FERC approved changes to PJM’s fuel-cost policy (FCP) rules on Tuesday, replacing annual reviews with a new periodic review process and eliminating the requirement for zero-marginal-cost units to submit FCPs (ER20-1764).
The deadlines for reviewing FCPs were also changed, giving the Independent Market Monitor an initial 10 business days to review a policy and an additional five business days when a market seller revises the policy. PJM will have 20 business days to review a policy and an additional five business days for reviewing revisions, although that time frame can be changed if agreed to by the RTO and the market seller.
The revisions are set to take effect on Sept. 1. They were proposed by the PJM Industrial Customer Coalition and endorsed by the Members Committee in March. (See Revised Fuel-cost Policy Approved by PJM MC.)
Heat rate and cost curves for 550-MW natural gas-fired team unit | PJM
“We find that the revisions reduce administrative burdens on market sellers and PJM and afford certain flexibility without jeopardizing the purpose of requiring fuel-cost policies,” the commission said. “We also find that PJM’s proposal provides additional transparency regarding the conditions under which PJM will expire or terminate a fuel-cost policy and affords market sellers additional time within which to make modifications to a fuel-cost policy.”
PJM proposed six main revisions to its FCP rules. They include:
Replacement of the annual review process with a periodic review process, easing the administrative burden of reviews while ensuring policies don’t become outdated. PJM anticipates setting a three-year expiration date for each policy.
Removal of the requirement for resources with zero marginal costs to have FCPs. PJM argued it is an “unnecessary burden” to require market sellers of resources with no marginal fuel costs to submit FCPs to avoid a penalty because their fuel costs will always be zero.
Allowance of a temporary cost offer methodology when a market seller does not have an approved FCP. PJM said the proposed methodology would allow a market seller to offer a “conservatively estimated, cost-based offer” while its FCP is under review by the RTO and the Monitor.
Replacement of the revocation provision, with the ability for PJM to expire FCPs. The RTO cited three scenarios that would allow for the expiration period under consultation with the Monitor, including changes in governing documents, an inconsistent cost estimation method or the failure to update a generation transfer to another market seller.
Revisions to the existing penalty calculation, including reduction of penalties for noncompliant cost-based offers where there is no market impact or the market seller self-identifies an error in the cost-based offer.
Elimination of the penalty for noncompliant cost-based offers if the reason for fuel pricing or cost estimation deviation is because of an “unforeseen event” outside of the control of the market seller, its agents or affiliated fuel suppliers.
FERC determined that PJM’s revisions to the penalty calculation structure will “diminish the potential volatility in the current penalty amount while not limiting the deterrent effect of the penalties.” The commission also said it believed the penalty structure revisions will “appropriately represent the overall market impact a market seller’s noncompliant cost-based offer may have had on the market over the time period of noncompliance.”
MISO on Tuesday won FERC’s approval to create an 11th stakeholder sector for hard-to-categorize members despite some misgivings about the equity of the new arrangement.
The commission’s order means the grid operator can alter its bylaws and Transmission Owners Agreement to include an “Affiliate” sector, which will serve as a repository for new members that can’t be pigeonholed into other sector groups (ER20-1926). The Affiliate sector would also serve as a home for any member that isn’t participating in another sector. Prospective members must declare a sector affiliation before they can join the RTO.
Commissioner Richard Glick dissented in part from the order, saying it was odd and inappropriate for the commission to greenlight rules that it recognized as unfair.
MISO’s Advisory Committee in spring voted to create the sector with the blessing of the RTO’s Board of Directors, which cautioned that the move should be considered a temporary measure and charged the committee with developing a holistic ruleset on how new sectors are created and new members are admitted to them. The board said the AC should ensure all members have full participation in the stakeholder process. (See Board OKs 11th MISO Sector, Orders Redesign.)
The AC has until March to draft a fuller solution for incoming and increasingly diverse MISO members. In the meantime, the committee recommended that the new sector not be allowed a vote in either its or Planning Advisory Committee matters but have one designated non-voting seat for its meetings and be allowed to offer opinions during the its quarterly discussions on industry current events.
The committee began debating the merits of a new member sector last year when Lignite Energy Council (LEC), a North Dakota coal lobbying group, approached MISO about membership. The company did not fit neatly into any of MISO’s existing 10 sectors and was likely to be designated as an “other” in the Environmental and Other Stakeholder Groups sector.
Some AC members said it wasn’t fitting that a sector group would contain entities with diametrically opposed views, contending that a new sector was necessary to ensure the current Environmental sector could have a singular voice.
