Ameren Illinois Co v. Illinois Commerce Commission

• Court: Appellate Court of Illinois
• Decided: May 26, 2026
• Docket: 5-24-0164
• Status: Unpublished

Opinion

2026 IL App (5th) 240164-U NOTICE NOTICE Decision filed 05/26/26. This order was filed The text of this decision NOS. 5-24-0164, 5-24-0165, 5-24-0853, 5-24-0968, 5-25-0172 cons. under Supreme Court may be changed or Rule 23 and is not corrected prior to the IN THE precedent except in the filing of a Petition for limited circumstances Rehearing or the allowed under Rule disposition of the same. APPELLATE COURT OF ILLINOIS 23(e)(1).

FIFTH DISTRICT ______________________________________________________________________________

AMEREN ILLINOIS COMPANY d/b/a Ameren Illinois, ) Appeal from the ) Illinois Commerce Petitioner-Appellant, ) Commission ) v. ) ICC Docket Nos. 22-0487, ) 23-0082, and 24-0238 (cons.) ILLINOIS COMMERCE COMMISSION; THE ) CITIZENS UTILITY BOARD; ENVIRONMENTAL ) LAW & POLICY CENTER; VOTE SOLAR; SUNRUN, ) INC.; SOLAR ENERGY INDUSTRIES ASSOCIATION; ) COALITION FOR COMMUNITY SOLAR ACCESS; ) ILLINOIS SOLAR ENERGY ASSOCIATION; UNION ) OF CONCERNED SCIENTISTS; ILLINOIS ) INDUSTRIAL ENERGY CONSUMERS; NATURAL ) RESOURCES DEFENSE COUNSEL; ) ENVIRONMENTAL DEFENSE FUND; WALMART; ) INC.; FEDERAL EXECUTIVE AGENCIES; UNITED ) CONGREGATIONS OF METRO-EAST; AARP; ) PRAIRIE RIVERS NETWORK; ILLINOIS POWER ) AGENCY; THE PEOPLE OF THE STATE OF ) ILLINOIS AND COMMUNITY ORGANIZING AND ) FAMILY ISSUES, ) ) Respondents-Appellees. ) ______________________________________________________________________________

JUSTICE VAUGHAN delivered the judgment of the court. Justices Barberis and Boie concurred in the judgment.

ORDER

¶1 Held: The Illinois Commerce Commission’s orders reducing Ameren’s storm hardening investment in its refiled Grid Plan, disallowing Ameren’s request to include the Other Post-Employment Benefits asset in its rate base and setting Ameren’s rate on equity are affirmed where substantial evidence supported the orders.

1 ¶2 Petitioner, Ameren Illinois Company d/b/a Ameren Illinois (Ameren) seeks review of the

Illinois Commerce Commission’s (Commission) decisions in three consolidated Commission

appeals. Ameren contends that the Commission’s orders that reduced Ameren’s proposed budget

for subtransmission line hardening program, rejected Ameren’s request to include the other post-

employment benefits asset (OPEB) in its rate base, and setting Ameren’s rate on equity were

erroneous. For the following reasons, we affirm.

¶3 I. BACKGROUND

¶4 On July 21, 2022, the Commission, pursuant to section 16-108.18 of the Public Utilities

Act (Utilities Act), also known as the Climate & Equitable Jobs Act (Jobs Act) (220 ILCS 5/16-

108.18 (West 2020) (amended by Pub. Act 102-662 (eff. Sept. 15, 2021)), issued an order that

required each electric company serving more than 500,000 retail customers in Illinois to formulate

and submit a Multi-Year Integrated Grid Plan (Grid Plan) for Commission approval as required by

section 16-105.17(f) of the Utilities Act (220 ILCS 5/16-105.17(f) (West 2020)). The Commission

order, citing section 16-105.17(f)(2) of the Utilities Act (id. § 16-105.17(f)(2)), set forth numerous

requirements for the Grid Plan which was due no later than January 20, 2023.

¶5 Pursuant to the Jobs Act, the Commission was granted authority to modify a utility’s Grid

Plan to comply with the objectives set forth in section 16-105.17(f) of the Utilities Act. See Id.

§ 16-105.17(f)(5)(B). The Commission could approve, or modify and approve, a Grid Plan only

after finding that the Grid Plan reasonably incorporated input from the parties, was reasonable,

and in compliance with the section 16-105.17 objectives and requirements. Id. If those findings

could not be made, the Commission was required to reject the Grid Plan. Id. The Commission was

required to either approve (with or without modification) or reject the Grid Plan by December 15,

2 2023. Id. If the Grid Plan was rejected, the utility was required to refile its Grid Plan within three

months of the rejection. Id.

