed roles as financial clearinghouses, for which they’re not ideally suited.
It could cast some doubt on whether CAISO can adequately assess PG&E’s creditworthiness, he said.
PJM has been scrambling to strengthen its credit policies following the collapse of GreenHat Energy, whose default is expected to cost members more than $100 million.
“This is an area that’s problematic for RTOs,” Miller said. “They’re extending credit and taking risk. That’s not in their traditional wheelhouse. They’re not in as strong a position as a clearinghouse normally is for assessing credit risk.”
Ripple Effect
PG&E, California’s largest utility, has seen its fortunes fall since the catastrophic wildfires of 2017 and 2018, for which it has received much of the blame. That blame was based on state investigations in some cases, and circumstantial evidence mixed with public distrust in others.
The utility’s stock price plummeted from more than $70/share prior to the 2017 fires in Northern California’s prized wine country to slightly more than $6/share following November’s Camp Fire, the deadliest in state history. The roughly 90% collapse in PG&E’s stock price represented a $33 billion loss in market value.
The utility announced Jan. 14 it would file for bankruptcy by the end of the month because it was facing at least $30 billion in wildfire liability. At least 750 lawsuits have been filed against it on behalf of nearly 5,600 plaintiffs, it said. (See PG&E Files Bankruptcy, as CEO Steps Down.)
On Wednesday, S&P Global Ratings further downgraded PG&E’s credit rating from CC to D status, the lowest grade used by the major ratings firms. The downgrade was based on PG&E missing a $21.6 million interest payment on $800 million in senior notes.
“We do not expect the company to make this payment during the [30-day] grace period given the company’s announcement that it expects to file for bankruptcy protection and commence a reorganization under Chapter 11 of the U.S. Bankruptcy Code,” S&P said in a news release.
The fallout from PG&E’s bankruptcy announcement is already beginning to hit its renewable suppliers.
“PG&E is the biggest utility in the biggest market in the West. It’s not just the RTO activities that people are concerned about,” Miller said. “It’s the bilateral contracts they’ve got for resource adequacy — renewable contracts, storage contracts, things like that.”
One generator, the 550-MW Topaz Solar Farm owned by Berkshire Hathaway Energy, recently had its credit rating downgraded to junk status — the same as PG&E’s — because it had signed an exclusive 25-year power purchase agreement with the utility, and analysts said it might not get paid. (See PG&E’s Credit Woes Spread, Worrying CAISO Members.) Also downgraded was NextEra Energy’s 250-MW Genesis concentrating solar thermal plant, built in 2007. PG&E is its sole purchaser.
PG&E reported to FERC in its 2017 Form 1 filing that it had signed about $40 billion in PPAs covering 2019 to 2043, including agreements to buy approximately $34.5 billion in renewable energy such as wind and solar.
In 2017, PG&E generated about 53% of its 61,397 GWh in bundled retail sales according to a security filing, with purchases making up the remainder. PPAs represented $42 billion of the company’s $78.8 billion in contractual commitments as of the end of 2017.
Once in bankruptcy, PG&E could attempt to cancel or renegotiate these contracts. Analysts say generators with above-market contracts signed years ago will be most vulnerable to having their prices reduced.
Credit Suisse analysts estimate that PG&E could save $2.2 billion a year by renegotiating its renewable contracts to current market prices, The New York Times reported. The analysts said PG&E is paying Consolidated Edison solar plants an average of $197/MWh, almost eight times the $25 to $30/MWh new solar plants are charging.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, said in an interview that his organization will push PG&E to honor its commitments to generators.
IEP sent a letter to California’s political leaders Jan. 15 urging them “to seek immediate assurance from PG&E that its energy-supplier contracts will be affirmed and that generation interconnection deposits supporting new renewable energy projects will be protected and used to develop the transmission upgrades necessary to interconnect those projects.”
Evaluating Exposure
While CAISO has said little publicly about the potential effects of PG&E’s meltdown, conversations are going on behind the scenes as market participants try to sort out their exposure.