Coal trade organization America’s Power, coal and iron mining organizations, and some chambers of commerce are also interested in joining the Affiliate sector, according to LEC.
The commission said the proposal seemed to be a “good-faith attempt to provide America’s Power and Lignite Energy Council with an opportunity to participate in the stakeholder process, albeit on an unequal footing, while MISO and its Advisory Committee examine options for a more permanent arrangement for its sector system as a whole.”
FERC also said that because America’s Power and LEC made filings themselves to support the new sector design, it was “reluctant to second guess what is likely a deliberate, informed decision by the interested parties.”
But the commission also warned that it was awaiting a second filing next March on a more permanent solution. It said that if MISO doesn’t make a filing, it may institute a proceeding under Federal Power Act Section 206 against the RTO.
The commission also said that because it couldn’t know what MISO’s new sector design would be, it couldn’t honor America’s Power and LEC’s request to be allowed to block “new entrants with nonaligned viewpoints” from the Affiliate sector.
Glick: Can’t Have it Both Ways
It was FERC’s warning that it would investigate the arrangement if let unrevised that prompted Glick to issue a partial dissent to the order.
“The commission, with one hand, is accepting MISO’s revisions to the MISO Bylaws and Transmission Owners Agreement to create a new stakeholder sector for MISO’s Advisory Committee and, with the other hand, is suggesting that the revisions are, in truth, not just and reasonable or unduly discriminatory and thus should be modified,” Glick said.
He added that the FPA requires FERC to only accept tariff modifications that are just and reasonable.
Glick was quick to note that he thought the arrangement was fair, affording America’s Power and LEC an opportunity to participate in the MISO stakeholder process.
But he said the other commissioners took an “Orwellian turn” when they cautioned MISO that further revisions were needed to the sector setup: “The Federal Power Act does not permit us to have a foot in each camp. Either something is just and reasonable and not unduly discriminatory, or it is not. I cannot join an order that so blatantly ignores this irrefutable law of nature. If my colleagues believe MISO’s proposed revisions do not meet [FPA] Section 205’s requirements, they must reject the proposal. After all, it goes without saying that the commission may initiate a proceeding pursuant to Section 206 of the Federal Power Act if my colleagues believe further revisions are required. What they cannot do is have it both ways.”
The proposed expansion of CAISO’s Western Energy Imbalance Market to a day-ahead market won’t be as voluntary as advertised, some stakeholders argued this week during calls on the ISO’s plans.
CAISO released the straw proposal for its Extended Day-Ahead Market (EDAM) on July 20, followed by stakeholder calls Monday and Wednesday. (See CAISO Proposal Sets Course for EIM Day-ahead.)
A part of the plan that calls for participants to dedicate transmission capacity to the market drew ire.
Mark Holman, managing director of power with Powerex, said the EIM had proven widely popular because of its wholly voluntary nature. Having more mandatory components in the EDAM could make the market less attractive, he said.
“I think we really need to identify that this is not entities joining a multistate RTO with a corresponding design and governance model,” Holman said. “The EIM has worked well residing in parallel with other market opportunities.”
Western entities have been happy to do business through CAISO’s EIM — which has reaped $1 billion in benefits for participants, CAISO said Tuesday — but they are wary of giving Californians too much control.
To allay concerns, CAISO has made the EDAM’s voluntariness a centerpiece of its efforts, stressing that the EDAM would be much like the EIM and not like an RTO.
“The approach contemplated in this effort does not require full integration into the CAISO balancing authority area as participating transmission owners, nor does it require formation of or participation in regional transmission organization,” the ISO said at the start of its straw proposal.
In his presentation Tuesday, Don Tretheway, the ISO’s principal for market design policy, said one of the proposal’s main principles is that the EDAM will be a voluntary market and won’t assume responsibility for transmission planning, resource procurement and other key functions of an RTO.
However, CAISO said the EDAM will require a different approach to transmission usage than the EIM.
“EIM participants make transmission available to support energy transfers through contributions of interchange rights holders or available transmission capacity,” the straw proposal said. “This transmission supports energy transfers between balancing authority areas at no transmission usage rate.”
In contrast, “transmission to support EDAM transfers must have the same curtailment priority as internal load in each balancing authority area in order for energy and capacity schedules from the source balancing authority area to the sink balancing authority area to assure confidence for the sink balancing authority area,” it said.
‘Turn them over to the EDAM’
Jeff Spires, director of power with Powerex, said entities that rely on transmission to reach customers could get sidelined by the EDAM’s protocols.