¶6 Ameren filed its Grid Plan and its Multi-Year Rate Plan (Rate Plan) (see Id. § 16-

108.18(d)) on January 20, 2023. In support of its Grid and Rate Plans, Ameren submitted numerous

pages of testimony and exhibits. Responsive, rebuttal, and sur-rebuttal evidence was submitted. 1

Evidentiary hearings were held before Administrative Law Judges Jessica Cardoni, Daniel Coultas

and Leslie Haynes (collectively the ALJs) on August 8, 2023, and again on August 24, 2023.

¶7 A. Ameren’s initial Grid and Rate Plans before the ALJs.

¶8 1. Ameren’s “storm hardening” project

¶9 Ameren’s initial Grid Plan included a subtransmission line hardening program known as

storm hardening in the corrective maintenance portion of its Grid Plan and requested $40.3 million

in its four-year budget for that program. Riley Adams, a senior manager of electric programs for

Ameren, provided testimony. Adams testified that his primary responsibility in that position was

to manage Ameren’s circuit and pole inspection programs, which inspected approximately 177,000

poles and 260 circuits annually. He explained that the $40.3 million budget would allow Ameren

to install a composite pole every fifth pole to support weaker and older poles. The purpose of the

composite pole installation was to prevent cascading collapses of subtransmission lines due to

significant high wind weather events like derechos and tornados, or extreme winter events that

resulted in ice loading on the lines.

1 Throughout these proceedings numerous entities entered their appearances. However, only those entities with relevant evidence or argument to the issues on appeal are addressed. Those entities included: (1) Commission Staff (Staff); the Attorney General (State); (3) Illinois Industrial Consumer, Federal Executive Agencies, Citizens Utility Board, United Congregations of Metro-East and Prairie Rivers Network (collectively known as IFCUP); and (4) Walmart. 3 ¶ 10 Adams explained that many of the previous poles placed by Central Illinois Public Service

Company (CIPS) were old and lower grade than composite poles. He further explained that

installing a composite pole every fifth pole would provide greater resiliency and reliability,

improve public and worker safety, and would be more cost efficient than fixing the problem after

the lines collapsed. He stated that an engineering review identified and ranked 66 of the CIPS lines

that had potential for cascading. Twenty of those lines were previously retrofitted and resulted in

only 4 poles, as opposed to 20 or 30 poles, cascading during a storm event. In addition to the

remaining 46 CIPS lines, additional lines outside the old CIPS area were identified as “potentially

benefiting from hardening.” Adams testified that if the project was rejected, Ameren’s customers

would “continue to experience cascading failures on un-hardened, older, subtransmission lines

during storms” that led to lengthy resulting outages and additional resources to restore. The $40.3

million plan would harden 153.5 miles of poles in 2024, 146.5 miles of poles in 2025, 146.1 miles

of poles in 2026, and 122 miles of poles in 2027. A list of the proposed areas, broken down by

region, was attached to Adams’s testimony. The projects were ranked with a reliability score that

had the higher number “being more urgent”, the number of customers impacted for each project,

the number of poles needed, the estimated cost, the general age of the line, the project scope and

the estimated cost per mile for each project. The reliability scores ranged from 33 to 73 with the

line age ranging from 1913 to 1993. The cost per mile ranged from $62,500 to $90,000. The list

also included the overall ranking and priority for “future” projects outside of the original 62 current

projects.

¶ 11 Adams’s testimony relied on a winter storm from December 2021 in Windsor, Illinois, that

resulted in the cascading of 29 subtransmission poles. He stated that it took 41 hours to restore

power and cost $763,000 to repair. Adams estimated that if the storm hardening had occurred prior

4 to the storm, power would only have been out for eight hours, and the cost of repair would have

been around $120,000.

¶ 12 Adams agreed that unpredictability of both the severity and location of the severe weather

caused by climate change was a valid concern but stated the June 2023 derecho further supported

Ameren’s position related to the benefits obtained from storm hardening. Adams testified that four

nonhardened Illinois projects located in Tolono, Taylorville, Mattoon, and Moweaqua, Illinois,

were affected by the 2023 derecho. He explained that the cascading poles in Tolono cost $286,000

to restore and would have only cost $40,000 to harden. The Mattoon poles cost $338,000 to restore

and would have cost $120,000 to harden, and the Moweaqua poles cost $468,000 to restore and

would have cost $80,000 to harden. He further stated that both Tolono and Moweaqua had been

on the project list and that the one previously hardened line had no cascading.

