Page 1078 – RTO Insider

July 10, 2020February 19, 2025

Pa. House Passes Bill Limiting RGGI Entry

The Pennsylvania House of Representatives voted Wednesday to pass a bill limiting the state’s entry into the Regional Greenhouse Gas Initiative (RGGI), but experts expect the state will ultimately enter the environmental compact despite concerns from legislators.

House Bill 2025 passed by a bipartisan majority of 130-71. It would require the legislature’s approval before Pennsylvania can enter any multistate program like RGGI that imposes taxes. The Department of Environmental Protection would need to submit “a description of the economic and fiscal impacts that would result” from joining such a program to aid the legislature in its decision.

The bill would also require legislative authorization before the state can impose a carbon tax on employers engaged in electric generation, manufacturing or other industries.

Gov. Tom Wolf signed an executive order in October directing the DEP to develop a rulemaking for joining RGGI by July 31; citing the pandemic, Wolf provided the department with a six-week extension, to Sept. 15. His authority to issue such an order has been continually challenged by the Republican-controlled legislature. (See GOP Continues Opposition to Pa. RGGI Plans.)

Rep. Jim Struzzi speaks June 8 before the vote on his bill limiting Pennsylvania’s entry into the Regional Greenhouse Gas Initiative. | Pa. House

“This bill gives a voice back to the people by allowing those of us who represent them to have say in this process,” Rep. Jim Struzzi, the bill’s primary sponsor, said during Wednesday’s House session and vote. “The action to enter RGGI would have serious ramifications on Pennsylvania businesses, jobs, energy prices and future economic opportunities that are not being considered by the governor.”

RGGI, which includes New York and the six New England states, currently has three PJM states: Delaware, Maryland and New Jersey. On Wednesday, Virginia Gov. Ralph Northam announced that the state had finalized a rule in preparation for it joining the compact on Jan. 1. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)

The bill now goes before the State Senate for consideration, with sessions scheduled for July 13 and 14. The body may take up the House bill or consider its companion bill, Senate Bill 950, which currently has 20 Republican sponsors, representing 40% of the 50-seat chamber.

During Wednesday’s session, House Majority Leader Kerry Benninghoff (R) said that of the nine states that have already entered into RGGI, all of them voted to join through votes in their respective legislatures. Benninghoff also called RGGI a “job killing” measure that will drive high-paying jobs out of Pennsylvania and into Ohio and West Virginia, the state’s two neighbors that are neither part of nor considering joining the compact.

“No governor has the authority to rule by the swipe of a pen without the input or the consent of the people of Pennsylvania,” Benninghoff said. “No governor has the authority to implement a tax, and no governor has the authority to enter into a binding compact or agreement. That authority lies with the people of Pennsylvania and the members of this chamber sent by the people.”

Rep. Leanne Krueger (D), a supporter of RGGI, said H.B. 2025 was an attempt to downplay the significance of reducing carbon dioxide emissions in Pennsylvania and at the same time scare people into thinking the actions of joining the group will harm them financially.

“Joining RGGI is the biggest climate action that Pennsylvania will have ever taken, the biggest environmental action certainly of my generation,” Krueger said in comments after the bill passed. “And yet we’re facing a bill that would stop the governor in his tracks and not allow us to join this common-sense” market.

Outside View

Despite Wednesday’s vote, outside observers said Pennsylvania still stands a strong chance of joining RGGI.

ClearView Energy Partners predicted in a report that Wolf is guaranteed to veto any bills passed by the legislature overriding his executive order. And although Wednesday’s bill passed with bipartisan support, ClearView said there most likely won’t be enough votes to overcome a veto.

ClearView said legislators may rely on a strategy of inserting H.B. 2025 language into November’s budget, forcing Wolf to take a stand on budget debates. However, it pointed out Wolf has line-item veto authority over the budget and has used his power before to reject abortion language inserted in last year’s budget.

Another possible Republican strategy, according to ClearView, is a legal challenge, as legislators have argued that Wolf’s executive order did not cite specific provisions within the Pennsylvania Air Pollution Control Act, which does not describe CO2 as a “pollutant.”

July 10, 2020February 12, 2025

Coal Org Pushes Back on Self-Commit Study

Coal trade organization America’s Power has countered a recent Union of Concerned Scientists analysis that claimed coal generation self-commitments are unnecessarily costing Midwestern ratepayers millions.