Powerex markets BC Hydro’s excess hydroelectric power, much of it to California. The company chafed under EIM market rules in the past because of transmission constraints at the U.S.-Canada border. (See Troubled Waters for Powerex in EIM.)
Spires gave an example Tuesday of potential problems with EDAM’s transmission model involving transfers through the Bonneville Power Administration’s BAA, which covers a vast swath of the Pacific Northwest. Transfers from Canada to California pass through BPA’s territory. BPA is slated to join the EIM in 2022.
| FERC
“If you were to take a balancing authority area like the Bonneville Power Administration, they have many third parties in their BA,” Spires said. “They have many different transmission customers, and between BPA and some of the other service providers, there’s about 8,000 MW of transmission capacity from the BPA system down to California.
“If BPA were to join the EDAM, then under this design, all of those transmission customers would no longer have the ability to use their physical transmission rights under the [open access transmission tariff] in order to deliver their resources to California,” he said. “The only way that they could make use of those rights is to instead turn them over to the EDAM for market use.”
Such a scenario is incompatible with a voluntary market, he said.
Tretheway told Spires, “You should still be able to self-schedule from your resource all the way to CAISO under the EDAM.”
Spires responded, “I just don’t think we share the same perspective on this.”
Mark Rothleder, CAISO vice president for market policy and performance, said ISO managers were still working on the EDAM’s transmission design.
“We hear what you’re saying, and we understand your concerns,” Rothleder told Spires. “I don’t have an answer at this point. This is a little bit of a tough nut to crack on this one.”
The straw proposal addresses only the first “bundle” of topics in CAISO’s EDAM initiative: resource sufficiency rules; use of transmission; and the distribution of congestion and “transfer” revenues — the last being a new concept introduced in the plan to accommodate flows across BAAs in the West.
Comments on the first-phase straw proposal are due to CAISO by Sept. 10. The ISO’s Board of Governors and the EIM Governing Body are scheduled to take up the EDAM plan next year.
FERC on Tuesday rejected transmission customers’ complaint over MISO’s seven-year-old cost allocation plan for baseline reliability projects (BRPs).
The commission said the Coalition of MISO Transmission Customers, Industrial Energy Consumers of America and competitive transmission developer LS Power failed to show that MISO’s current allocation for BRPs is unjust and unreasonable (EL20-19).
The groups filed the joint complaint early this year, alleging that MISO’s location-based cost allocation methodology doesn’t square with the commission’s principle that beneficiaries of transmission projects should pay for them. (See Groups Lodge Complaint over MISO BRP Allocation.) In MISO, BRP costs are allocated only to local transmission pricing zones where project facilities are physically located.
They said MISO’s BRP allocation fails to identify all beneficiaries, arguing that the RTO should return to a cost allocation based on a line outage distribution factor (LODF) methodology, the BRP method in place prior to 2013. The LODF method would expand the number of projects eligible for competition under FERC Order 1000, they said.
But FERC said the arguments weren’t enough to upend its previous finding that the transmission pricing zone where a BRP is located enjoys “most of the benefits provided by that project.”
“Therefore … assigning all of the associated costs to that pricing zone results in an allocation of costs that is roughly commensurate to the distribution of the project’s benefits,” FERC said.
| MISO
The commission also said the complainants didn’t refute its finding when it approved MISO’s classification of BRPs as local transmission facilities that the “spillover of benefits to other zones is modest enough to make the local allocation of costs ‘roughly commensurate’ with the allocation of benefits.”
“While multiple court decisions acknowledge the difficulty of measuring benefits to assess adherence to the cost-causation principle, courts ‘have never required a ratemaking agency to allocate costs with exacting precision’ and have not required, as a rule, ‘that the commission has to calculate benefits to the last penny, or for that matter to the last $1 million or $10 million or perhaps $100 million,’” FERC said, citing the D.C. Circuit Court of Appeals.
The commission also said there was a difference between local transmission facilities built to meet reliability standards, such as BRPs, and transmission projects in an RTO’s regional transmission expansion plans. BRPs wouldn’t be a good fit for competitive bids, FERC said.
“Because the issues that BRPs are designed to address are specific and localized, we find that complainants have not demonstrated that it is no longer just and reasonable for MISO to maintain its current BRP cost allocation method,” the commission wrote.
“Unlike the 2019 regional cost allocation order, the complaint does not allege that MISO’s BRP cost allocation method identifies BRP benefits and chooses to disregard them for purposes of cost allocation. Rather, complainants argue that the current BRP cost allocation method does not attempt to identify benefits outside the BRP’s local transmission pricing zone. However, we reiterate that complainants have not met their burden to show that the current cost allocation method does not result in an allocation of costs that is at least roughly commensurate with the distribution of benefits,” the commission said.