¶ 13 Staff proposed a $27.412 million reduction from Ameren’s requested $40.3 million. Staff

contended that Ameren’s recent experiences with the poles failed to support either the predictive

capability of Ameren’s efforts or that the proposal would produce material levels of savings in

restoration costs following cascading events. It claimed the cost-benefit analysis revealed that the

costs exceeded the benefit of the project. It noted that Ameren had the burden to show how the

additional expenditure optimized utilization of the electricity grid assets and resources to minimize

total system costs and asserted that Ameren failed to meet that burden.

¶ 14 Staff witness, Mark Lautenschlager, testified that Ameren usually only completed two line

hardening reinforcements a year and that Ameren’s current request was many times higher than

its historical effort. While Staff agreed that limiting cascading failure was a sound approach, it

complained that Ameren provided no basis for the increased pace from its previous history in fifth

pole reinforcement. Staff estimated that five anti-cascading reinforcements per year was sufficient.

5 It further noted that the Tolono lines were the only candidate for storm hardening in the first four

years of Ameren’s Grid Plan and “was below the midpoint of priority rankings among the 62

locations identified” in the attachment. Taylorville was on the “future” list. Staff also expressed

concerns with Ameren’s predictive capabilities in identifying the high-risk cascading locations. It

noted that even if one derecho occurred, the restoration costs from the derecho were substantially

less than the $40.3 million budget requested by Ameren.

¶ 15 The State argued that Ameren failed to provide clear identification of the scope of the work

which precluded any quantitative comparison of the project benefits to project costs. The State did

not recommend a reduction to a certain amount or certain number of projects per year. Instead, the

State requested that Ameren’s lack of supporting documentation be viewed as evidence of

Ameren’s deficient cost effectiveness approach and lack of transparency that justified limiting its

budget to historical levels plus inflation while leaving Ameren discretion to allocate investment

prudently and subject to review in the reconciliation proceeding.

¶ 16 On October 20, 2023, the ALJs found that the reliability benefits associated with storm

hardening were evident and supported the expansion of Ameren’s previous efforts. However, they

found insufficient evidence that such a major undertaking was necessary at this time. It found that

the Staff’s adjustment was appropriate noting that the adjustment would still increase Ameren’s

historical efforts and prioritize hardening the circuits at the greatest risk. The ALJs opined that a

more significant expansion might be justified when data from the current four-year period was

available. As such, the ALJs modified Ameren’s requested $40.3 million budget for storm

hardening to $12.903 million over four years.

6 ¶ 17 2. Inclusion of OPEB 2 in the rate base.

¶ 18 Ameren evidence revealed that it maintained an OPEB trust used to fund its OPEB

obligations. It stated that its obligations were protected by federal law designed to prevent misuse

of the funds dedicated to employees who earned the benefits during their previous employment.

Funding for the Ameren OPEB trust was an expense met by ratepayer funds, supplements from

shareholders, or positive investments of the original funds. Ameren stated that its OPEB trust was

severely underfunded in 2011. Ameren averred that its shareholders made a $100 million deposit

in August 2011 into the OPEB trust. In support of the claim, Ameren filed a copy of a $100 million

treasury request for electronic payment from Ameren Corporation to a bank account of the same

name on August 10, 2011. The description read “AIC Retiree VEBA Contributions August 2011.”

At the time Ameren filed its Grid and Rate Plans, the OPEB trust was overfunded, i.e., it had more

money than necessary, and OPEB was no longer a liability, but was an asset or contra-liability of

Ameren. Ameren’s Rate Plan included the OPEB asset in its rate base calculation.

¶ 19 Ameren submitted the testimony of Ronald Stafford, the Director of Regulatory

Accounting at Ameren. Stafford explained that pension and OPEB expenses for retired employees

were identified as a non-service related cost, while the same categories for active employees were

identified as service-related costs. He explained that the non-service costs attributable to retirees

were negative in each of the test year periods and those costs were not expenses in Ameren’s

Federal Energy Regulatory Commission (FERC) Form 1. He explained that “the ratemaking

adjustment to remove the negative retiree expense for employees retiring from the

production/power supply function results in no adjustment to rate base and an increase in operating

2 OPEB is the anachronym for Other Post-Employment Benefits which are non-pension benefits Ameren provides to retired employees consisting primarily of retiree medical benefits. 7 expenses.” He then explained how the amounts were forecast and described the adjustment for

pension and OPEB non-service expenses, stating, “Pension and OPEB non-service expenses are

recorded to non-operating income in the test year forecast to align with SEC reporting. Schedule

C-2.15 presents an adjustment to include these expenses in operating expense Account 926

consistent with ICC/FERC reporting.” Stafford further testified that Ameren included an

adjustment to rate base for the OPEB contra-liability which was consistent with the Commission’s

treatment of OPEB in 13 previous cases from 2009 and from 2012 to 2022.