The market participant that spoke to RTO Insider on background, for example, said it had been struggling to determine how much collateral PG&E had posted with CAISO and whether other participants would be obligated to pay its share and for how long.
Another concern is the tens of millions of dollars in grid management charges (GMCs) that PG&E pays to CAISO each year, for which other members also could find themselves on the hook. In 2017, PG&E paid $51 million to CAISO in GMCs. Those grid fees fund the ISO’s fixed revenue requirement and any default must be covered by other participants.
Fallout from a PG&E default could spread to the Western EIM as well. Because the EIM falls under CAISO’s Tariff, EIM members have an obligation to cover defaults, similar to other CAISO members, in proportion to their market activity. Their voluntary day-to-day participation in the EIM, however, could allow them to reduce transactions to minimize exposure, and even ultimately withdraw from the market.
CAISO members whose assets are controlled by the ISO have no such recourse. They must cover a defaulter’s payments under the ISO’s tariff provisions once the defaulter has exhausted its collateral or “financial security.”
The ISO’s tariff provisions on creditworthiness require participants without unsecured credit to post collateral in the form of “an irrevocable and unconditional letter of credit issued by a bank or financial institution,” a prepayment to the ISO or a combination of the two. It remains unknown what kind of security PG&E posted.
CAISO requires financial security sufficient to cover a participant’s “estimated aggregate liability,” which represents all unpaid obligations plus five trading days, providing the ISO a cushion before the participant responds to a call for additional collateral within the required two business days. Posted collateral must be sufficient to cover other liabilities as well, such as a congestion revenue rights portfolio that has gone into the red.
In a situation where a market participant defaults on its payments to the ISO and has no collateral left, section 11:29:17 of the CAISO Tariff lays out a process by which the ISO can spread the costs to other members proportionally based on their market activity. Section 29.11 of the Tariff stipulates that those provisions also apply to EIM members.
Another potential consequence of PG&E’s bankruptcy: CAISO’s own financial position could be adversely affected.
In awarding the ISO an A+ credit rating in 2016, Fitch Ratings said one of the key factors it considered was the “solid credit profiles of California’s three largest investor-owned utilities.”
That was before S&P and Moody’s Investors Service stripped PG&E of its investment-grade credit status, downgrading it to “junk” because of its dire financial outlook from the fires and the fact that California politicians weren’t riding to its rescue, as some had expected.
S&P still gave CAISO an A+ credit rating as of Thursday. CAISO’s current annual debt service costs of $16.9 million are well below the 2006 peak of $80 million, and the 2009 construction of the ISO’s Folsom headquarters accounts for most of its $181 million (as of 2017) in long-term debt.
‘Out the Window’
State Assemblyman Chris Holden, chairman of the Utilities and Energy Committee, who co-authored last year’s Senate Bill 901 to aid PG&E, said he wasn’t inclined to do more right away.
SB 901 contained provisions allowing the state’s IOUs to issue long-term bonds, with approval of the California Public Utilities Commission, to cover costs of the 2017 fires. Holden had said he intended to offer legislation to make the bill’s provisions applicable to the Camp Fire and other 2018 fires. A PG&E bankruptcy wouldn’t be good for the state or its ratepayers, he said.
Holden recently backed away from that effort, telling the San Francisco Chronicle, “Our purpose was to keep PG&E from going into bankruptcy, but that’s out the window now. Now the courts are getting out in front.”
CARMEL, Ind. — Staff engaged in MISO’s ongoing market system replacement will this year focus on moving the platform to the cloud and creating a single means of submitting modeling data, stakeholders learned last week.
MISO plans to move its system from a server-based platform to the cloud some time in 2020, IT Senior Director Curtis Reister said during a Jan. 17 Market Subcommittee meeting. The RTO will phase in use of the new system gradually from 2020 to 2024.
“We’re going to do what’s called a private cloud,” Reister said.
He explained that while the cloud platform will function like a public network to staff, equipment to support it will be built solely for MISO and be kept on RTO premises, keeping systems more secure.