The complaint was met with mixed reactions earlier this year from MISO’s stakeholder community. Some said the complaint sought to circumvent the RTO’s stakeholder process. Others said it would be irresponsible to open reliability projects to competitive bidding. Others still said reliability is a state responsibility and argued that BRPs largely demonstrate only local benefits. Regulators from the Organization of MISO States largely opposed the complaint.
MISO itself argued that the LODF methodology is a measure of impacts rather than benefits.
The third time’s a charm for MISO getting FERC approval of its sweeping, cost-allocation overhaul for large economic transmission projects.
The commission on Tuesday accepted MISO’s proposal to lower the voltage threshold for market efficiency projects (MEPs) from 345 kV to 230 kV, add two new benefit metrics and eliminate the current 20% postage stamp allocation in favor of allocating full project costs to benefiting transmission pricing zones (ER20-1723).
In the latest iteration, MISO removed all mention of the local economic project category that FERC twice rejected. The small project type was a sticking point in the earlier filings because the commission took issue with a proposal to measure the value of such a project on a regional basis but cost-share only locally. The category was intended for smaller, economically driven transmission projects between 100 and 230 kV, in which 100% of costs would be allocated to the local transmission pricing zone containing the line. (See Local Projects Axed from MISO Cost Allocation Refile.)
Now such projects will again be consigned to MISO’s “Other Project” category, which has no regional benefits test and prescribes that smaller economically beneficial projects be allocated to the transmission pricing zone in which they are located.
In keeping with its previous orders, the commission found no problems with MISO’s plan to add new benefit metrics for savings if a project can reduce dependency on the RTO’s transmission contract path with SPP or eliminate needs for other reliability projects. The two new savings calculations will join MISO’s existing adjusted production cost savings metric in project evaluation.
| MISO
“We find that the cost allocation resulting from the application of the three benefit metrics will be more precise at determining benefits,” FERC said.
The new rules will also provide limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability.
Dairyland Power Cooperative argued that the 230-kV threshold is still too high and “unduly discriminates against areas of the MISO footprint that do not utilize the 230-kV voltage class.” The co-op said MISO was dismissing the idea that smaller transmission projects could deliver regional benefits. It said 2018’s Old Dominion Electric Cooperative v. FERC — in which the D.C. Circuit Court of Appeals ruled that FERC erred when it prohibited cost-sharing for a class of high-voltage projects that demonstrated significant regional benefits — should be applied as caselaw, even for lower-voltage facilities in MISO.
But the commission pushed back on that assertion, saying, “Unlike the situation in ODEC, neither MISO nor the commission … has made the finding that MISO projects between 100 kV and 230 kV produce ‘significant regional benefits.’”
No 100-kV Threshold
FERC declined another request for a 100-kV MEP threshold in a separate order issued the same day (EL19-79).
LS Power last June asked FERC to compel MISO to lower the threshold for competitively bid transmission projects from 345 kV to 100 kV and outline a procedure for identifying beneficiaries. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)
The company argued that “MISO’s transmission planning process fails to provide a path for development of regionally beneficial economic enhancements that do not currently qualify as [MEPs] and … this failure has resulted in unnecessary congestion costs and unjust and unreasonable rates.”
FERC pointed out that it just accepted MISO’s plan to lower the MEP voltage threshold to 230 kV. But even if it didn’t accept the allocation proposal, LS Power didn’t have a strong enough argument, the commission said.
“Although the concurrent … order lowers the market efficiency project voltage threshold to 230 kV, we nevertheless find that LS Power has failed to demonstrate that the then-existing 345-kV voltage threshold … and the current cost allocation method for economic other projects is unjust and unreasonable,” FERC said.
FERC said LS Power’s examples of hypothetical 100-kV projects that could benefit the footprint regionally also didn’t meet the burden of proof.
Commonwealth Edison officials apologized to the Illinois Commerce Commission, while ICC Chair Carrie Zalewski defended herself against conflict-of-interest allegations Wednesday in the wake of the company’s bribery scandal.
The ICC questioned ComEd officials for 90 minutes during its open meeting over the company’s agreement to pay a $200 million fine to settle allegations that it bribed Illinois House Speaker Michael Madigan (D) in return for legislation that increased the company’s earnings and bailed out parent Exelon’s money-losing nuclear plants.
