Page 1191 – RTO Insider

October 2, 2019

Creditor Group Joins Call to End PG&E ‘Exclusivity’

By Robert Mullin

A notable group of claimants has added its voice to the growing chorus of parties asking a federal judge to end Pacific Gas and Electric’s exclusive right to offer a plan for emerging from bankruptcy.

On Tuesday, the Official Committee of Unsecured Creditors of PG&E filed in support of a motion urging the U.S. Bankruptcy Court in San Francisco to terminate PG&E’s so-called “exclusivity period” and open the utility’s Chapter 11 proceeding to alternative plans.

“Competing plans proposed by diverse stakeholders have created strong positive momentum, which is vital for a successful resolution of PG&E’s bankruptcy cases,” the Official Committee of Unsecured Creditors of PG&E said in a statement accompanying its filing supporting the motion. “Ending the exclusivity period would foster competition among plans and will generate improvements in both plans.”

PG&E headquarters in San Francisco | © *RTO Insider*

The committee was appointed by the bankruptcy court to represent the interests of organizations with unsecured credit claims against the utility and its parent company, PG&E Corp. Its members include the International Brotherhood of Electrical Workers, Pension Benefit Guaranty Corporation, NextEra Energy, Deutsche Bank, Davey Tree and others.

PG&E last month asked Judge Dennis Montali to extend its window of exclusivity from late November to late January, arguing it has made a good-faith effort to resolve one of the biggest bankruptcies in U.S. history.

In its current — and incomplete — form, PG&E’s reorganization plan proposes using $14 billion in new equity financing to pay off wildfire claims and emerge from bankruptcy by June, in time to take advantage of a new $21 billion wildfire recovery fund established by the California State Legislature. The plan would provide a capped trust of $8.4 billion for fire victims in addition to the $11 billion for subrogation claims.

The motion to end exclusivity was submitted by an “ad hoc group” (AHG) of bondholders who hold about $10 billion in unsecured PG&E debt. They’ve proposed a competing reorganization plan that would provide them control over the utility, injecting more than $30 billion in liquidity, including about $18.4 billion for fire victims. (See Judge Weighs Compe t ing PG&E Bankruptcy Plans.) That plan has been endorsed by the Tort Claimants Committee (TCC), the court-appointed group representing victims of wildfires sparked by PG&E equipment.

While the unsecured creditor group stopped short of outright endorsement of the bondholder proposal, it did laud the plan and call it “a significant step forward.”

“For the first time, a plan is being proposed that pays all unsecured claims, including wildfire claims, in full, is supported by the TCC, a fiduciary for all wildfire claimants, and is backed by evidence of substantial committed financing,” the creditor committee said in its filing.

It also noted the bondholder plan is not conditioned on “a lengthy and uncertain estimation process” or a trial over claims related to the 2017 Tubbs Fire in California’s wine country, which Montali in August determined should be decided in state court, likely complicating and prolonging the outcome of PG&E’s bankruptcy.

The creditors had little favorable to say about PG&E’s own plan, noting its approach stands in “stark contrast” to that of the bondholders.

“In its October rulings on exclusivity, lifting of the automatic stay with respect to the Tubbs Fire trial and setting in motion the process going forward for estimation, the [bankruptcy court] made crystal clear its view that resolution of the wildfire claims and payment of the individual victims is the Court’s paramount objective in these cases,” the creditor committee wrote. “The ad hoc group and the TCC took that guidance to heart, got in a room and reached a fair and reasonable agreement that stands to benefit all creditors. The debtors, on the other hand, chose instead to focus their efforts on a bilateral settlement with a single group of institutional creditors.

October 2, 2019

South Carolina Power Cooperative Joins PJM

By Christen Smith

As South Carolina lawmakers field offers for state-run utility Santee Cooper, its largest customer quietly joined PJM last month.

Central Electric Power Cooperative became a voting member of PJM on Sept. 5 as part of the “other suppliers” sector. Jeff Shields, a PJM spokesperson, said Tuesday the new addition doesn’t include transmission system integration and doesn’t expand the RTO’s 13-state footprint — a somewhat common occurrence among its 1,000-plus members.

“Just like Central Electric Cooperative, they [other individual companies] find benefit from membership without integration of service territory,” he said.

The Columbia-based co-op owns 800 miles of transmission lines across all 46 counties, making it the largest customer of Santee Cooper, the state-run utility company that provides electricity and water to more than 2 million residents statewide.

Central Electric provides wholesale electric service to all 20 of the state’s cooperatives and has a peak demand of about 4,500 MW. The co-op owns community solar and peaking generation but obtains most of its energy through long-term power purchase agreements with Santee Cooper, Duke Energy Carolinas and the Southeastern Power Administration.

The PJM membership will become official once the company receives approval from the U.S. Department of Agriculture’s Rural Utilities Service, expected sometime in November.

“Our relationship with PJM is new, but there’s nothing new about our long-term planning,” said Robert Hochstetler, Central’s CEO. “As we plan, we consider least-cost, reliability and diversification of our portfolio, and their geographic footprint and generating capacity offer benefits other than power supply for Central.”