The group, formerly known as the American Coalition for Clean Coal Electricity, said that far from conducting uneconomic behavior, MISO’s coal units closely follow energy demand. The group said that in 2018, changes in electricity demand and coal generation output correlated about 87% of the time, regardless of utility or whether MISO issued dispatch instructions. It also said the percentage was the same as natural-gas fired generation in the footprint.

“Not only are coal-fired generating units run economically, they are run according to market demand as much any other type of generation in MISO,” America’s Power said in its rebuttal, released June 25 and titled “Never Let the Truth Get in the Way of a Good Story.”

“Self-committing coal-fired power plants is not a trick to rip off ratepayers,” it said. “Rather, it benefits ratepayers and helps maintain the reliability of the electricity grid.”

UCS’ June analysis concluded that coal plant self-commitments saddled Midwest electricity customers with $350 million in avoidable costs in 2018. The study also said individual ratepayers could have saved an average $60 apiece over the year if the most efficient existing resources in MISO were deployed instead of coal plant self-scheduling. UCS used the study to make a case for state regulators to open investigatory dockets into utilities that exhibit high costs. (See UCS Analysis Knocks Coal Self-commitments.)

| America’s Power

MISO has said about 90% of energy from its coal is either from economic commitments or economically dispatched above the units’ economic minimum levels.

“Some claim that self-commitment of coal-fired resources results in prolonged run times and uneconomic outcomes for end-use customers,” MISO said in an April report. “Further, they say self-commitment distorts the markets by allowing coal units to displace lower-cost renewables and other resources from the grid. In fact, the vast majority of all self-committed coal generation in MISO is actually dispatched economically — meaning it is the lowest-cost resource option that MISO markets have available at the time to serve load.”

MISO Executive Director of Market Operations Shawn McFarlane said most self-committed, coal-fired energy is dispatched economically.

“We try to minimize any uneconomic dispatch … taking into account operational constraints,” McFarlane said during the Market Subcommittee meeting in May.

Monitor to Weigh in

On Thursday, MISO’s Independent Market Monitor David Patton told the MSC that he will publish his own report on coal self-commitments next month, but he doesn’t anticipate alerting staff and stakeholders to a problem.

Coal resources that offer in the day-ahead market as must-run are overwhelmingly offered economically, Patton said. He said 98% of available offline coal units offered economically in the day-ahead market this spring, up from 89% last year.

“As gas prices fall, it’s becoming harder to predict when it will be economic for coal resources to run,” Patton said. Offering in must-run status prevent the units from incurring expensive cycling costs when they’re decommitted and brought back online later, he said.

July 10, 2020

MISO Closer to Seasonal Capacity, Reliability Reqs

MISO will evaluate the merits of defining new seasonal reliability criteria and implementing a sub-annual capacity construct, stakeholders learned Wednesday.

The new evaluation stage is another, more formal step toward creating a seasonal capacity construct. The RTO has repeatedly said it is considering defining unique system reliability requirements for the footprint because of analyses that signal an emerging wintertime loss-of-load risk.

The move could have MISO issuing sub-annual reserve margins based on seasons, beyond NERC’s annual reliability standards. The RTO plans to publish a white paper on reliability needs in the third quarter.

Brattle Group Principal Sam Newell told stakeholders that supply shortage risks are shifting from the summer peak.

“As MISO looks to a future with more wind and solar and less coal and seasonal mothballing, the risks will continue to shift,” Newell said during a Resource Adequacy Subcommittee conference call Wednesday.

Some stakeholders have said seasonal reliability criteria could infringe on states’ jurisdiction over resource adequacy and told MISO the existing annual local clearing requirements and planning reserve margins it provides are sufficient. (See Stakeholders Split on Potential MISO RA Requirements.)

MISO Seasonal Capacity — MISO’s Carmel, Ind., headquarters | © *RTO Insider*

But on Tuesday, 11 utilities and power organizations urged MISO in a letter to move ahead with a sub-annual capacity construct. The group — including Xcel Energy, Ameren, DTE Energy, Consumers Energy and WEC Energy Group — said the RTO should pursue a segmented capacity auction and capacity resource accreditation changes based on seasons or months.