¶ 20 Stafford provided additional testimony to respond to Staff and the State’s witnesses who

disputed inclusion of OPEB in the rate base. Stafford testified that over time the fund became “a

mix of two components: 1) contributions funded by customers and associated market returns, and

2) contributions funded by shareholders and associated market returns.” He testified that Staff’s

comments did not account for the second component stating that,

“[I]n 2011 *** Ameren Illinois made a $100 million contribution to the

OPEB fund sourced from shareholder funds (and above the annual OPEB accrual

expense level at which Ameren Illinois funds the OPEB plan), because the OPEB

plan was under funded for a number of years. Thus, this $100 million along with

the market returns on this amount are shareholder funded”

and should be included in the rate base. Stafford continued stating,

“In addition, the over-funded OPEB plan has, for accounting purposes,

generated gains resulting in negative OPEB expense (which is credited to

ratepayers) since 2016. What this indicates is that the fund is generating sufficient

returns to cover current accrued expenses. Customers have received the benefit of

this negative expense in the form of a cumulative reduction in the annual revenue

8 requirement. But because Ameren Illinois cannot withdraw funds from the OPEB

Trust to cover the negative expense paid to customers, this reduction in the annual

revenue requirement is effectively funded by shareholders. So in essence, the

customer is receiving the OPEB fund market returns in excess of current and

ongoing anticipated expenses and shareholders are making a contribution to the

OPEB fund in an equal amount. Absent Rate Base treatment of both the

contributions made by shareholders and the market returns on those contributions,

customers inappropriately receive a double benefit: the benefit of the negative

expense and the continued growth of the OPEB asset because the cash cannot be

accessed.”

¶ 21 Stafford explained that the OPEB expense was negative because the fund’s investments

were performing well. “A negative OPEB expense typically results when the expected return on

plan assets exceeds interest cost on the OPEB benefit obligations, the cost of benefits earned during

the year, and amortization of historical gains and losses.” Stafford further explained that when

OPEB expenses were positive it would increase Ameren’s operating expenses for purposes of

calculating the revenue requirement; however, when it was negative, the accounting decreased

Ameren’s operating expenses. He noted, however, that a negative OPEB expense was not a

reduction in the actual cash expenditures Ameren incurred to operate its business.

¶ 22 Stafford testified that under federal law, surplus assets removed from the OPEB Trust to

reimburse the utility for the reduction in revenue would be subject to a 100% excise tax, thereby

effectively prohibiting any withdrawal not associated with payment of retiree benefits. Therefore,

the inclusion of negative OPEB expense in rates reduced Ameren’s cash flow because the cash

expenditures for operations did not decrease. Beginning in 2016, the negative OPEB expense

9 resulted in Ameren lowering rates to reflect the negative expense. The lowered rates had a

cumulative credit of $146.4 million that equated to a rate reduction benefit of $93.122 million

during the four-year period. Ameren could not recover the rate reduction from the OPEB trust, so

the Ameren shareholders also funded the cash flow reduction.

¶ 23 Stafford testified that the Commission’s treatment of OPEBs was important because

Ameren was in an unusual situation with respect to these costs, at the outset of the Rate Plan. He

further stated that using formula rates, 3 Ameren included the over-funded balance of the OPEB

plan in rates as a contra-liability, which was a reasonable balance between the interests of

Ameren’s customers, its retirees, and the utility.

¶ 24 Stafford stated that Staff’s proposed disallowance of the over-funded balance from rate

base would penalize Ameren for prudent management of the OPEB trust over the last decade. By

denying Ameren the opportunity to include the over funded balance in rate base, Ameren was

being penalized for bringing the plan to a fully funded status. He stated that disallowing the asset

from the rate base would further penalize Ameren because Ameren was crediting ratepayers for

the overfunded status thereby reducing rates for the customers but had no way to restore the

cashflow lost due to the reduced rates which left the shareholders bearing the burden of the credits.

¶ 25 Stafford stated “at least a portion of the overfunded balance” were sourced by shareholder

funds. He stated that Ameren’s contribution was recognized in the Commission’s order in Ameren

Illinois Co., Ill. Comm. Comm’n No. 11-0282 (Order-Final Jan. 10, 2012) (Docket No. 11-0282).