The cooperative said PJM membership will allow it to request feasibility studies of importing electricity generating capacity and energy from the RTO’s power pool. In its market participant category of membership, however, “Central’s interest will be purely contractual, not operational, in nature.”

“We don’t intend to commit resources into PJM, meaning we won’t be integrating our transmission system with theirs,” said Hochstetler. “We only intend to determine whether purchasing from PJM represents low-cost, risk-adjusted power supply.”

Central said it’s currently in discussions with Duke about its contract, set to expire in 2030. Its Santee Cooper agreement could last until 2058, though the company expects more conversations with other suppliers as it diversifies its portfolio.

Santee Cooper has been under increasing scrutiny after a $10 billion plan to expand the V.C. Summer nuclear plant near Jenkinsville unexpectedly fell apart in July 2017, leaving ratepayers on the hook for $4 billion racked up in construction costs before the utility and its privately run partner, SCANA, pulled the plug. Federal investigators are now trying to determine how soon the utilities knew of the impending doom and whether key information was hidden from lawmakers and regulators who could have intervened.

In March, the state legislature — long pressured by Gov. Henry McMaster — announced a plan to sell Santee Cooper in 2020 to erase the construction debt and spare customers from four decades of rate hikes. Lawmakers have also expressed support for studying RTOs and whether such a system could work well in South Carolina.

As for SCANA, Dominion Energy finalized a merger with the troubled company in January that included a $2 billion plan to freeze customer rates after mounting hikes in the wake of the abandoned nuclear project.

“Putting into effect bills below the temporary rates and keeping residential, commercial and industrial electric bills lower and competitive with neighboring states will aid South Carolina in its economic development efforts and ensure the state has a reliable energy supply to fuel growth and power the state’s homes and businesses,” Dominion CEO Tom Farrell said at the time.

October 1, 2019March 22, 2024

FERC General Counsel Tapped for Commission

President Trump on Monday announced he will nominate FERC General Counsel James Danly to fill the Republican vacancy left by the death of Kevin McIntyre.

The commission was reduced to three members — Chairman Neil Chatterjee and Commissioners Richard Glick and Bernard McNamee — after the departure of Commissioner Cheryl LaFleur in August.

That has left the commission without a quorum in some cases as Glick, the lone Democrat, has been recusing himself from votes involving his former employer, Avangrid. (See related story, FCA 13 Results Stand Without FERC Quorum.)

Danly, formerly a member of the energy regulation and litigation group at Skadden, Arps, Slate, Meagher & Flom, was tapped to serve as general counsel in September 2017, a month after Chatterjee was named chairman.

Danly earned his J.D. at Vanderbilt University Law School in 2013 and a bachelor’s from Yale University, where he studied classics and English.

After law school, he clerked for Judge Danny Boggs of the 6th U.S. Circuit Court of Appeals.

He was a managing director of the Institute for the Study of War, a military think tank in D.C., and served an International Affairs Fellowship at the Council on Foreign Relations.

A former U.S. Army officer, he served two deployments to Iraq and received a Bronze Star and Purple Heart.

During his first tour, with an infantry company in the Dora district of Baghdad, he authored and executed Operation Clos e Encounters, a tactical counterinsurgency program during the troop surge of 2007, according to a biography he provided to the Council on Foreign Relations.

In his second tour, he served under General David Petraeus at Multi-National Force – Iraq.

If confirmed, Danly’s term would end June 30, 2023.

In a profile in June, E&E News reported that Danly espouses a legal philosophy he calls the “humble regulator” — that FERC should work under a very narrow reading of the Federal Power Act and Natural Gas Act rather than using the agency’s discretion to interpret the statutes.

E&E said Danly’s philosophy was influenced by the conservative Federalist Society, which has served as a clearing house for many of Trump’s judicial appointments.

September 30, 2019

PJM MRC/MC Briefs: Sept. 26, 2019

CEO Search Continues

VALLEY FORGE, Pa. — Neil Smith, chairman of PJM’s search committee and a member of its Board of Managers, told the Markets and Reliability Committee on Thursday that he anticipates former CEO Andy Ott’s position will be filled by the end of fall.

“We are focused on speed but not at expense of quality,” he said. “When we can share, we will.”

Ott retired June 30 and board member Susan J. Riley stepped into his role temporarily while the organization searched for a replacement. (See PJM CEO Andy Ott to Retire.)

PJM’s Markets and Reliability Committee and Members Committee met Sept. 26 in Valley Forge, Pa. | © *RTO Insider*

Non-retail BTM Generation Rules Endorsed

Stakeholders unanimously endorsed revisions to Manuals 13 and 14D to clarify the reporting, netting and operational requirements of non-retail behind-the-meter generation (NRBTMG). In Manual 13, maximum generation emergency actions and deploy-all-resource actions are identified as triggers to load NRBTMG.

The endorsement follows a one-month deferral requested by Exelon in order to review applying the rules to community solar programs and aggregate net energy metering. Both PJM and Exelon told the Operating Committee on Sept. 10 that compromise language was close to being finalized, which excluded both types from reporting requirements. (See “Non-retail BTM Generation Update,” PJM OC Briefs: Sept. 10, 2019.)

PJM’s Terry Esterly said Thursday that staff added the revisions to Manual 14 Appendix D and Manual 28.