“The reliability risks facing the MISO footprint have been plainly identified, appropriately articulated to stakeholders and demonstrated by the significant number of emergency actions taken by MISO operators since June 1, 2016,” the group wrote. “The transition to a sub-annual capacity construct would provide MISO and stakeholders with the ability to procure more tailored capacity commitments to address non-summer capacity risk.”

MISO also added another maximum generation emergency event to its tally Tuesday for its Northern and Central regions, as much of MISO Midwest was gripped by a persistent heat wave.

This year’s resource adequacy survey conducted by MISO and the Organization of MISO States indicated that the RTO could face a 400-MW capacity shortfall as early as 2022, and the next five years could contain surpluses as high as 12.5 GW or deficits as steep as 6.8 GW. (See OMS-MISO Survey Sees Uncertain Supply Future.)

MISO Executive Vice President of Market and Grid Strategy Richard Doying said change in some form is inevitable for the Planning Resource Auction. He said the capacity auction needs to send signals to buy or build generation when appropriate.

“I don’t believe we can say, ‘Most load is covered, so we’re good,’” Doying said. “It’s a varied landscape that we need to navigate here.”

July 9, 2020

Pandemic Poses Long-term Reliability Challenges

Participants in the first panel of FERC’s two-day technical conference on the long-term impacts of the COVID-19 pandemic struck a hopeful tone Wednesday on the resilience of the North American energy industry.

But they also warned that caution is still needed even as some utilities prepare to return to normal operations.

Uneven Virus Recovery Stalls Returns

pandemic Reliability Challenges — TC Energy CEO Stanley Chapman | *FERC*

Speaking on the “System Operations and Planning Challenges” panel, TC Energy CEO Stanley Chapman observed that the uneven pace of recovery from the pandemic can create difficulties for utilities, especially those with geographically widespread operations. Shifting circumstances on the ground mean that applying a uniform reopening plan across an entity’s footprint may not be practical.

“Mexico City is having a huge [growth in] cases with respect to COVID-19, and as a matter of fact, as we go through our return-to-office plans — [which] we’re going to implement for 25% of employees in Calgary on July 15 — we’re not going to implement [them] in Mexico City given the number of cases,” Chapman said. “Even if you look at things just within the U.S. [itself], we’re not going to reopen the Houston office on July 15 as we had planned, given the large number of COVID cases that we’re seeing in Houston.”

These ongoing issues are not only a challenge for returning workers to the office; field employees run the risk of infection as well. While panelists applauded frontline workers for sacrificing time with their families to ensure the safety of the grid — with several noting that their employees had volunteered for the duty knowing the dangers — they also stressed that the skill of these workers meant their loss to infection would cause major strains on operations.

Utilities Prioritize Worker Safety

Ensuring the safety of frontline employees will be even harder amid the ongoing hurricane season, which industry representatives have already warned is likely to be more active than usual. (See Pandemic Adds to 2020 Hurricane Season Challenges.) Wildfires are also a concern this summer. In response, utilities have had to rethink how they implement their typical response plans.

“Making sure we can keep the men and women on the front lines safe and healthy … really is the heart of some of those new challenges,” said Stan Connally, executive vice president for operations at Southern Co. “Think of thousands of men and women coming together to respond to natural disasters, and we have typically housed, framed, oriented [and] fed those men and women in centralized ways. … Obviously that brings some risks to health and safety in our current pandemic, so our new protocols focus on decentralizing those operations.”

Along with the logistics of moving personnel into position, utilities have also had to grapple with the new challenge of ensuring adequate supply of materials they never considered necessary before, such as gloves, masks and other personal protective equipment (PPE). Operators are also looking beyond these immediate concerns and considering even bigger prospective challenges, which may be harder to address on an individual company basis.

“Early on in the process, hand sanitizer and PPE … were a little bit difficult to get our hands on, but that seems to have worked itself out over time,” Chapman said. “I would note, we’re part of a global supply chain. There are certain items that tend to be supplied disproportionately from one company or region of the world, and in those instances, we definitely need to take a step back and ensure that we have a broad supply of these … critical parts, and we’re not overly dependent on a region or country to supply them to us.”

Strengths, Weaknesses of Planning Exposed

Many participants praised the efforts of their staff to implement business continuity plans early in the outbreak. However, they also acknowledged that the arrival of an actual pandemic had exposed vulnerabilities — for example, in the increased risk from cyberattacks after many employees started working remotely — that they had not anticipated. Experts warned earlier this year that the outbreak had exposed the need for long-term focus on electronic security among critical infrastructure. (See Solarium Team Urges Long-term Cybersecurity Focus.)