The new platform will be designed to accommodate market changes more quickly, Reister said. “With a big monolithic system like today, it is difficult to find the impacts of even a modest change.”
By 2021, the cloud-based platform will also include a “model manager,” a single integrated system for model data submission and validation. MISO currently relies on several different means to collect and process grid information for modeling.
“The model data comes in through a lot of different sources. We’re looking at a much more seamless way to gather and verify that information,” Reister said.
Also by 2021, MISO will launch a new user interface for members to submit market transactions such as bids and offers.
MISO plans to update the current interface early this year to address browser incompatibility, behind the originally scheduled release in late 2018. Members have reported having to rely on old versions of web browsers to use the current interface.
Stakeholders asked for an update on current vendor General Electric’s overall performance on the early stages of the multilevel project.
“We’re currently on schedule with our deliveries with GE,” Reister said in response to stakeholder inquiries about the company’s performance. GE has steadily shown it has the resources and ability to meet the RTO’s demands, he added.
MISO continues to “monitor” news around GE and the company’s performance, Reister said. Last week, at least one financial analyst predicted that GE’s financial performance will begin to rebound.
The RTO has said it will not announce a recommended final platform vendor until the fourth quarter, when it finishes evaluating alternatives. (See “Market Platform Replacement Enters Year 3,” MISO Board of Directors Briefs: Dec. 6, 2018.)
MISO has committed to another stakeholder update of its platform replacement in April.
At Least 1 Market Project Delay
While MISO expects to continue carrying out improvements to its current platform, at least one market upgrade will be placed on hold until the new system is operational.
Implementation of more sophisticated modeling software that can accommodate different combinations of combined cycle units and their dependencies will be postponed until mid-2023, MISO said. The RTO originally planned to have the improvement in place by 2020 but last year announced a delay until 2022. (See MISO Delays Combined Cycle Model Update.)
MISO Executive Director of Market Operations Shawn McFarlane said there are “technical issues in installing it on the legacy system,” explaining that day-ahead market clearing could experience delays if the project were implemented in the current system.
Director of Market System Enhancement Dhiman Chatterjee said market systems would experience a “significant amount of uncertainty” if the RTO implemented combined cycle modeling on the existing platform.
However, MISO’s proposed, short-term reserve product, which will furnish capacity within 30 minutes, will still move ahead as planned, supported by the current market platform. The RTO hopes to roll out the new type of reserve in mid-2021.
MISO last week published a conceptual design of short-term operating reserves in which online and offline resources can either register as a supplier or provide availability through hourly offers in the day-ahead and real-time markets. Resources would clear according to opportunity costs, offer prices and a demand curve when insufficient amounts of the reserves exist. Clearing resources will be paid their respective zonal market clearing prices. The early design doesn’t account for participation by storage resources, but the RTO said later versions will include storage participation “where appropriate.”
MISO said 30-minute operational needs are “not efficiently modeled” in the current market, and that a new reserve product would help better manage its Midwest-South contractual limit on SPP’s transmission, manage constrained load pockets and meet systemwide energy needs even during times of load and supply volatility. The new reserve type would be especially helpful in MISO South, where operators rely on less transparent out-of-market commitments to address the Midwest-South transfer constraint and load pocket needs.
CARMEL, Ind. — MISO last week posted draft 2019/20 Planning Resource Auction data that are virtually unchanged from last year’s early predictions.
The RTO released the data as it prepares for its usual spring resource adequacy activities, including organizing its annual resource adequacy survey.
MISO is currently forecasting a 121.6-GW systemwide coincident peak and 125.3-GW total zonal coincident peak for the planning period. It also estimates an approximate 134.4-GW planning reserve margin requirement and a combined 152.6 GW in local resource requirements. The estimates are subject to change, but they don’t materially stray from last year’s preliminary data reflecting low demand but declining margins. (See MISO RASC Briefs: Little Change to Capacity Forecasts.)