Stakeholders Urge Consensus on Load Management Testing Requirements

Stakeholders urged PJM and Enel X to reach a compromise on their dueling proposals to update load management testing requirements before a scheduled vote at the October MRC meeting.

“I would encourage both parties to find common ground and present one proposal,” said Adrien Ford of Old Dominion Electric Cooperative. “I think there’s been a lot of progress, and I’m just hoping we can see just a little more movement.”

The key differences between the two packages, endorsed at the Market Implementation Committee on Sept. 10, involve how much advance notice PJM provides to demand response resources before a test and procedures for retesting. (See PJM Stakeholders Support More Realistic DR Testing.) PJM wants testing procedures to more closely mimic reality and proposes a three-step notification system that gives resources first notice on the 21st of the month before, with additional alerts the day before and the morning before. Resources that fail would request a PJM-scheduled retest.

Enel X contends the month-ahead notification provides little useful information to resource owners who operate on a week-ahead timeline. It’s also uncertain how PJM will manage retests when new rules would test resources seasonally — an ambiguity the Enel X proposal attempts to clear up.

PJM — Brian Kauffman, Enel X | © *RTO Insider*

“If you want to do a retest, how will you have time in a season to do a retest?” said Brian Kauffman of Enel X. “Since that could really determine the compensation for resources in a year, it’s really important.”

Susan Bruce, of the PJM Industrial Customer Coalition, said the RTO’s proposal reads like a “gotcha test” to the companies she represents.

“We are not in a position to support PJM’s package,” she said, noting that consensus can still be reached. “I’m not looking to change testing for generators, but I note that there is an open-book test for generators, and there are many low-capacity-factor generators that similarly might not be operating a lot given our very healthy reserve margins.”

Pete Langbein, PJM’s manager of demand response operations, assured Bruce and others that that wasn’t staff’s intention.

“The idea was not to have a gotcha test,” he said. “We heard folks loud and clear, and what you have before you is dramatically different from what we started with. We agree it’s not fair” to test without advance notice.

Independent Market Monitor Joe Bowring said PJM’s package isn’t rigorous enough.

“It’s important to remember that demand response plays a critical role in PJM and a significant role in capacity markets. The PJM proposal is a very modest improvement, and of course you’d rather not have it because it imposes costs.

“While I appreciate your concerns, PJM’s proposal is at the extreme end of modes and should be a very basic requirement for ensuring that demand response is actually there when we need it,” he added.

If PJM and Enel X are unable to reach a compromise, the RTO’s package will be considered first by the MRC. Enel X’s proposal would only come to a vote if the PJM package fails to win approval.

Reserve Requirement Study Preliminary Results

PJM said preliminary results for its 2019 reserve requirement study lowered both the installed reserve margin (IRM) and forecast pool requirement (FPR), which will reset key parameters for the RTO’s upcoming capacity auctions.

Patricio Rocha Garrido, of PJM’s resource adequacy planning department, said the 2019 capacity model, the 2019 load model and the 2019 capacity benefit of ties (CBOT) drove the nearly 1% decrease in IRM, though the capacity model didn’t impact the lowered FPR.

The final report will be distributed Oct. 8 and include recommended IRM and FPR for delivery years 2020/21 through 2023/24.

Manual 34 Changes

The MRC and Members Committee also approved by acclimation changes to Manual 34: PJM Stakeholder Process addressing the prioritization of issues and creating an alternative path for critical, time-sensitive issues. The changes are also intended to ensure transparency throughout the process. (See New Rules to Give PJM Members More Time on Issues.)

The MRC also endorsed changes to the following manuals:

Manual 11: Energy & Ancillary Services. The revisions document the procedure for addressing missing historical performance scores in the regulation market and clarify that the reserve requirements used in the market clearing process are based on the largest single contingencies that are communicated by PJM Operations and modeled in the markets clearing software.
Manual 15: Cost Development Guidelines. To comply with FERC Order 841, changes were made to language on hydro resources and flywheels. Definitions were added for efficiency factor, fuel cost, variable operations and maintenance (VOM) and ancillary service costs. It was also approved by the Members Committee.
Manual 27: Open Access Transmission Tariff Accounting and Manual 28: Operating Agreement Accounting. The changes, required to comply with FERC Order 841, detail PJM settlement procedures for “charging energy,” which is purchased by energy storage resources for later resale. Charging energy is always billed at the applicable LMP, but different categories of charging energy are subject to different sets of charges. They include “direct charging energy” — power purchased by a storage resource from the PJM energy market for later resales to the market or is lost to conversion inefficiencies — and “load-serving charging energy,” which is purchased from the energy market and stored for later resale to end-use load.

– Christen Smith

September 30, 2019

ISO-NE IDs $8.7M Tx Fix for Boston Area

By Rich Heidorn Jr.

ISO-NE has identified a 160-MVAR reactor at National Grid’s Golden Hills 345-kV substation in Saugus, Mass., as a key part of its solution to Boston’s 2028 needs, the RTO’s Kaushal Kumar told the Planning Advisory Committee on Thursday. The reactor, at an estimated cost of $5.47 million, is intended to correct high-voltage violations found at minimum load levels.