Stafford also addressed the Commission decision in Ameren Illinois Co., Ill. Comm. Comm’n No.

3 Formula rates were part of the 2011 Energy Infrastructure and Modernization Act (EIMA), enacted by Public Act 97-616 (eff. Oct. 26, 2011) (adding 220 ILCS 5/16-108.5), amending the Utilities Act. See 220 ILCS 5/16-108.5(c) (West 2022); see also People ex rel. Raoul v. Illinois Commerce Comm’n, 2021 IL App. (1st) 200366 ¶ 7. Sections 16-108.5(c)(4)(B), (D), and (k)(3) of the EIMA specifically authorized inclusion of pension and OPEB expenses in the formula. See Id. §§ 16- 108.5(c)(4)(B), (D), (k)(3). 10 20-0308 (Order-Final Jan. 13, 2021) (Docket No. 20-0308). Stafford explained that the focus in

that case was Ameren’s proposal to share the customer benefit of the negative OPEB expense and

the adverse impact of reduced cash flow on the utility between the utility and the customers. Here,

Stafford believed that Ameren should be permitted to include the $191.722 million OPEB over-

funding in the rate base.

¶ 26 Staff recommended that the Commission reduce the rate base for the OPEB contra-liability

for all four years because “Ameren ha[d] not demonstrated that the OPEB asset was created with

shareholder funds, warranting a return on rate base.” Staff further argued that while section 16-

108.5 of the EIMA (see 220 ILCS 5/16-108.5(c)(4)(B), (D), (k)(3) (West 2022)) specifically

authorized recovery of pension and OPEB costs, the same recovery was not specifically authorized

by the Jobs Act, which was the statutory basis of the Grid and Rate Plans. Staff disagreed that any

of the cases cited by Ameren were relevant because the ones from 2009 were based on OPEB

liability and the cases from 2012 through 2022 were based on the EIMA. Staff opined that without

specific language in the Jobs Act allowing pension and OPEB inclusion, neither should be allowed

in the rate base. It further asserted that prior case law also supported its claim that when insufficient

evidence was presented to show that shareholders created the OPEB asset, it should not be

included. Staff noted that the Commission decision in Docket No. 11-0282 rejected inclusion of

OPEB liability and the Commission decision in Docket No. 20-0308 rejected inclusion of OPEB

contra-liability in the rate base after specifically finding that the OPEB asset was funded by

ratepayers.

¶ 27 IFCUP recommended the Commission accept Staff’s adjustments to the OPEB contra-

liability, i.e., denying inclusion of the OPEB contra-liability in its entirety. IFCUP stated this

11 would reduce revenue requirement by $8.93 million in 2024, $10.66 million in 2025, $12.13

million in 2026, and $13.66 million in 2027.

¶ 28 On October 20, 2023, the ALJs found that Ameren’s request to include OPEB contra-

liability in the rate base was “inconsistent with Commission practice and law” and therefore was

contrary to the Jobs Act requirements. See 220 ILCS 5/16-108.18(d)(3)(A) (West 2022). They

noted that Ameren’s evidence as to whether the OPEB overpayments were sourced from

shareholders was the same as the evidence that was rejected in Docket No. 11-0282. The ALJs

further found that how the EIMA dealt with pension assets was irrelevant because the EIMA was

replaced with the Jobs Act which did not contain similar provisions. The ALJs noted that Ameren’s

argument for contra-liability in the rate base was previously rejected in Ill. Commerce Comm’n

On Its Own Motion, Ill. Comm. Comm’n No. 20-0309 (Order-Final June 18, 2020). It stated the

Commission could balance the interests of ratepayers and shareholders as required by United

States Supreme Court law but could also prohibit shareholders from profiting off ratepayers’

money.

¶ 29 3. ROE

¶ 30 Ameren provided much testimony about its requested rate on equity (ROE). The testimony

was provided by Ameren witness Dylan D’Ascendis, who used a utility proxy group to calculate

the ROE because Ameren was not a publicly traded company. The utility proxy group was

comprised of 14 companies that were based on his screening criterion. Ameren’s proposed ROE

considered three models comprised of discounted cash flow (DCF), risk premium model (RPM)

and capital asset pricing model (CAPM), which D’Ascendis then applied to the utility proxy group.