The U.S. Attorney’s Office in Chicago filed a one-count information on July 17 alleging that ComEd arranged no-work jobs for Madigan associates including former Chicago Alderman Michael R. Zalewski, the father-in-law of the ICC chair, to influence legislation favorable to the company.
The allegations came several weeks after radio station WBEZ reported that it had obtained emails showing Madigan’s top aide recommended Zalewski for the ICC in December 2018, about four months before Gov. J.B. Pritzker named her to a five-year term as chairwoman. (See How ComEd Got its Way with Ill. Legislature.)
In opening remarks, Republican Commissioner Sadzi Martha Oliva said she was concerned by the “optics” of the hearing.
“I believe the allegations surrounding the bribery scheme may conflict with Chair Zalewski’s ability to do her job effectively by adversely affecting the confidence of the public,” Oliva said. “Holding this hearing in this manner is not good for the integrity of the commission while attempting to restore trust from ratepayers. I fear that not raising my concerns to the public and on the record makes me complicit in failing to restore the public’s trust.”
“I have not done anything wrong,” Zalewski, a Democrat shot back. “To suggest otherwise [is] both disingenuous and irresponsible. I perform my duties ethically, honestly [and] with integrity. I came from the [state] Pollution Control Board, where I earned that reputation for nine years — never been questioned.”
Public Comments
Several people also spoke about the scandal during the public comments section of the meeting.
Republican activist Jesus Solorio said Zalewski should resign or that her fellow commissioners should demand she recuse herself from any matters regarding ComEd, calling her a member of “one of the most politically connected families in Illinois.”
Republican activist Jesus Solorio calls for the resignation of ICC Chair Carrie Zalewski (center on dais). | Illinois Commerce Commission
Solorio said Zalewski’s husband, Democratic state Rep. Michael J. Zalewski, “received thousands of campaign contributions from Commonwealth Edison and voted for the legislation that we now know involved a criminal conspiracy orchestrated by Mr. Madigan and his friends. We also know that Commonwealth Edison gave Ms. Zalewski’s father-in-law a $5,000/month contract around the same time Mr. Madigan recommended Ms. Zalewski to be Commonwealth Edison’s regulator. We cannot pretend this cloud over the commission’s integrity is not a problem. We deserve more than empty assurances.”
Federal officials say ComEd’s bribes aided passage of the 2011 Energy Infrastructure Modernization Act (EIMA) — which approved a formula rate mechanism — and the 2016 Future Energy Jobs Act (FEJA), which authorized subsidies for Exelon’s Clinton and Quad Cities nuclear generators.
Illinois PIRG Director Abe Scarr | Illinois Commerce Commission
“In many ways, this corruption is not news. It’s been plain to see to anyone willing to look. ComEd and Exelon have used political power to corrupt utility regulation in Illinois,” said Illinois Public Interest Research Group Director Abe Scarr, who called for a “comprehensive audit” of the utility.
“Many benefits ComEd promised in EIMA have not arrived,” Scarr said. “Without proper examination, we have no way to know if customers are getting real value for the 40% increase in delivery rates they have paid since 2011 or if alternative investments would have brought more value at lower costs.”
Jeff Scott, associate state director for AARP Illinois, said FEJA should be repealed and EIMA — which he said guaranteed ComEd automatic rate hikes — allowed to expire. He also called on the state to repeal retail choice in response to the threat posed to nuclear and renewable generation by PJM’s expanded minimum offer price rule. (See Clock Ticking on Exelon Illinois Nukes Under MOPR.)
“Rather than create a new complicated capacity procurement mechanism on top of the already complicated PJM, Illinois should instead end retail choice and restructuring altogether, end deregulation and again allow the utilities to own generation fully regulated by the ICC with an open, transparent and honest planning process.”
ComEd Promises Reform
ComEd CEO Joe Dominguez said he was saddened that “a few” ComEd officials responsible for the bribery scheme tainted the work of thousands of utility workers who have continued to provide “world class service” despite the coronavirus pandemic.
“There are no excuses for our conduct, and I will offer none today,” he said.
Commonwealth Edison CEO Joseph Dominguez | Exelon
Dominguez said the deferred prosecution agreement ComEd signed did not allege that EIMA “was bad policy or the investments didn’t benefit customers.”
“I simply don’t agree that those investments were not carefully reviewed and were not deemed to be prudent in every measure for the customer. We’ve done studies about the cost-benefit analyses of things like the installation of smart meters and our energy efficiency programs.
“Residential customer bills today are less than they were 10 years ago. I want to emphasize that that is not adjusted for inflation … and if you were to adjust it for inflation, it’s 20% less than it was a decade ago.”