Kumar, a senior transmission planning engineer, said the solution was chosen from four 115-kV and 345-kV alternatives in the RTO’s final review. All the finalists also require the installation of a 115-kV breaker in series with breaker 4 at Exelon’s Mystic generating plant to eliminate a breaker failure contingency, a project estimated at $3.25 million.

ISO-NE transmission planning includes the Mystic Generating Station — Mystic Generating Station

Together, the two solutions are estimated at $8.72 million (+50%/-25%).

Kumar said the cost estimate and expected in-service date were the most important factors in the RTO’s selection.

The winning project was the cheapest among the options that could be in service in 2021.

Because it is time-sensitive, it will be installed by National Grid. A need is considered time-sensitive — and excluded from competitive bidding — if the improvements are required within three years of a completed needs assessment.

ISO-NE transmission planning — ISO-NE selected a 160-MVAR reactor at the Golden Hills 345-kV substation as the cheapest solution to correct high-voltage violations expected at minimum load levels in the Boston area in 2028. | *ISO-NE*

Needs Update Reduces Thermal Violations

The RTO also briefed the PAC on its updated study of non-time-sensitive needs in the Boston study area, which will be the subject of a request for proposals in the fourth quarter. The update incorporates the Golden Hills reactor and system changes since the finalization of the Boston 2028 Needs Assessment in June.

The update made several changes to resource assumptions:

The New England Clean Energy Connect (NECEC) and Revolution Wind offshore wind projects were added to the model after providing approved contracts to the RTO. NECEC, a transmission line that would deliver Canadian hydropower to New England, was modeled as a 1,090-MW injection at the Larrabee Road 345-kV substation in Maine. Revolution Wind was modeled as a 120-MW injection at the Davisville 115-kV line in Rhode Island. Both were modeled at 20% of their nameplate capacity.
Resources that filed retirement and permanent delist bids for Forward Capacity Auction 14 were removed from dispatch assumptions.
The model uses FCA 13 active demand capacity resources (ADCRs), updated from FCA 12.
Resources outside Boston that filed retirement and permanent delist bids for FCA 13 have been removed from dispatch.
An “asset condition” project to refurbish the 110-510/511 cables in downtown Boston was added.

The needs assessment posted on June 10 identified one N-1 and six N-1-1 thermal violations under peak loads, all considered non-time-sensitive needs. The updated analysis eliminated three N-1-1 thermal violations: on the Woburn-Wakefield Junction 345-kV and Stoughton-to-K Street 345-kV circuits 1 and 2.

Four other thermal violations identified in the June 2019 Needs Assessment remain:

N-1 Thermal Overload: W. Amesbury–King St. 115-kV line;
N-1-1 Thermal Overload: circuits 1 and 2 of the Woburn-North Cambridge 345-kV lines; and
N-1-1 Thermal Overload: North Cambridge–Mystic 345-kV cable.

Mystic Reactor

ISO-NE’s Pradip Vijayan updated the PAC on revisions to the requirements for a 300-MVAR dynamic reactive device needed for system operations after the retirement of Mystic Units 8 and 9. Exelon announced last year that it would retire Mystic in 2022, but FERC approved a cost-of-service agreement between the company and ISO-NE to keep Units 8 and 9 operating through May 2024.

Since the Aug. 8 PAC meeting, RTO staff reduced the device’s requirement to provide full leading capability at 1.05 per unit voltage at the point of interconnection (POI), down from the original 1.1. The requirement to provide full lagging capability at 0.9 per unit voltage is unchanged.

Staff also amended some of the reactive power requirements for clarity, saying the device must provide continuous voltage control at the POI and must not stay in standby mode (providing no reactive power) under normal operating conditions.

The reactor is considered non-time-sensitive.

The RTO plans to finalize the Boston 2028 Solutions Study next month. Stakeholder feedback on the selection and the study report, which was posted Sept. 24, are due on Oct. 9. Comments should be sent to pacmatters@iso-ne.com.

“You can look for an RFP [on the non-time-sensitive needs] in December,” said the RTO’s Eva Mailhot. “That’s our Christmas present to you guys,” she joked.

Eastern Connecticut 2029 Needs Assessment

ISO-NE’s Jon Breard provided an update on the Eastern Connecticut (ECT) 2029 Needs Assessment, which was suspended in February because changes in the 2019 draft capacity, energy, loads and transmission (CELT) forecast indicated the net load figures in the ECT 2027 assessment were too high. The 2019 CELT shows changes in load, energy efficiency and solar PV from the 2017 CELT.

The revised ECT needs assessment considers future load forecasts, resource changes based on FCA 13 results, coordination with proposed Southeastern Massachusetts and Rhode Island (SEMA/RI) projects, and NERC, ISO-NE and Northeast Power Coordinating Council (NPCC) reliability standards.

Also included were NECEC and the Vineyard Wind and Revolution offshore wind farms.

ISO-NE transmission fix — Eastern Connecticut study area | *ISO-NE*

The CELT 2029 90/10 summer peak load forecast is 32,468 MW, an increase of 1,663 MW over the 2022 forecast. However, net load excluding station service decreased by 100 MW because of increased forecasts for energy efficiency and PV production.

The report concludes that non-transmission options were not able to correct the reliability violations in ECT.