The constant growth DCF was calculated at 9.58%. The RPM was calculated at 11.43% and

11.23% respectively, based on projected and current interest rates. The CAPM analysis determined

12 the ROE at 11.26% at the current and projected interest rates. After applying the model values to

the utility proxy group, D’Ascendis stated the equity rate was 9.95% and 10.95% using current

interest rates and 10.02% and 11.02% based on projected interest rates. Ameren then applied

adjustments for credit risk (downward adjustment of 0.05%) and flotation costs (upward

adjudgment of 0.07%) and determined its fair and reasonable ROE was 10.50%.

¶ 31 Ameren also argued against the Staff’s proposed ROE contending that the Commission

could not employ the EIMA-mandated formula for a proceeding that was conducted under the Jobs

Act. It further argued that Staff failed to demonstrate that the 580 basis points added was sufficient,

the Rate Plan was not the functional equivalent of the EIMA formula rate, and Staff’s proposal set

the starting ROE too low.

¶ 32 Staff recommended an ROE of 8.914% using the formula rate plan under the EIMA. The

formula cost of equity was calculated as the sum of

“(A) the average for the applicable calendar year of the monthly average

yields of the 30-year U.S. Treasury bonds published by the Board of Governors of

the Federal Reserve System in its weekly H.15 Statistical Release or successor

publication; and

(B) 580 basis points.” 220 ILCS 5/16-108.5(c)(3) (West 2022).

Staff argued that the average U.S. Treasury Bond yielded 3.114% plus 580 basis points, equating

to 8.914%. Staff contended that Ameren’s electric distribution operations carried significantly less

risk under the formula rate plan and would continue to do so under the Rate Plan than under

traditional ratemaking. It stated that Ameren’s financial ratios remained strong, and its credit

ratings maintained a stable outlook under the formula rate plan, further supporting its usage.

13 ¶ 33 Staff argued that Ameren’s requested 10.50% ROE was significantly overstated. Staff

noted that IFCUP witness Christopher Walters agreed with Staff and recommended a 9.30% ROE.

Staff further noted that Walmart witness Alex Kronauer recommended nothing higher than 9.13%.

After addressing Discounted Cash Flow (DCF), Non-Constant Discounted Cash Flow (NCDCF)

and Capital Asset Pricing Models (CAPM), Staff argued that Ameren’s rate of return was less

risky than for those in Ameren’s utility proxy group due to changes in the ratemaking process in

Illinois, further noting many cost recovery riders allowed for recovery of certain revenues or

expenses outside of the Commission-authorized revenue requirement.

¶ 34 The State requested that the ALJs reject Ameren’s requested 10.5% ROE and adopt the

8.91% ROE recommended by Staff. The State noted that Ameren’s current rates were 7.852% in

the filing year and 7.782% for the 2021 reconciliation year. The State also relied on Walmart

witness Kronauer, who claimed that the requested increase would increase rates solely to increase

revenues to the shareholders. While acknowledging that return on equity was a key factor in any

rate case, the State, citing section 16-108.18(d)(3)(B) of the Jobs Act (220 ILCS 5/16-

108.18(d)(3)(B) (West 2022)) noted that the cost of equity approved should be consistent with

Commission practice and law and recommended continued use of the EIMA formula rate method

despite the lack of direction requiring the Commission to adopt a formula rate in the Jobs Act. The

State further argued that the “comparable” utilities proxy group relied upon by Ameren failed to

contain, in reality, comparable utilities, and therefore, Ameren’s proposals resulted in widely

disparate results. It further asserted that Ameren’s claim of non-competitive ROEs were simply

complaints that the ROE rates were lower than they liked because the evidence revealed that

Ameren had no issues attracting increased amounts of capital, and there was no evidence of

damage to Ameren’s financial integrity.

14 ¶ 35 IFCUP recommended the Commission adopt the testimony of its witness, Walters, who

recommended 9.30% ROE stating that it achieved the careful balance of shareholder and consumer

interests required by law. Walters used several models and applied them to the utility proxy group.

He found the rates for each formula as follows: constant growth DCF average 9.54%, constant

growth DCF median 9.77%, quarterly grown DCF average 9.54%, quarterly DCF median 9.77.

sustainable growth DCF average 8.67, sustainable growth DCF median 8.14%, multi-stage growth

DCF average 8.32%, multi-stage DCF median 8.33%, risk premium, and CAPM, and applied them

to the utility proxy group. Based on the DCF models, risk premium and CAPM, Walters obtained

respective ROEs of 9.1%, 9.90%, and 9.40%. Given the shift in risk, he recommended an ROE of

9.30%. IFCUP further requested rejection of AIC’s requested 10.5% ROE stating it “drastically

overstates the Company’s cost of capital and would impose exorbitant costs on ratepayers for no

purpose other than to increase [Ameren’s] profit margins.” It further argued that Ameren’s

proposed 10.5% ROE was excessive due to flaws in the calculations and the fact that some requests

were contrary to Commission precedent.