Speaking at a Jan. 16 Resource Adequacy Subcommittee meeting, Tim Bachus, MISO capacity market administration analyst, said he doesn’t expect much change to the data through March, when auction numbers will be finalized.
This year’s auction conduct threshold, calculated as 10% of cost of new entry, ranges from $22 to $25/MW-day depending on zone, Independent Market Monitor staffer Michael Chiasson said.
Late last year, MISO said it would require a 16.8% planning reserve margin requirement for June 2019 to May 2020. At the time, it said it had nearly 154 GW of installed capacity on hand to meet the requirement.
Meanwhile, the RTO will send voluntary surveys to market participants by late March as part of its annual resource adequacy survey with the Organization of MISO States. Completed surveys are due back April 15. Results of OMS-MISO surveys are typically released in June.
“The last decade has seen a lot of changes in our fleet mix … and this survey is an important tool to continue dialogue on the change,” MISO resource adequacy team member Stuart Hansen said of the survey.
The New York Public Service Commission on Thursday ruled that John F. Kennedy International Airport could have a solar project up to 5 MW compensated under the value stack program for distributed energy resources (VDER) while having other solar projects dedicated to serving on-site load (Case 18-E-0766).
The New York Power Authority and the Port Authority of New York and New Jersey filed a petition last month for clarification on the issue of net metering and VDER eligibility for its community distributed generation solar project after Consolidated Edison said its tariff did not allow such compensation where more than 5 MW was located on one site.
The PSC held its regular monthly session in Albany on Jan. 17.
Con Ed’s Jan. 4 response said that while the commission had expanded the capacity limit for eligible projects from 2 MW to 5 MW, it “has not acted, however, to remove the longstanding requirement that all eligible on-site generation be counted toward the size limitation for NEM [net energy metering], and therefore value stack, eligibility.” (See NYPSC Expands VDER Project Size to 5 MW.)
The commission’s original VDER order of March 2017 directed that compensation for eligible DER transition from NEM to the value stack, a methodology that bases compensation on the benefits provided by the resources (Case 15-E-0751).
The commission’s Jan. 17 declaratory ruling said “the rated capacity of projects used solely for serving on-site load and not seeking compensation under the value stack or net metering should not be counted towards the rated capacity limit.”
In response to Con Ed’s concern that the ruling could result in utility-scale generators splitting off 5 MW of a larger project to receive value stack compensation, the commission noted “that such a situation would represent a significantly different fact pattern than the one presented. … This declaratory ruling is intended to address only situations where the non-value-stack generation is used solely for serving on-site load.”
Wholesale Concerns
John B. Rhodes
“I find this ruling to be clear and helpful and a narrow clarification of the intent and of the intended application of our language,” PSC Chairman John B. Rhodes said.
“This is a simple but important interpretation of our 5-MW cap in the value stack compensation process,” Commissioner Gregg Sayre said. “I never intended through my vote on the value stack to exclude a small project from value stack compensation just because a large customer has a bunch of other generation in the same area that won’t ever hit the network.”
Commissioner James Alesi also supported the measure, but Commissioner Diane Burman voted no, saying “one concern is whether this intrudes on the wholesale market that would be going through the NYISO process rather than here.”
Ted Kelly
Ted Kelly, assistant counsel for the Department of Public Service, testified that “the reason that a project like this one or like another project that could be built under this declaratory ruling would not be an inappropriate avoidance of the wholesale market is because the primary project is intended for self supply, and customers always have the option of building generation for self supply, even beyond the 5-MW cap, without having to interconnect or be involved with the wholesale market. They can still be direct customers of a distribution utility while having that large generator for self supply.”
Diane Burman
Asked by Burman what would happen if NYPA and the Port Authority did something that would make it a wholesale market issue, Kelly said they would have to file an interconnection request with Con Ed.
“To the extent that NYPA has had an ongoing focus on increasing its jurisdictional reach, how do you see this item applying to that issue?” Burman said.