All needs are time sensitive and located on the systems of Eversource Energy, National Grid and Connecticut Municipal Electric Energy Cooperative, the RTO said.

The RTO plans to post the draft ECT needs assessment next month, with the final report expected to be posted in the fourth quarter.

The study found no N-0 violations in ECT or neighboring areas and one N-1 low-voltage violation and no N-1 thermal violations in the ECT area. Steady-state peak load results identified seven N-1-1 violations.

The RTO plans to post the final needs assessment report in the fourth quarter.

Transmission Planning Technical Guide Short-circuit Requirements

The RTO’s Faheem Ibrahim briefed the committee on proposed assumptions for conducting short-circuit analyses using an ASPEN OneLiner.

Such analyses are used in generator interconnection studies, system impact studies, needs assessments, solution studies, and NERC and NPCC compliance studies.

Ibrahim said having a single set of study conditions and solution parameters in the Transmission Planning Technical Guide will ensure consistency across the different studies.

Comments on the revised guide are due to pacmatters@iso-ne.com by Tuesday.

September 30, 2019

CPUC Adds RAMP Costs to Rate Case for 1st Time

By Hudson Sangree

The California Public Utilities Commission authorized costs for a new safety program as part of a utility’s general rate case (GRC) for the first time Thursday, when it approved rate increases for San Diego Gas & Electric and Southern California Gas.

The unanimous approval of the utilities’ three-year general rate case included costs associated with the CPUC’s Risk Assessment Mitigation Phase (RAMP) program.

The “applicants are the first utilities to incorporate RAMP into their GRC filings, and these costs are being included in [their] respective revenue requirements for the first time in [test year] 2019,” the CPUC said in its decision.

Both companies are owned by Sempra Energy.

The RAMP program is part of the CPUC’s efforts to address disasters caused by the state’s three big investor-owned utilities, such as the San Bruno gas pipeline explosion and recent wildfires. The program, and the related Safety Model Assessment Proceeding (S-MAP), require the IOUs to examine the risks they face and propose strategies to mitigate those risks, which the CPUC must then approve.

CPUC RAMP — Part of the rate hike approved for San Diego Gas & Electric Thursday was for fire safety measures. | *SDG&E*

The utilities’ RAMP reports would eventually be integrated into their GRCs every three years, the CPUC decided. The SDG&E/SoCal Gas rate case was the first time that happened.

“The SDG&E and SoCalGas RAMP proceeding is an opportunity for large California investor-owned utilities to describe their proposed mitigations for safety risks associated with the operation of their assets,” the CPUC said on its website.

For SDG&E and SoCalGas, the rate-case decision filled nearly 800 pages, following a two-year review in which 20 parties intervened and 500 exhibits were entered into evidence, said Liane Randolph, the commissioner assigned to the rate case.

The result included a $1.99 billion revenue requirement for SDG&E’s combined operations and $2.77 billion for SoCalGas in 2019, with adjustments allowed in 2020 and 2021. A typical residential customer will see an increase of $1.01/month (0.7%) for electric service and $4.50 to $5 (about 14%) a month for gas service, Randolph said.

“However, a large part of the increases represents costs for incremental safety-related programs and activities that are being added to the GRC for the first time as a result of the … RAMP process,” Randolph told her colleagues at Thursday’s meeting. “The RAMP process requires SDG&E and SoCalGas to identify key safety risks and to propose programs that mitigate those risks.”

Programs being approved address wildfires caused by utility equipment and catastrophic damage from pipeline failures. Among SDG&E’s programs are 3D imaging that lets the utility assess the risk of pole failure because of winds and third-party attachments to poles, Randolph said. A gas leak survey process that uses electronic mapping is another example, she said.

RAMP costs are part of the PG&E’s next rate case, which the CPUC plans to decide in early 2020.

September 30, 2019March 13, 2025

Chatterjee Coal Country Forum to Consider ‘Energy Transition’

By Michael Brooks

FERC Chairman Neil Chatterjee on Thursday released an ambitious, star-studded agenda for the commission’s energy conference to be held Oct. 21 at the University of Kentucky in Lexington.

Dubbed the EnVision Forum, the daylong conference will feature 12 panels, three at a time, with some moderated by former FERC Commissioners Colette Honorable and Robert Powelson.

Panels will include “Transforming Transmission: Investing Today in Tomorrow’s Grid,” featuring former Commissioners Jon Wellinghoff and Phil Moeller, and “Emerging Issues in Organized Electricity Markets,” with ISO-NE CEO Gordon van Welie, MISO CEO John Bear and interim PJM CEO Susan Riley.

Giving keynote addresses will be Murray Energy CEO Robert Murray, American Electric Power CEO Nick Akins, Energy Storage Association CEO Kelly Speakes-Backman and Deputy Energy Secretary Dan Brouillette.

“Launching the EnVision Forum in my home state of Kentucky, where we are seeing a wave of societal challenges due to the closure of coal plants and mines, was the logical first step for us to take,” Chatterjee said in a statement.

“We want to start some new conversations with new voices and create relationships and understanding among the range of interests that are affected by this energy transition.”