Asked by Commissioner Richard Glick how NERC’s pandemic contingency plan — drafted in 2009 — had stood up to the COVID-19 outbreak, CEO Jim Robb admitted that while the plan had been useful as a foundation on which to build a response, on-the-ground solutions have often had to be devised from day to day as the circumstances evolved in unforeseen ways.

“That plan was … completely uninformed by the extraordinary circumstances that this COVID situation has presented, in terms of its breadth and depth of the crisis it’s created in certain geographies,” Robb replied. “That plan served us and the industry well, in terms of the basics that needed to be done, but I think it would be very fair and self-critical to say [that] … in many ways we’ve been at some level building the plane as we’re flying it.”

July 9, 2020

Calif. Energy Commission OKs $22M for Storage

The California Energy Commission approved $22 million in grants Wednesday to fund long-term energy storage projects, considered key to the state’s decarbonization goals, and another $6 million to test the possibilities of using repurposed electric vehicle batteries for solar storage.

The long-term storage grants included $13 million to Native American tribes to test systems that could deliver stored solar and wind power for hours longer than lithium-ion batteries.

“The importance of sustained investments in this space can’t be understated,” CEC Vice Chair Janea Scott said.

The funding is vital “to help push this type of technology forward and to really be looking in the storage space at long-term of ‘what’s the next step,’ so we’re always just a little out ahead of where we’re trying to push the technology as we go in our quest toward 100% clean energy,” Scott said.

The CEC funds energy research through its Electric Program Investment Charge (EPIC) grant program. California load-serving entities are required by Senate Bill 100 to provide retail customers with 100% clean energy by 2045.

Commissioners voted unanimously Wednesday to award $7.3 million to the Rincon Band of Luiseño Indians in San Diego County to connect solar arrays to a vanadium redox flow battery, which uses tanks of chemicals, and a flywheel storage system. Each storage method will provide 400 kW of load for up to 12 hours, creating a microgrid that will power a wastewater treatment plant and a public emergency shelter, among other buildings, the tribe said.

California energy storage — The Rincon Band of Luiseño Indians in San Diego County received $7.3 in grants for long-term storage projects. | *Rincon Band of Luiseño Indians*

Several other tribes won grants to integrate flow batteries and flywheels with solar arrays.

Indian Energy, a Native American-owned company that provides energy solutions to tribes and the military, won a $5 million grant to install a zinc hybrid cathode battery, a flow battery and a mechanical flywheel at Marine Corps Base Camp Pendleton, north of San Diego.

Antelope Valley Water Storage, in the Mojave Desert northeast of Los Angeles, was given $2 million to fund an aquifer pumped-hydro system, which stores water underground to produce hydroelectric power when solar goes offline at night.

Used-car Batteries

The commission also funded projects that will test “retired” EV batteries for use in stationary storage systems.

Technicians remove EV batteries near the end of their useful life, but many can still hold a charge. Connected together to store solar power, the batteries create a microgrid while avoiding waste. BMW is among the companies that have experimented with “second-life” car batteries on a large scale in Europe.

The CEC awarded $2.8 million to the San Diego State University Research Foundation to pair second-life EV batteries with a solar photovoltaic system. Rejoule was given $2.9 million “to develop novel battery grading tools to more quickly and accurately assess the health of repurposed EV batteries for stationary storage.”

“With California leading the nation in electric vehicle acceptance, [it] will have the largest opportunity to fully utilize these batteries that have substantial energy left for stationary use,” Mike Gravely, research program manager at the Energy Commission, told the commissioners.

July 9, 2020

PJM Dusts off ‘State Agreement’ Tx Approach

With Virginia, Maryland and New Jersey committed to building almost 10 GW of offshore wind, PJM is dusting off a never-used mechanism that would allow states to pay for transmission needed to achieve public policy goals.

FERC approved PJM’s “state agreement approach” in the RTO’s first Order 1000 compliance filing in 2013, saying it was “supplemental to PJM’s proposal to consider transmission needs driven by public policy requirements, and not needed for compliance.”

