The privately held Infrastructure Investments Fund (IIF) completed its acquisition of El Paso Electric (EPE) on Wednesday following a final regulatory check by the Nuclear Regulatory Commission, the companies said in a statement.
The statement came after FERC on July 22 approved EPE’s and IIF’s market power mitigation plan and rejected rehearing requests challenging the commission’s approval of the deal (EC19-120). (See FERC OKs El Paso Electric Mitigation.)
The commission in March approved the transfer to IIF of EPE’s license for the company’s share of Palo Verde, but it recently sent a letter to the organizations with questions about the ownership (STN 50-528, STN 50-529, STN 50-530, 72-44).
El Paso Electric owns 15.8% of the Palo Verde nuclear plant (pictured). The Nuclear Regulatory Commission had raised questions over the private Infrastructure Investments Fund’s foreign interests. |
NRC had questions about possible “foreign ownership, control or domination” of EPE’s 15.8% share in the renewed operating license for the Palo Verde nuclear plant in Arizona. On July 28, however, the agency said in a letter to the utility’s interim CEO that a previous order approving the transaction still stood.
Staff said that following a brief review, they had determined not to modify, suspend or revoke the order, but that “future changes to the … partnership agreement that affect the restrictions on passive limited partner investors may constitute an indirect transfer of control of the Palo Verde licenses that would require prior NRC approval.”
Scott Burnell, an NRC public affairs officer, told RTO Insider in an email that staff began reviewing the EPE and IIF responses July 27 to determine whether the agency needed to take further action on the transferred license.
Burnell noted that staff recently learned about the possible foreign ownership ties to IIF entities linked to the transaction through filings the private equity group made with the U.S. Securities and Exchange Commission and the Federal Communications Commission.
The company said July 29 that its new board of directors had appointed Kelly Tomblin as its new CEO. Tomblin joins the company after more than 30 years of leading utilities in the U.S. and internationally. She was most recently CEO of INTREN, a utility solutions provider with 14 regional offices across the U.S.
“EPE plays a critical role in the communities [it] serve[s], and I look forward to making this community my own,” Tomblin said in a statement.
EPE and IIF announced the transaction in June 2019. IIF is a $12.5 billion private investment vehicle advised by a dedicated infrastructure company investment group within J.P. Morgan Investment Management.
IIF is the umbrella name referring to the three master partnerships that hold all of its investments: IIF US Holding 2, IIF US Holding and IIF Int’l Holding. IIF US Holding 2 owns Sun Jupiter Holdings, which has formed a corporation to merge with EPE, with the utility as the surviving entity.
EPE shares disappeared from the New York Stock Exchange on Wednesday. The stock closed at $68.25 on Tuesday, up $1.85 since hitting $66.40 on July 20 before FERC’s final approval.
Grid operators preparing to incorporate distributed energy resources into their systems must be ready to address the resulting challenges to stability, according to a report by the Australian Energy Market Operator (AEMO).
In a webinar for members of NERC’s System Planning Impacts from Distributed Energy Resources Working Group on Tuesday, Jenny Riesz, a principal for operational analysis and engineering at AEMO, shared some insights from recent studies of the power grid in the state of South Australia.
Jenny Riesz, AEMO | NERC
The state is considered a good test case because of the high level of DER installation there, with more than two-thirds of minimum operational demand met by distributed photovoltaic resources in 2019. In addition, the region shares only a single AC interconnector with the rest of Australia’s National Energy Market, which separates from the rest of the grid periodically; this provides an opportunity to study the operation of the local grid in isolation.
“With all of the distributed PV coming in, operational demand is dropping fairly dramatically, and some of our forecasts predict that we could hit zero operational demand in that region within the next one to three years, or perhaps even become negative,” Riesz said. “So [it’s] very timely to start to understand what operational challenges are likely to arise [and] how do we actually operate a grid that’s [majority supplied] from distributed photovoltaics.”
PV Cut-outs Endanger Reliability
One of the main challenges presented by South Australia’s DERs has been frequent disconnection of distributed PV resources during disturbances to the power system. In a study of about 13,000 PV systems operated by individual consumers over several years, AEMO observed that voltage disturbances frequently led PV sites to disconnect from the grid, with more severe changes in voltage leading to more disconnections. In the most extreme case, a change of 0.9 V caused about 40% of PV sites to disconnect.
AEMO’s resource development outlook assuming a high install level for distributed energy resources through 2042 | AEMO
Disturbed by this behavior, which is forbidden by Australia’s reliability standards, AEMO partnered with the University of New South Wales (UNSW) and the Australian Renewable Energy Agency to test the inverters used in PV systems. The testing program confirmed that the problem is serious and widespread.
“They’ve now looked at a whole suite of different inverters and tested what they do when exposed to a deep voltage disturbance, and … around half of the inverters that we’ve tested do in fact disconnect when we expose them to a voltage disturbance,” Riesz said.
While the investigation is not complete, the utility believes the problem could arise from inverter manufacturers designing products thinking only of the tests they will have to pass rather than the standards they are intended to fulfill. As no manufacturers are currently required to test for voltage fluctuations, it is likely that this feature is overlooked, resulting in products that pass muster in the factory but are unfit for real-world conditions.
AEMO’s projections for maximum net PV disconnection in South Australia | AEMO
This shortcoming could have major consequences: In a simulation of a severe but credible fault in the Adelaide metropolitan area — where about 60% of South Australia’s PV sites are located — about 20% of underlying load and 40% of PV resources in the state disconnected. While this can be tolerated when PV resources are supplying a lower portion of the net load, when their share of the grid is higher, the sudden widespread loss of generation could be much more severe, particularly if the event is triggered by the loss of a large synchronous generator or the region is in an islanded state at the time.
“We’re now looking at something on the order of a doubling of the largest credible contingency that we have to plan for and manage,” Riesz said.
Long-term Solutions Under Development
The extent of PV disconnection is expected to decrease in the short term because of the addition of four large synchronous condensers in South Australia next year. However, with PV installations projected to continue their strong growth in the following years, longer-term solutions are urgently needed.
AEMO has several programs underway to address the issue. The most basic change is to revise the relevant reliability standard to require voltage ride-through testing. The operator is currently awaiting industry comments on the proposed revisions; in the meantime, it is negotiating with the state government to impose the new requirement at the local level.
Further tests at UNSW have also found a number of additional functions that are not being met by existing equipment; for example, more than 30% of tested inverters could not provide over-frequency droop functions under simulated real-world conditions. The operator is concerned that a broader program may be needed to ensure compliance with reliability standards at inverter manufacturers.
“We’re about to launch a major audit to start to understand if that is indeed what’s going on, and then we’ll be putting together a working group to understand how we’re going to improve compliance going forward,” Riesz said. “It’s quite a tricky issue, and there’s not very clear lines of accountability in terms of who should be monitoring and enforcing that.”
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.”