There will also be panels on the intersections between energy and telecommunications, water and the opioid epidemic (“Pain, Pills, and Police: The intersection of the energy industry and the opioid epidemic”).

“The law enforcement community is grateful for Chairman Chatterjee’s out-of-the-box thinking in also focusing this conference on the intersection of the opiate epidemic and the coal industry at both ends of our commonwealth,” panel moderator Russell Coleman, U.S. attorney for the Western District of Kentucky, said in a statement.

Speaking to RTO Insider on Friday, Chatterjee said he has been “humbled and overwhelmed by how much interest there has been in this.” He estimates that, not including press and support staff, about 170 people have confirmed they will attend so far.

The event will be held “throughout” Kroger Field, the University of Kentucky’s 61,000-seat football stadium. Chatterjee said he has not yet done a site visit, but the stadium is home to the Woodford Reserve Club, used to host special events.

Chatterjee said the idea for the event took shape over the past six months. He said that as the industries that FERC regulates rapidly change, “the commission has clearly seen an increase in the visibility of its work,” but “a lot of people aren’t familiar with it.”

“It’s time people had a better idea of what FERC does,” he said. The forum will also give the commission the opportunity to hear discussions it wouldn’t normally be able to during its regular business hours, he said.

But Chatterjee also “liked the idea of getting out of Washington” and introducing stakeholders to Kentucky, a place that hasn’t felt the benefits of the energy transition as much as others, he said.

Prior to joining FERC, Chatterjee, a Lexington native, was an adviser on energy policy to Senate Majority Leader Mitch McConnell (R-Ky.). But energy wasn’t his first choice when coming to Capitol Hill: He originally wanted to work on health care policy, he said, as both his parents were professors and cancer researchers at UK. (He attended St. Lawrence University in upstate New York, as he couldn’t stand the idea of taking classes from his parents and their friends, he said.)

It was only when working on energy issues on behalf of McConnell that, he said, he fully realized the importance of coal to Kentucky. “Coal wasn’t just part of the economy; it’s part of the cultural lifeblood of the state.”

It’s also a central part of politics there. McConnell, who faces re-election in 2020, has been attacked by his Democratic challenger, Amy McGrath, for not supporting legislation to strengthen coal miners’ pensions or a fund that supports miners with black lung disease.

Just after he joined the commission in August 2017, Chatterjee said in FERC’s “Open Access” podcast that as a Kentucky native, “I’ve seen firsthand throughout my life how important a contribution coal makes to an affordable and reliable electric system. … As a nation, we need to ensure that coal, along with gas and renewables, continue to be a part of our diverse fuel mix.”

A year later, after FERC unanimously rejected the Department of Energy’s NOPR Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants, Chatterjee talked about how former Chairman Kevin McIntyre had “helped me grow in my role as I made the transition from formerly partisan legislative aide to independent regulator.” (See Returning Chair Pledges to Protect FERC’s Independence.)

The inclusion of a panel on the opioid crisis had some FERC watchers scratching their heads.

“It appears from the content of this event that the chairman is [planning to run] for political office in Kentucky,” said one FERC observer who agreed that Chatterjee appears more animated by politics than by many of his FERC duties.

“This is a purely substantive event with serious and diverse technical content that is not political in any way whatsoever,” Chatterjee said Monday when asked if any political ambitions in the state.

It’s apparent at least that he did not shy away from the controversial. One panel is titled “All of the Above vs. Green New Deal: How States Balance Costs, Carbon and Communities” and will feature several state utility commissioners. Another is a “Conversation on Climate,” to be moderated by Rich Powell, executive director of ClearPath, an organization that supports “conservative policies that accelerate clean energy innovation.” Jason Bordoff, director of Columbia University’s Center on Global Energy Policy, will be a panelist.

Tyson Slocum, director of Public Citizen’s Energy Program, who has been highly critical of FERC, said he agreed to participate as a panelist on “Empowering 21st Century Energy Consumers with Technology” after receiving assurances he would be able to make his points that “FERC has to do a lot more to ensure the public and the public interest has a meaningful seat at the table” on commission issues and on RTO governance.

Public Citizen and other groups have been pushing since at least 2016 to have FERC provide public funding for interventions before the agency, as they say was required by the Public Utility Regulatory Policies Act. (See Citizens Groups Seek Public Funding for FERC Interventions.)

Rich Heidorn Jr. contributed to this report.

September 30, 2019

Texas PUC Briefs: Sept. 26, 2019

Texas regulators last week formally approved one of two transmission projects necessary to integrate much of the city of Lubbock’s load into ERCOT.

The Public Utility Commission signed off on a certificate of convenience and necessity (CCN) during its open meeting Thursday, granting Sharyland Utilities and Lubbock’s joint application for a 58-mile, $90 million 345-kV link between substations in Ogallala and Abernathy. Substation improvements will increase the total cost to nearly $100 million (48625).

The commission also heard oral arguments from two landowners opposing the path of the second 345-kV project, a 33-mile line from Abernathy to Wadsworth projected to cost about $74 million (48668).

The Texas PUC holds its open meeting Sept. 26.

The PUC will vote on the second CCN during its Oct. 11 open meeting. Chair DeAnn Walker suggested neither landowner — one of whom said he was a 101-year-old World War II veteran — needed to again make the long trip from Lubbock.