Critics have said lower bills are a result of lower wholesale power costs, not delivery-service rates, which are the only component covered by formula rates.
Dominguez said Exelon hopes to restore ComEd’s reputation by its hiring in March of former Assistant U.S. Attorney and former Securities and Exchange Commission Regional Director David Glockner as Exelon’s executive vice president of compliance and audit.
“I don’t think there is a person better suited” for the job, Dominguez said, citing Glockner’s “impeccable reputation.”
David Glockner, Exelon executive vice president of compliance and audit | Exelon
Glockner cited Exelon’s new policies regarding interactions with public officials and the vetting and monitoring of lobbyists and political consultants.
All employment and vendor referrals or requests from public officials must be tracked and referred to the utility CEO, general counsel and compliance department under the new rules. “The request can be approved only if everybody in that process signs off,” he said.
“There were policies that the company had that were in place that prohibited this sort of conduct that occurred here, but in retrospect, it’s clear that those policies alone weren’t enough and the interactions with public officials are an area where we need to give employees more detailed guidance. We need more controls and most importantly more eyes on decisions that are often difficult and where there can be a real risk of … misconduct.”
Glockner agreed to return to the ICC to discuss its compliance record. “We realize that there is a significant public trust deficit,” he said.
Dominguez assured the commission that ComEd would not seek to recover its $200 million fine or any of the questionable lobbyist spending and no-work jobs from ratepayers.
“The commission obviously is going to be exploring this issue for a while and take actions in the interests of ratepayers,” Zalewski said in closing the meeting.
Legal Bills
The chair’s husband has spent nearly $75,000 in campaign funds on legal services since his father’s home was raided by federal agents, radio station WBEZ reported last week.
“In early June 2019, I engaged Jones Day for legal counsel. I wanted to ensure legal compliance in case any investigatory agency sought my cooperation,” Rep. Zalewski said in a statement, declining to comment on whether he had been contacted by federal law -enforcement officials. “As several investigations are ongoing, I’ll have no further comment at this time.”
WBEZ said the state representative had been Madigan’s point man on negotiations for a gambling bill last year but relinquished his role after complaints that he was conflicted. WBEZ said a review of state lobbyist-disclosure documents showed Zalewski’s law firm had more than 30 clients with interests in gambling legislation the state.
Entergy on Wednesday reported second-quarter earnings of $361 million ($1.79/share), bettering 2019’s second-quarter performance of $236 million ($1.22/share).
When adjusted for nonrecurring items, such as the removal of Entergy Wholesale Commodities when it exits the merchant power business in 2022, earnings came in at $276 million ($1.37/share). (See Entergy Celebrates Sale of Final EWC Nuke.) Entergy’s results beat projections by Zacks Investment Research’s survey of analysts, who expected average earnings of $1.23/share.
“We delivered another strong quarter and remain on track to achieve our full-year objectives. Sales were better than expected; we’re on pace to achieve our cost savings target for the year; and our capital plan is unchanged,” Entergy CEO Leo Denault said in a press release.
Entergy CEO Leo Denault | Entergy
The New Orleans-based company is affirming its full-year guidance range of $5.45 to $5.75/share, pinning some of the projection on the petrochemical-heavy regional economy.
“While we have seen some slowdown in industrial activity, our industrial base is among the most economically advantaged in the world,” Denault told financial analysts during a conference call. “We expect it to lead the region’s recovery in their respective industries.”
Executives said Entergy could take an earnings hit of 15 to 20 cents/share following a FERC administrative law judge’s July decision recommending the commission return to ratepayers $147.3 million related to nuclear decommissioning tax deductions for the Grand Gulf Nuclear Station in Mississippi (ER18-1182).
The company’s stock price gained $1.45 during the day, closing at $104.12. The stock price is still down 11.7% for the year, having begun 2020 at $117.93.
ISO-NE‘s preliminary analysis suggests that summer demand from June 1 to July 11 was consistent with the 2020 Capacity, Energy, Loads and Transmission (CELT) forecast despite the economic impact of the COVID-19 pandemic on New England.
The RTO ran this year’s CELT models with numbers from Moody’s Investors Service’s June economic forecast in order to estimate how much the pandemic-related economic disruption might affect preparation for the upcoming 2021 CELT forecast, Load Forecasting Manager Jon Black told the New England Power Pool’s Power Supply Planning Committee on Tuesday.