¶ 36 Walmart recommended an ROE no higher than 9.13% and opposed Ameren’s requested

10.50%. Walmart noted that Ameren’s ROE under section 16-108.5(c)(3)(A) of the EIMA (220

ILCS 5/16-108.5(c)(3)(A) (West 2022)) would be 7.85% and that Ameren’s requested ROE was

265 basis points above what would have been authorized under the EIMA. Walmart witness

Kronauer assessed the unreasonableness of Ameren’s requested rate, noting the use of forecasted

test years reduced risk to shareholder, as well as the recent ROEs awarded by other state regulatory

commissions.

¶ 37 The ALJs first addressed whether the EIMA formula rate remained applicable to cases

under the Jobs Act. It determined that it did not because the formula rate did not allow the

15 Commission to interpret evidence and eliminated the Commission’s broad discretion for setting

ROEs. The ALJs further noted the inconsistency in Staff’s position between this issue and that

regarding the OPEB asset, i.e., the EIMA is either relevant for everything or nothing. The ALJs

further found the utility proxy group of little value. The ALJs rejected the DCF proposals from

Ameren and IFCUP because they used outdated stock prices but found Staff’s proposed average

constant growth DCF and NCDCF ROE of 9.17% acceptable. The ALJs rejected Ameren and

IFCUP’s use of risk premium analyses because historical data was not a reasonable predictor for

future behavior. As to CAPM, the ALJs adopted Staff’s risk-free rate of 4.19%, its average

monthly beta of 0.705, and a MRP that was 7.53 which resulted in a CAPM of 9.50%. The ECAPM

provided by Ameren was rejected due to historical Commission disfavor of the model.

¶ 38 The ALJs also addressed adjustments recommended by Ameren based on size, credit risk

and flotation costs. It rejected the adjustments for size and flotation costs but adopted Ameren’s

downward adjustment of 0.10%. The ALJ’s unadjusted ROE was an average of Staff’s DCF and

NCDCF of 9.17% and the ALJ’s calculated CAPM of 9.50%, which equated to 9.34% ROE. The

ALJ’s then applied the downward credit risk adjustment of 0.10% to allow an ROE of 9.24%.

¶ 39 B. Ameren’s initial Grid and Rate Plans before the Commission

¶ 40 Ameren, Staff, and nearly all of the intervenors filed statements of exception with the

ALJs’ proposed order. The Commission issued a final order on December 14, 2023. Therein, the

Commission rejected Ameren’s Grid and Rate Plans. The Commission set a tentative Rate Plan

until Ameren’s revised Plans were filed. As to the issues raised on appeal, the parties’ arguments

and Commission’s findings and conclusions are set forth below.

16 ¶ 41 1. Storm Hardening

¶ 42 Ameren requested that the Commission reject the ALJs disallowance of $27.4 million of

its proposed budget for the project. It claimed the decision was based “on a limited and unclear

criticism” of Ameren’s evidence that included “recent experiences with extreme weather that

demonstrate[d] the urgent need for, and significant benefits of, this work.” It requested the

Commission fully fund the project because it would make the grid more reliable, resilient,

affordable, safer and better prepared for clean energy future. It further argued that not funding the

proposal might “lead to significant consequences for customers for affordability, reliability, and

safety.” Ameren contended that the ALJs order failed to fully account for the significant

affordability, reliability, and safety benefits that the storm hardening provided. It addressed the

evidence related to the cost of storm hardening and the cost of repair following a major storm.

Ameren claimed the ALJs decision to reconsider the issue in the future based on data and evidence

that would come from the period of the current Grid Plan was “improperly and prematurely

restrictive” given that the order recognized that there was “no consensus on how cost effectiveness

should be established for this kind of work.” Ameren requested the Commission find the originally

requested $40.3 million budget was reasonable.

¶ 43 Staff did not specifically address the storm hardening project in its initial brief. However,

its reply brief requested rejection of Ameren’s requested increase. It agreed that the evidence

showed reliability benefits related to storm hardening but argued that Ameren failed to demonstrate

achievable benefits from the locations proposed. It also contended that Ameren did not have the

ability to identify cascading locations with sufficient accuracy to justify the expenditure of $40.3

million.