“My daughters went to [Texas] Tech [in Lubbock], so I know what that drive’s like,” Walker said.

The CCNs are needed to move 470 MW of the city of Lubbock’s load from SPP to ERCOT. (See “LP&L Lines for ERCOT Integration near Final Approval,” Texas PUC Briefs: Sept. 12, 2019.)

Oncor will be responsible for the projects’ construction before turning them over to Lubbock Power & Light, the city’s municipal utility. Both lines are scheduled to be energized by June 2021, meeting LP&L’s target date to join ERCOT.

Commission Approves Rate Recovery, $328K in Fees

In other business, the commission approved $110,600 in administrative penalties:

Retailer Quest Distributors was docked $20,000 for collecting deposits without informing the commission and without adequate customer protections (49576).
Utility AEP Texas settled for $69,000 (49725) and Entergy Texas settled for $21,600 (49829) in penalties regarding annual service quality.

The PUC approved El Paso Electric’s requests for a distribution cost recovery factor, based on an annual Texas retail revenue requirement of almost $7.8 million (49395), and to implement an interim fuel refund of almost $19.2 million (49482). It also agreed to requests by Southwestern Public Service (49495) and Oncor (49594) to adjust their energy efficiency cost recovery factors.

— Tom Kleckner

September 30, 2019

Key Details Change in MISO MEP Cost Allocation Plan

By Amanda Durish Cook

CARMEL, Ind. — Months after FERC rejected an earlier cost allocation plan, MISO is circulating a new draft proposal that would further lower voltage thresholds but raise cost minimums on economically beneficial transmission projects.

Under the new plan, MISO would lower the voltage requirements on market efficiency projects (MEPs) from 345 kV to 100 kV, compared with the 230-kV minimum in the first filing.

However, the cost threshold is set to rise from $5 million to $25 million for regional MEPs.

For interregional MEPs with either SPP or PJM, MISO will also seek a 100-kV voltage threshold but no cost threshold.

MISO MEP — Jesse Moser, MISO | © *RTO Insider*

“Perfection is not achievable, but we want to be as good as we can be,” Jesse Moser, MISO director of economic and policy planning, said during a meeting of the Regional Expansion Criteria and Benefits Working Group (RECBWG) on Thursday.

Moser said the cost requirement increase maintains a “demarcation of larger, regionally beneficial projects.” MISO’s $5 million threshold was approved by FERC in 2007.

The $25 million figure is not final and still open to suggestion, Moser said. He said a regional MEP cost threshold could also be designed to move with inflation. Going forward, MISO intends to review its MEP cost allocation method with stakeholders once every three years, he said.

“It was more about having a way to have some separation between local and regionally economic projects,” Moser said. “There’s not going to be an answer that doesn’t have some controversy and challenges.”

As in the first filing, the new plan would exempt from MISO’s competitive bidding process any MEPs needed within three years to mitigate reliability issues. The filing also preserves the elimination of a 20% postage stamp cost allocation. It additionally still seeks to add new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path.

But the new filing has abandoned a provision that would create a local economic project type.

FERC rejected the first cost allocation filing in June, finding it would have violated the principle of cost causation because projects proposed under the local economic transmission category would be required to demonstrate regional benefits while only being cost-shared on a local level.

The project type was meant for smaller, economically driven transmission projects between 100 and 230 kV, with 100% of costs to be allocated to the local transmission pricing zone containing the line. The projects would not only have to meet a local benefit-to-cost ratio of 1.25-to-1 or greater within their pricing zones but also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs. (See MISO Mulling Next Steps on Cost Allocation Overhaul.)

“While FERC expressed appreciation for many aspects of the proposal, the commission had some concerns about the newly created local economic project category,” MISO CEO John Bear said at the RTO’s July Informational Forum.

Discord

MISO considered several possibilities before settling on the draft proposal, including lowering the voltage threshold to 100 kV for interregional MEPs only or placing projects lower than 230 kV back into the RTO’s existing “other” project category. Stakeholders have offered various opinions on the refiling, with some urging MISO to lower the interregional voltage threshold to 100 kV on both sides of the seam, and others advising that any 100-kV project be eligible for regional cost-sharing.

“This seems simpler than some of the earlier discussions,” Clean Grid Alliance’s Natalie McIntire said of the new version at the RECBWG meeting.

However, other stakeholders contended the MISO community was suffering from “cost allocation fatigue.” Some said it wasn’t clear why the RTO so dramatically altered its original proposal to include 100-kV projects instead of simply removing the lower-voltage project issues FERC raised.

Xcel Energy’s Susan Rossi characterized the proposal as a “drastic change at the last minute.”

But others said that if MISO failed to address the lower-voltage cost-sharing, it would be ignoring LS Power’s pending complaint that asks FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)

McIntire also said some stakeholders were forgetting that the original proposed 230-kV threshold was just the product of a compromise that several stakeholders still disagreed with because they felt it still represented too high a bar.

“I think MISO’s decision to move to 100 kV throws that compromise out the window, and that will be evident to FERC,” Entergy’s Matt Brown contended.