“The main takeaway here, based on the first 41 days of the summer: I don’t see any real, systematic issues with the CELT 2020 peak forecast models, even at 183 MW of mean error for the highest peak demand days,” Black said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
The error represents less than 1% of the 2020 CELT 50/50 gross peak load forecast and does not indicate the forecast deviating from actuals in a systematic way, he said.
“We’ve seen a strong rebound in summer demand,” Black said. “Early on in the April-May time frame, when weather was mild, we did see relatively significant reductions in demand and energy, but from a summer peak perspective, we’re not seeing that throughout the first 41 days of summer.”
The results also align with those of ISO-NE’s recent weekly analyses of COVID-19 demand impacts, performed by the System Operations Department, Black said.
The RTO used the October 2019 (i.e., pre-COVID) Moody’s macroeconomic forecast in the development of CELT 2020 and expects to use the Moody’s October 2020 macroeconomic outlook to develop CELT 2021.
Graphing the Data
ISO-NE’s June baseline scenario assumed a 50% probability of worsening U.S. economic performance, no second wave of infections that would cause states to shut down again and nationwide confirmed cases of 2.4 million — with new infections peaking in April, a 6% confirmed case fatality rate and 10% hospitalization rate.
The downside scenario assumed a much higher-than-expected incidence of new infections and deaths in the latter part of 2020 causing businesses to reopen much more slowly than anticipated, with consumer spending not rebounding, especially in air travel, retail and hotel stays. It also assumed 4.1 million confirmed cases, new COVID-19 infections peaking in May, with 12% confirmed case fatality rate and 17.5% hospitalization rate.
Compared to the CELT 2020, the new expected (i.e., baseline) macroeconomic outlook results in a summer demand forecast that is approximately 113 MW lower in 2021 and 26 MW lower in 2025. However, consideration of a lower probability, greater downside economic risk scenario suggests greater summer demand impacts in 2021 (-232 MW) and 2025 (-127 MW).
Preliminary review of summer 2020 peak days gross demand forecast vs. actual (June 1–July 11) | ISO-NE
When compared to the October 2019 macroeconomic forecast used in the CELT 2020, the June 2020 forecast for regional gross state product (RGSP) is approximately 7% lower in the near term (2021) and recovers to 1.4% lower in 2024.
Black also noted the connection between how these assumptions are modeled and what the economic fallout of that is, saying it’s not just the COVID-19 stats that are important.
Regional gross state product (RGSP) forecast for New England | ISO-NE
“We’ll be getting the October vintage of this forecast for CELT 2021, just like we always do, so it will be interesting to see how different that outlook is three months from now,” Black said.
The deltas of both the baseline scenario and the greater downside potential scenario are within the realm of confidence bands for a long-term load forecaster, he said.
“The load forecast is the result of what we’ve been seeing year over year as time has marched on: that economics are driving demand lower, especially summer demand, from one CELT forecast vintage to the next,” Black said. “We have a much smaller margin of downside potential here, even with changes in the macroeconomic expectations.”
Citing an “increase in adversary capabilities and activity,” the National Security Agency (NSA) and the Cybersecurity and Infrastructure Security Agency (CISA) are warning critical infrastructure facilities in the U.S. to “take immediate actions” to secure operational technology (OT) assets against cyber threats.
In an alert issued last week, the agencies noted that OT assets capable of accessing the internet have become increasingly common across the 16 U.S. critical infrastructure sectors, including the energy industry. Because these systems interface with legacy OT assets that were not designed with malicious cyberactivity in mind, their spread — along with a decentralized workforce and outsourcing of instrumentation and control, OT asset management and maintenance and other key functions — has created a “perfect storm” of vulnerability that can be exploited by malicious actors, the agencies said.
Warning from Attack on Israel
While the alert did not mention any specific attacks against U.S. assets, it did link to a report from CyberScoop on a cyberattack against control systems at water facilities in Israel. That attack occurred in May and has been attributed to the government of Iran, though Israel’s government has not officially identified the culprits beyond stating that the crime did not appear to be motivated by profit.
According to NSA and CISA, attackers in recent incidents have commonly gained access to organizations’ information technology network through spearphishing attacks, then pivoted to accessing the OT network. Initial access may also be gained through internet-accessible control hardware that lack authentication requirements or through the use of exploits known to be common across hardware from the same vendors.
NSA headquarters in Fort Meade, Md. | National Security Agency
Once inside a utility’s systems, attackers usually deploy commodity ransomware to encrypt data on both networks. Impacts include loss of availability on the OT network and lockouts for human operators, leading to loss of productivity and revenue or even manipulation by the adversary that results in disruption to offline processes.