The approach allows individual or groups of states to submit a transmission project for study by PJM, even if it does not qualify as a reliability or market efficiency initiative under the RTO’s Tariff. The project would be included in the Regional Transmission Expansion Plan as a supplemental project or baseline state public policy project — which could trigger a competitive solicitation — if the states agree to pay for it.

During a presentation at the Planning Committee meeting Tuesday, Mark Sims, infrastructure coordination manager, cited several types of projects that could use the approach, including meeting renewable energy goals, emission reduction, grid hardening and supporting electric vehicles.

Because the state agreement approach has never been deployed, Sims said PJM officials thought it would be beneficial to provide stakeholders with education on it. The presentation came a week after the RTO’s announcement of its new State Policy Solutions group. (See PJM to Work with States on Policy Goals in New Group.)

PJM transmission — Public policy in the PJM planning process | *PJM*

Sims said the state agreement approach is addressed in Schedule 12 (B) of the Tariff, Manual 14B and Schedule 6 of the Operating Agreement.

Sue Glatz, PJM director of infrastructure planning, said many generation public policy projects have been developed through the generator interconnection process. “That will continue in the future,” she said. “However, there are other routes that can be [taken], and that’s what we’re talking about today, recognizing that some of these public policies now may be on a larger scale.”

Glatz noted that FERC has scheduled an Oct. 27 technical conference on offshore wind. The commission said it will “discuss whether existing commission transmission, interconnection and merchant transmission facility frameworks in RTOs/ISOs can accommodate anticipated growth in offshore wind generation in an efficient and effective manner that safeguards open-access transmission principles.” (See FERC Announces Tech Conferences on Carbon, OSW.)

Maryland last year approved an offshore wind target of 1,200 MW by 2030. In March, Virginia lawmakers approved a target of 5,200 MW by 2034. In 2018, New Jersey lawmakers set a target of 3,500 MW by 2030; Gov. Phil Murphy issued an executive order last November to increase the target to 7,500 MW by 2035.

Gregory Carmean, executive director of the Organization of PJM States Inc., emphasized that the state agreement approach is one avenue available to the states but was not approved by FERC as meeting PJM’s obligation under Order 1000 to plan transmission for public policy needs.

“FERC has said that’s a supplemental process. It’s nice [if] the states want to do that, but that doesn’t meet [PJM’s] Order 1000 obligations,” Carmean said.

Sims said PJM plans on conducting at least two more informational sessions on the state agreement approach, including one in August and September.

“We want to introduce the [state agreement] topic today and get feedback on what there may be questions about,” Glatz said.

July 7, 2020

PJM to Work with States on Policy Goals in New Group

PJM has created a new group to work with states to advance energy initiatives like offshore wind and grid security.

The State Policy Solutions group will combine PJM’s knowledge of planning, markets and operations with its interpretation of state laws and regulations to help government bodies implement energy policies.

PJM officials said the new group will lend the RTO’s “subject matter expertise” to help states reach energy goals and to help facilitate discussions among states or regional groups if efficiencies in policies make sense across multiple government bodies.

PJM policy goals — PJM CEO Manu Asthana | © *RTO Insider*

“Our states are key stakeholders, and we’re committed to partnering with them whenever possible as they contemplate and execute their policy goals,” CEO Manu Asthana said in a statement.

The State Policy Solutions group is initially focusing on five areas at its launch, PJM said, including offshore wind, resource adequacy, grid modernization, clean energy targets and grid security. The RTO said the areas were chosen because of their overlap with its main functions.

Tim Burdis, PJM’s lead strategist for state government policy, will manage the group, reporting to Asim Haque, the RTO’s vice president of state policy and member services.

Haque, who served as chairman of the Public Utilities Commission of Ohio before coming to PJM in 2019, said the group is a response to evolving state energy policies.

Although the RTO has given technical assistance to states in the past, Haque said the new group will provide a more “holistic, end-to-end approach” through the RTO’s understanding of state laws, regulations, related cases and FERC orders.

“PJM will always champion its primary duties of keeping the lights on and running efficient markets,” Haque said. “At the same time, PJM can utilize its expertise in carrying out those functions to assist our states as they advance their policy objectives. This is an opportunity for us to innovate and partner together in an evolved RTO/multistate dynamic.”

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said what the group will be tasked with doing is not totally clear to him or his organization, but he said the group “seems very promising” and that states’ access to PJM’s expertise will be helpful in decision-making on complicated issues.