“This item is really within NYPA’s core existing jurisdiction in that it’s supporting one of its own customers, as Port Authority is a partial NYPA customer, including partially for its JFK load, supporting one of its own customers building on-site energy management tools, including renewables, energy efficiency and so on,” Kelly said.
Grants NYSERDA Access to Customer Utility Data
In a second ruling, the PSC granted the New York State Energy Research and Development Authority access to the data of customers not participating in NYSERDA programs to help the agency analyze the impact of its clean energy efforts (Case 14-M-0094).
The commission’s order directs NYSERDA and the state’s utilities to develop a memorandum of understanding governing the data exchanges. It also directs the agency to detail its need for customer data; to justify why other data cannot serve that need; to limit sharing of the information; and to ensure that it is not used for financial gain by any third party.
“It’s foundationally important that we ensure that the programs we approve do in fact work. Specifically, this means being able to tell if we’re making a difference, and that requires data,” Rhodes said. “This report assures that data in a way that’s careful and appropriate, which is necessary given that we’re talking about data and therefore about privacy and security.”
“If you can’t measure something, you can’t improve it successfully,” Sayre agreed.
Burman dissented without prejudice for NYSERDA to refile.
The order gives wide latitude to the agency without direct commission oversight “and that concerns me,” Burman said. “And it’s also being done without — in this case — without any external consumer advocates or other stakeholders having weighed in except for CPA [Consumer Power Advocates],” a group that represents hospitals, universities, medical schools and cultural institutions in New York.
“Frankly I think it is incumbent on anyone who’s submitting a petition that directly touches upon consumers … to make sure that there is direct outreach to consumer advocates or others who may be affected,” Burman said. “I would have liked to see in the petition the actual studies expected to be done. That would give us and other stakeholders more information on exactly what is planned. It’s a three-year plan and … we’d like to know what to expect.”
The commission also denied a request by New York City for unrestricted access to customer usage and other utility data.
“This sort of broad, nonspecific request is inconsistent with commission precedent,” the order said.
The commission noted that its December 2018 order adopting accelerated energy-efficiency targets opened a “comprehensive proceeding to assess the strategic use of customer energy usage data,” and invited the city and other interested governmental entities to participate in that proceeding (Case 18-M-0084). (See NYPSC Expands Storage, Energy Efficiency Programs.)
The named utilities in Thursday’s order are Con Ed; Orange and Rockland Utilities; Central Hudson Gas & Electric; National Grid gas distributors National Fuel Gas Distribution, Brooklyn Union Gas and KeySpan Gas East; Niagara Mohawk Power; New York State Electric and Gas; and Rochester Gas & Electric.
The commission also granted NYSERDA’s requests for relief from certain reporting requirements related to System Benefits Charge III and IV programs (Cases 05-M-0090; 10-M-0457). The SBC provides funding for NYSERDA programs targeting energy efficiency, research and development, and the low-income sector.
The indefinite mothballing of a 470-MW coal-fired plant has reduced ERCOT’s “pretty scary” reserve margin of 8.1% to 7.4%, prodding the Texas Public Utility Commission into ordering several market changes.
The PUC on Thursday directed ERCOT to tweak its operating reserve demand curve (ORDC), which provides a price adder during periods of generation scarcity, and to proceed with implementing real-time co-optimization.
“I was already concerned, and with [this plant] coming out, it’s heightened my concerns,” said PUC Chair DeAnn Walker, whose “pretty scary” comment has been making the rounds in the trade press. She made the comment following the December release of ERCOT’s last capacity, demand and reserves (CDR) report, which revealed the 8.1% reserve margin. (See ERCOT Predicts Tight Reserve Margin for 2019.)
Shortly before the open meeting began, ERCOT announced it had completed a reliability analysis and determined that the city of Garland’s Gibbons Creek Generating Station was not required to support system reliability. That clears the way for the city to indefinitely suspend the plant’s operations, effective June 1.
ERCOT representatives assured the PUC that it can meet demand with the new historically low reserve margin by following its emergency operations procedure. That would entail procuring emergency response service, voltage-reduction measures and releasing reserves.