2020 Extension

The new MEP filing will still contain a cost allocation proposal for interregional projects with PJM, even though FERC’s rejection of MISO’s first allocation plan stood to complicate separate deadlines associated with compliance around the longstanding complaint by Northern Indiana Public Service Co. (See “Interregional Filings Also Rejected,” MISO Allocation Plan Fails on Local Project Treatment.)

FERC in mid-September granted an extension that will allow MISO to file its interregional allocation compliance by Jan. 2, 2020, instead of the original late September deadline (EL13-88). MISO was originally due to file its PJM interregional cost-sharing plan by Sept. 23, the date established in FERC orders stemming from NIPSCO’s 2013 complaint over the PJM-MISO seam that ultimately eliminated a cost minimum and lowered the voltage threshold for MISO-PJM interregional projects to 100 kV.

MISO said it needed the extra time for the MEP filing “to ensure proper coordination” with the compliance filing ordered in the NIPSCO complaint. The RTO also said that this is its first extension request since FERC rejected its proposed cost allocation changes to interregional and regional MEPs.

At a Sept. 17 meeting of the MISO board’s System Planning Committee, Director Nancy Lange urged stakeholders to keep working on a cost allocation refiling and remain undeterred by FERC’s rejection of the first proposal.

“I was happy that there was a consensus that could be filed with FERC,” Lange said of MISO’s first filing in late February.

Moser said MISO doesn’t envision using all the extension period granted in the NIPSCO complaint and hopes to make a revised cost allocation filing before Thanksgiving. MISO’s latest proposal is open to stakeholder comment through Oct. 10.

September 30, 2019

PUCO Delays Ruling on AEP Solar Projects

By Christen Smith

The Public Utilities Commission of Ohio last week delayed ruling on the need for two solar projects proposed by American Electric Power after the company asked for a “brief hold” to update its filings to reflect the impact of the recently approved Clean Air Act.

In its request filed Sept. 20, AEP said certain provisions of the new law — also known as House Bill 6 — convey potential benefits to the 300-MW Highland Solar and 100-MW Willowbrook facilities proposed in its long-term forecast report filed last year. The company offered very few details of how the legislation changes its proposal, citing confidentiality agreements, but did ask for a 60-day delay in proceedings.

“The new filing, if successful, would present the commission with additional options and flexibility as compared to the company’s existing proposal filed in these proceedings,” Steven Nourse, AEP’s attorney, wrote in the request. “Moreover, it is the company’s view that the new filing will ameliorate many of the concerns and objections raised by opponents in these proceedings. Such developments should be viewed as helpful regardless of whether the potential opinion and order scheduled for consideration on Wednesday would have initially rendered a positive finding or a negative finding on the need issues.”

The $170 million Clean Air Act, signed into law in July, curtails the state’s current renewable portfolio standards and tacks on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills, mostly for FirstEnergy Solutions’ Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects, including Highland Solar and Willowbrook, in rural areas of the state. (See Ohio Approves Nuke Subsidy.)

AEP submitted documents last year seeking cost recovery under the state’s renewable generation rider (RGR) for 500 MW of wind and the Highland and Willowbrook solar projects.

PUCO said last year that it would first determine the need for the projects before approving cost recovery mechanisms. On Sept. 19, the commission indicated it would announce a decision in the first half of the proceedings at its Thursday meeting; however, the agenda item was subsequently withdrawn. PUCO spokesperson Matt Schilling said the commission gave no reason for the change, telling RTO Insider that “it’s not uncommon to pull cases from the agenda to allow for more time to consider.”

Protesters — including the Ohio Consumers’ Counsel, Direct Energy, IGS and IGS Solar — urged the commission to rule in the case anyway, calling the bill irrelevant to “the statutory issue of whether Ohio utility consumers need electricity from the proposed solar plants.” Kroger and the Ohio Coal Association also opposed AEP’s request.

“HB 6 did not alter Ohio law that strictly limits a utility’s ability to seek PUCO approval of customer-funded subsidies for new generation plants that it proposes to own or operate,” the protesters wrote in a joint filing. “This separate funding for a monopoly utility generation project (including solar) can only be approved by the PUCO if the utility can show, among other things, that utility consumers need the electricity from the proposed power plants. As has been shown in this case, Ohio consumers don’t need electricity from AEP’s proposed plants, as the competitive market provides more than an adequate supply of power.”

The companies further allege that AEP doesn’t need a second revenue stream on top of the money afforded to the projects via HB 6.

“An outcome that could actually ‘ameliorate many of the concerns and objections raised by opponents in these proceedings,’ as AEP asserts, would be for AEP to withdraw its proposal and to develop the contested renewable projects through a separate affiliate,” the companies wrote. “Of course, AEP is free to undertake that endeavor outside this proceeding, without a delay in the PUCO’s decision.”

Scott Blake, an AEP spokesperson, told RTO Insider on Monday that concerns about the company collecting twice on the same projects presuppose the commission would accept the proposals as filed — an unlikely scenario given the impacts of HB 6 and the points raised by protesters within the proceeding.

“The HB 6 credit would also be factored in to any customer charge,” he said. “Under the proposal, we would purchase power at a fixed cost per megawatt-hour from the developer of the project. The credit from HB 6 would be included in the cost and used to calculate the customer portion.”