“Over the past few years, there have been complaints that PJM has not been responsive to the concerns of the states,” Poulos said. “I’m hoping this ushers in a period where PJM works to repair and develop those important relationships.”

State regulators and other stakeholders were dismayed when PJM announced last year that Denise Foster had unexpectedly resigned as head of the RTO’s State and Member Services Division and that her unit would be realigned. (See Stakeholders, States in Dark over PJM Personnel Moves.)

PJM has frequently found itself in the middle of state-federal jurisdictional disputes over energy policy. Illinois and New Jersey officials are considering pulling their utilities from the RTO’s capacity market because of FERC’s 2019 order expanding the minimum offer price rule.

The RTO is currently considering how it could incorporate carbon pricing for only some of its 14 member states (including D.C.). (See related story, PJM Carbon Pricing Group Talks RPS, ZECs, RGGI.)

July 7, 2020

Energy Harbor Settles with Solar Co. for $66M

Energy Harbor will pay almost $66 million to cancel a solar power purchase agreement signed by its predecessor, FirstEnergy Solutions (FES), clearing away another legal battle as it continues to emerge from bankruptcy.

On Saturday, Judge Alan M. Koschik, of the Bankruptcy Court for the Northern District of Ohio, approved a stipulation outlining the settlement between Energy Harbor and Maryland Solar Holdings.

The judge’s order came three days after FERC granted Energy Harbor’s request to hold in abeyance for 90 days a docket the commission had opened to consider whether FES could abrogate its contracts with Maryland Solar and the Ohio Valley Electric Corp. (OVEC) (EL20-35).

The commission said it agreed with Energy Harbor that the proceeding would be moot if the bankruptcy court accepted its settlements with Maryland Solar and one announced in May with OVEC.

Energy Harbor agreed to pay Maryland Solar $65.9 million less $1 million in cash collateral held by the solar company for the PPA signed by FES in 2011 for the purchase of renewable energy and related credits. Maryland Solar, which owns a 20-MW solar farm in Washington County, Md., had sought $79.8 million in the dispute.

FES changed its name to Energy Harbor upon emerging from bankruptcy in February, with former bondholders owning 50% of the equity.

Energy Harbor also assumed FES’ obligations with OVEC and agreed to pay the company $32.5 million in a settlement approved by the bankruptcy court on June 15. (See Energy Harbor to Pay OVEC $32.5M in Settlement.)

In March, FERC ordered a paper hearing to consider FES’ attempt to void the OVEC contract and PPA with Maryland Solar as part of its bankruptcy proceeding. The commission acted after the 6th U.S. Circuit Court of Appeals issued a mandate overruling the bankruptcy court’s May 2018 injunction preventing FERC from issuing any order requiring FES to continue complying with the contracts. The appellate court also reversed the bankruptcy court’s ruling allowing FES to reject the contracts.

In holding the proceeding in abeyance, FERC ordered Energy Harbor to file a report by Sept. 29 updating the commission on the status of the court proceedings.

FERC’s order opening the docket said the “jurisdictional contracts” included several wind PPAs signed by FES in addition to the OVEC and Maryland Solar contracts. But Energy Harbor’s June 15 motion to hold the FERC docket in abeyance said Maryland Solar and OVEC were “the sole counterparties to the jurisdictional contracts at issue in this proceeding.”

A company spokesman clarified that FES had entered into stipulations with all of the other counterparties during the Chapter 11 restructuring proceedings.

July 7, 2020

Texas Public Utility Commission Briefs: July 2, 2020

The Texas Public Utility Commission last week approved a new rule that allows utilities operating solely outside the ERCOT region to apply for a generation-cost recovery rider (GCRR) for capital investments in individual generation facilities (55031).

The rule applies primarily to El Paso Electric, Entergy Texas, Southwestern Electric Power Co. and Xcel Energy’s Southwestern Public Service. It stems from a bill passed (HB 1397) in last year’s state legislature.

PUC Chair DeAnn Walker, pointing to the abundance of renewable facilities already installed and coming online, modified the rule in a memo before the July 2 open meeting to clarify that a utility may include “more than one discrete generation facility” in the rider. Utilities will be allowed to amend their GCRRs to request inclusion of additional generators.

Texas Public Utility Commission — PUC Chair DeAnn Walker, the sole commissioner present, leads July 2’s open meeting.