“There’s some talk that 7.4% is not that big of a deal,” Walker said. “I believe you can absolutely run this system in a reliable manner, but when you hear 7.4%, does that give you a lot of comfort?”
“At that reserve margin level, it’s likely that we will have to take advantage of those additional resources,” replied Dan Woodfin, ERCOT’s senior director of system operations. “We will likely have to do that on a number of occasions this summer, but there’s not an indication at this point in time that we will have to implement rotating outages.”
Woodfin did not discount the use of rotating outages in the case of extreme weather, low wind output or forced generation outages.
“Again, I have full confidence in ERCOT managing and running our system, and if we have a large unit trip this summer on the hottest day of the year, I think we can manage this,” Walker said. “But I also believe there are things this commission can do.”
ERCOT’s Dan Woodfin (left) and Warren Lasher address the Texas PUC.
In a memo filed shortly before the PUC’s open meeting began, Walker suggested making a 0.25 standard deviation shift in the loss-of-load probability calculation and using a single blended ORDC curve as soon as practicable. She suggested a second shift of 0.25 in the standard deviation next year.
Both Sides
The change would lead to the ORDC’s more frequent use, and at higher levels.
Walker said the blended ORDC would also increase the development of demand response, distributed generation and self-generation, and could lead to delays in pending retirements and other units returning to service much more quickly.
Writing that real-time co-optimization would bring economic and operational benefits to the market, Walker also proposed that PUC staff bring back to the commission’s Feb. 7 meeting a list of policy issues for stakeholder comment and asked that ERCOT provide a high-level implementation plan and timeline.
Walker said including marginal losses in the security-constrained economic dispatch is not “worth the implementation cost and market disruption.”
Commissioners Arthur D’Andrea and Shelly Botkin agreed with Walker’s proposals, though Botkin said she was not prepared to take the second step with the ORDC just yet.
ERCOT staff told the commission they could take the ORDC change to the grid operator’s Technical Advisory Committee on Jan. 30 and to the Board of Directors on Feb. 12. That would enable ERCOT to implement the revised ORDC by April.
“I think there are a lot of good arguments on both sides,” D’Andrea said. “I think all of us agree we’re going to stay committed to market principles and let our energy-only market work. I think acting now is prudent.”
| Tom Harpool Collection, University of North Texas Special Collections
Vistra Energy released a statement in support of the actions, saying “proper price signals must be sent to incentivize investment in maintaining the existing generation facilities and developing new, more efficient technology” as the Texas market evolves from older, less-efficient technology.
In performing its transmission reliability assessment of Gibbons Creek, ERCOT said “the tools under its emergency procedures are adequate in maintaining grid reliability.”
Garland Power & Light in December submitted a notification of suspension of operations for the 35-year-old unit, which is operated by the Texas Municipal Power Agency. It had been operating seasonally since 2017 and returned to mothballed status in October.
WASHINGTON — FERC devoted most of its monthly open meeting Thursday to honoring recently deceased Commissioner Kevin McIntyre, with Chairman Neil Chatterjee delivering a lengthy, emotional eulogy that drew tears from some staff members in the audience.
Chatterjee went beyond merely praising McIntyre’s character and work at the commission. Instead, for about half the commission’s 50-minute meeting, he recalled, sometimes with a shaky voice, how he and McIntyre bonded during their time on the commission together, forming a brotherly relationship.
The chairman said that in the weeks since McIntyre’s Jan. 2 death, many people have related to him that McIntyre told them that “he loved me like a brother.”
“And that’s classic Kevin, that he would never have said those words to me directly, because he didn’t like to emote like that. He would have said something to the effect of, ‘I love you like my much shorter brother. I love you like my dark-haired brother.’
“But I’ve heard it from enough people that even though I didn’t hear it directly, I know he meant it, and I love my brother. And I am going to work with my colleagues to ensure that we execute on the legacy that he put into motion, not just for him and in his memory, but because he was an earnest public servant that genuinely wanted to do the right thing.”