While utilities should aim to prevent attackers from entering sensitive systems in the first place, CISA and NSA also recommend developing a resilience plan to limit the damage done by actors who gain a foothold and turn control systems against their users. Elements of a successful resilience plan include:
the ability to disconnect systems immediately from the internet if they can operate safely without being online;
a plan for manual operation should industrial control systems (ICS) become unavailable;
removing unnecessary functionality that increases the risk and attack surface area;
maintaining secure, offsite backups for “gold copy” resources (firmware, software, ladder logic, service contracts and product information); and
testing and validating procedures for data loss from malicious cyberactivity.
Entities are also encouraged to rehearse their incident response plans frequently through tabletop exercises that include executive, public affairs and legal teams.
Pandemic Highlights Cyber Concerns
Cyberattacks have become a serious concern for the electricity industry in recent months because of the sudden expansion of the remote workforce during the COVID-19 pandemic. (See SolariumTeam Urges Long-term Cybersecurity Focus.) In a report earlier this year, NERC urged utilities to use the Electricity Information Sharing and Analysis Center and the Cybersecurity Risk Information Sharing Program to stay informed about the latest threats. (See PPE, Testing Top Coronavirus Concerns for NERC.)
National security officials also have been increasingly focused on cyber threats to the electric grid originating from foreign governments. In May, President Trump declared a national emergency regarding foreign threats to the bulk power system, which was followed earlier this month by information requests from NERC and the Department of Energy. (See NERC Issues Level 2 Supply Chain Alert.)
China and Russia are commonly seen as the biggest threats to the North American grid, though experts believe Iran has targeted the U.S. energy infrastructure as well. (See Iran Cyber Threat Increasing, Experts Say.) Cuba, North Korea and Venezuela are also considered potential threats.
In a press release, advocacy group Protect Our Power said NSA and CISA’s report “confirms the urgency” of the cyber threat against the BPS, along with the need for a coordinated response from all stakeholders.
“Addressing grid threats will require a combination of government funding and regulatory incentives encouraging utilities to invest in cybersecurity,” POP Executive Director Jim Cunningham said. “It is also critical that utilities and key government agencies continue to proactively share cybersecurity information so that all asset owners know about incoming attacks and effective best practices and resources to repel or mitigate those attacks. The grid is only as strong as its weakest link.”
The Utilities Technology Council (UTC), National Rural Electric Cooperative Association (NRECA) and American Public Power Association (APPA) asked the D.C. Circuit Court of Appeals on Monday to overturn the Federal Communications Commission’s ruling opening a portion of the 6-GHz band for unlicensed use.
The FCC’s April 24 ruling came over the objections of utilities, which say their communications in the spectrum could be disrupted by unlicensed use. (See Utilities Alarmed as FCC Opens 6 GHz Band to Wi-Fi.)
The commission said its ruling will allow the next generation of Wi-Fi — more than two-and-a-half times faster than the current standard — and an explosion of new uses in the “Internet of Things.” It said its ruling will nearly quintuple the amount of spectrum available for Wi-Fi, improving rural connectivity (Docket 18-295).
Microwave tower in the Mojave National Preserve, Calif.
Utilities contend that the commission failed to balance protection of critical communications in its desire to be innovative. They use the 6-GHz band for point-to-point microwave links providing communications with substations, fault sensors, two-way meters and service crews. It is also used to provide situational awareness in rural areas where wired networks are not available. Other critical infrastructure — such as police and fire dispatch, railroads and natural gas and oil pipelines — also use the spectrum.
The FCC insists that it will protect utilities by using automated frequency coordination systems (AFC) to prevent standard power access points from operating where they could cause interference to existing services. But utilities say AFC — which uses a “database lookup scheme” to ensure that unlicensed users are not encroaching on an existing user’s priority access to the frequency in a specific area — should be required for low-power devices also.
The petition by UTC, NRECA and APPA asks the court to find that the FCC acted unlawfully by permitting new devices into the band without sufficient safeguards and without considering numerous studies demonstrating the risk of interference.
“From the beginning of this proceeding, we urged the commission to fully vet and test its theories and assumptions that it could safely permit unlicensed users into a band already heavily used for public safety and essential electricity, water and natural gas services,” UTC CEO Sheryl Riggs said in a statement. “Existing users of the 6-GHz spectrum band offered study after study demonstrating that the FCC’s plan was flawed and needed to be revised so as to allow a thorough analysis to prove these new devices could operate without causing interference. We do not take this step lightly but feel that taking this matter to court is in the best interest of our members, our industry and the public.”