“I feel like where we are with our future generation, most are going to be smaller projects, where you may need to have more than one included in the rider,” Walker told her fellow commissioners.

The commission agreed that if the rule is not working, they can always revisit the issue. Walker said the PUC’s earnings-monitoring process would allow them to determine whether any utilities were taking advantage of the rule.

Walker was the only commissioner present in the PUC’s meeting room. Commissioners Arthur D’Andrea and Shelly Botkin both called in from remote locations.

PUC Extends Customer Relief Program

The commissioners agreed to extend the state’s Electricity Relief Program from July 17 to Aug. 31, citing Gov. Greg Abbott’s decision to curtail certain economic activities in the face of rising coronavirus diagnoses and hospitalizations. An order will be drafted for the commission’s approval during its July 16 open meeting.

The PUC created the program in March to help retail providers’ unemployed customers by shielding them from disconnections for nonpayment and offering bill payment assistance.

“While we certainly wish we could snap our fingers and make this virus go away, it’s clearly with us for the long haul and we need to reflect that in our decisions,” Walker said.

The state reported a record 8,258 COVID-19 confirmed cases on July 4, bringing its total to 195,239. A record 8,181 Texans were hospitalized on Sunday. The state has reported 2,637 deaths.

The program is funded by a rider charge applied to customer bills within the ERCOT region.

Entergy, LCRA Get CCNs

In other actions, the PUC:

G ranted Entergy Texas a certificate of convenience and necessity (CCN) to build, own and operate a 230-kV line and substation north of Houston that is needed to accommodate future load growth. Entergy has reached a settlement with all intervenors on a 9-mile route that is projected to cost $34.1 million. The substation is expected to cost an additional $23.3 million (49715).
Approved Lower Colorado River Authority’s request for a CCN for a new substation and a 138-kV line connecting the facility with the grid in the Texas Hill Country north of San Antonio. The 22.5-mile project, costing an estimated $64.3 million, is needed to address congestion and voltage issues, LCRA said (49523).

July 7, 2020

Hearing Ordered on $154M ATSI Rate Bid

FERC last week ordered hearing and settlement judge procedures on American Transmission Systems Inc.’s (ATSI) request to recover deferred and ongoing legacy costs related to the company’s move from MISO to PJM in 2011 (ER20-1740).

ATSI’s proposed revisions to its transmission formula rate, filed by PJM in May, sought $154 million in additional rates, including legacy MISO Transmission Expansion Plan costs, costs of ATSI’s integration into PJM and deferred vegetation management costs.

In 2011, the commission rejected ATSI’s first request for recovery of PJM integration costs and MISO exit fees, saying the company had failed to “provide sufficient information or support that would enable the commission to find that it is just and reasonable for ATSI’s transmission customers to bear the costs arising from the decision to switch RTOs.”

FERC upheld the denial on rehearing in 2016. It said its ruling was without prejudice, allowing ATSI to file a new request that included a detailed cost-benefit analysis showing that the benefits to wholesale transmission customers exceed the costs of the switch to PJM. (See FERC Rejects ATSI Bid for Cost Recovery on Switch from MISO to PJM.)

ATSI Rate Bid — American Transmission Systems Inc. is a unit of FirstEnergy. | *FirstEnergy*

In justifying its new rate request, ATSI, a unit of FirstEnergy, said its move to PJM has generated about $4 billion in benefits, dwarfing the $154 million it seeks to recover.

But American Municipal Power (AMP), Buckeye Power, Industrial Energy Users of Ohio (IEU) and the federal energy advocate for the Public Utilities Commission of Ohio protested the request.

AMP and Buckeye said the request should be rejected because of the four-year delay in refiling for the RTO transition costs since the commission’s 2016 rehearing order. AMP said utilities should not have unlimited discretion on how long it will carry deferred costs on its books. AMP, Buckeye and IEU also contended that ATSI’s cost-benefit analysis did not accurately calculate the impact on Ohio retail customers.

IEU and AMP also challenged ATSI’s request for $18.7 million in deferred vegetation management costs incurred from 2013 to 2016, saying the company failed to demonstrate that they were “enhanced” or prudently incurred.

Citing the disputes, the commission’s order accepted ATSI’s proposed Tariff revisions and suspended them for five months to become effective Dec. 1, subject to refund.