McIntyre, 58, died after an 18-month battle with brain cancer. Sworn in as chair in December 2017, he relinquished the position to Chatterjee on Oct. 24 last year as his health deteriorated. (See FERC’s McIntyre Loses Cancer Battle.)
Chatterjee, who had previously served as chair for four months before McIntyre’s arrival, told of how he had felt overwhelmed by all the issues before the commission and reached out to McIntyre for advice.
According to Chatterjee, McIntyre told him over dinner, “‘Neil, I’m just a Jones Day lawyer. You are the chairman of FERC. These are your decisions to make, and it is incumbent upon you to lead. … Whatever decisions you and your colleagues make, I will work to push them forward. … Just do what you think is right; put country over party and the public good over politics, and you’ll be just fine.’”
About a month after McIntyre joined, FERC unanimously rejected the Department of Energy’s Notice of Proposed Rulemaking for the commission to order RTOs and ISOs to compensate the full operating costs of generators with 90 days of on-site fuel (RM18-1).
Collegial, Nonpartisan
Chatterjee, a former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), has been candid about how McIntyre helped him grow professionally from being a partisan aide to independent regulator. He has said that he was initially sympathetic to the NOPR because of the aid it would provide to coal country, including his home state of Kentucky. (See Returning Chair Pledges to Protect FERC’s Independence.) As chair, he pushed for a short-term plan to rescue as many plants as possible while the commission did additional fact-finding.
At another dinner between the two after the commission’s Jan. 8, 2018, ruling, McIntyre praised Chatterjee for his leadership during his tenure as chair on the issue.
Chatterjee said he was incredulous. “I said, ‘Kevin, that’s ridiculous. I’m self-aware enough to know that I made a number of mistakes. I threw up all over myself throughout this and botched this at myriad points.’ And he said, ‘Stop. No, you did not. You were confronted with a difficult situation. The secretary of energy asked us a very complex and important question. You tried to do the right thing.’ …
“He didn’t need to do that,” Chatterjee continued. But “that is the mark of a strong leader: someone who recognized that his colleague was feeling down and went and bucked me up and said, ‘Hold your head up high, and let’s continue to move forward together.’”
The two further bonded attending Georgetown Hoyas and Washington Nationals games, and over promoting awareness of Down syndrome, which McIntyre’s youngest child has.
Chatterjee also recalled how McIntyre’s wife, Jennifer, called him the day he was promoted back to the chair. According to Chatterjee, she said, “‘I know you hate this. I know you didn’t want this, and you are wracked with guilt. Stop it. The only thing of happiness that Kevin is taking from this difficult situation is the knowledge that his friend is going to have this opportunity. … Don’t go moping around; don’t hang your head; don’t feel sorry for yourself and for us. You need to man up and lead.’”
Commissioners Cheryl LaFleur and Richard Glick also praised McIntyre, echoing Chatterjee’s remarks about his dedication to nonpartisanship and collegiality.
“Sometimes it seems kind of rote to suggest that we should take heart in an experience such as this and vow to be better people,” Glick said. “But I think we would do well to take a page from Kevin’s book and focus every day on upholding the commission’s collegial, nonpartisan tradition. The coverage in the press sometimes seems to focus on the horse-race aspect of what we do: what commissioners are voting, how we are voting, or whether there’s an ‘R’ or ‘D’ next to our name. In my opinion, that’s not an accurate picture of how the commission functioned under Kevin, or how it functions today.”
On the morning after McIntyre’s death, “there was a sharp pang of loss and that hollow feeling all around the building and in everyone you talked to,” LaFleur said, “because it was the feeling that our best and our brightest had been taken away from us.” She said she appreciated McIntyre’s legal judgment, commitment to the rule of law and his concern for FERC even while he struggled with his health. She also “loved his vocabulary. He always used his unique words that properly summed up whatever he wanted to say.”
Chatterjee concluded his speech by announcing that FERC’s main meeting room would be named in McIntyre’s honor, with details of the dedication to be announced on a later date.