17 ¶ 44 The State did not address the reduction in its initial brief. However, its reply brief agreed

with the ALJs’ order finding that Ameren failed to demonstrate the need to accelerate storm

hardening spending. It requested affirmation of the ALJs $27.412 million reduction from the $40.3

million requested. It argued that based on Ameren’s cost of repair, the total amount requested

would be sufficient for 40 years of repair, as opposed to 4 years of storm hardening when the

locations of necessity were never shown.

¶ 45 The Commission agreed with the rationale for Staff’s adjustment to Ameren’s proposed

budget. It stated that Ameren’s evidence showed reliability benefits associated with line hardening

and further supported expansion of Ameren’s current line hardening efforts. However, the

Commission stated that it was not clear from the evidence presented that the significant increase

in capital spending on line hardening projects was necessary to sustain and increase Ameren’s

system reliability. Therefore, it was not clear to the Commission that the benefits achieved under

Ameren’s proposal justified the significant cost. The Commission further stated that because

Ameren’s Grid Plan was rejected it would determine the appropriate budget upon approval of a

refiled Grid Plan.

¶ 46 2. Inclusion of OPEB in the rate base.

¶ 47 Ameren argued that the Commission should reject the ALJs’ removal of Ameren’s OPEB

asset from the rate base. It claimed the order failed to address the merits of Ameren’s actual

proposal which provided ratepayers the benefit of negative OPEB expense credits in the amount

of $93 million, assured retirees of a fully funded plan, and compensated Ameren for its capital

outlay and inability to access OPEB funds. Ameren argued that this would more accurately balance

the interests of the customers and the interest of the investors. Ameren also argued that the ALJs

reliance on City of Alton v. Illinois Commerce Comm’n., 19 Ill. 2d 76, 84 (1960) was misplaced

18 because Ameren could not access the funds in the OPEB trust. It further disputed the ALJS’s

finding that the $100 million contribution was not from the shareholders, arguing that previous

Commission decisions never issued any such finding. Ameren also contended that even if the $100

million was not a shareholder contribution, Ameren’s shareholders funded the OPEB expense

credit to customers because operating costs were less than Ameren received from its rates and the

shortcoming was met by the shareholders.

¶ 48 Staff did not address the OPEB issue in its initial brief but recommended continued

disallowance of the contra-liability from the rate base in its reply brief. It argued that the Jobs Act

did not have specific language allowing Ameren to recover a rate of return on the asset. Staff

argued that the ratepayers were responsible for the OPEB expenses and paid those expenses and

therefore they were entitled to receive the credit for negative OPEB expenses. It further argued

that Ameren was attempting to relitigate the issue of shareholder outlay when it was previously

determined that the OPEB liability was a source of cost-free capital to Ameren provided by

ratepayers. It argued that the ALJ correctly rejected Ameren’s request for inclusion because a

public utility in Illinois may not receive a return on investment from ratepayers or ratepayer

supplied funds.

¶ 49 The State did not specifically address OPEB and the rate base in its initial brief. However,

in its reply brief, the State requested the Commission disallow inclusion of the OPEB contra-

liability in the rate base.

¶ 50 The Commission found that Ameren’s proposal to include its OPEB contra-liability in the

rate base was “inconsistent with Commission practice and law”, as required by section 16-

108.18(d)(3)(A) of the Jobs Act. 220 ILCS 5/16-108.18(d)(3)(A) (West 2022). Absent a specific

directive, which the Jobs Act did not have, a determination of rate base must be “prudently incurred

19 and reasonable in amount.” In arguing that its OPEB asset must be included in rate base, Ameren

consistently stated the Commission should consider “new evidence” and pointed to the copy of the

$100 million transfer. However, the Commission found that Ameren failed to demonstrate that the

$100 million to the OPEB fund was sourced from shareholder funds. The Commission noted that

this was the same contribution it considered and rejected in a previous docket. The Commission

further noted that while there was no dispute that a $100 million contribution was placed into the

OPEB trust in 2011, no evidence has been provided that the source of the contribution was

shareholder funds rather than ratepayer funds, nor how much should be apportioned to Ameren

gas versus Ameren electric operations. The Commission also noted that the balance in the OPEB

Trust, after the $100 million contribution in 2011, remained an OPEB liability (not an OPEB

asset), which the Commission also disallowed from the rate base in 2011 in Docket No. 11-0282.

¶ 51 The Commission also rejected Ameren’s EIMA argument stating that Ameren ignored the

fact that the EIMA was later amended to add statutory language related to pension and OPEB

assets (see 220 ILCS 5/16-108.5(c)(4)(D) (West 2022)). It noted that this case was not an EIMA

filing, it was a Jobs Act filing. It further noted that the Jobs Act did not include similar language

as the EIMA and if the legislature wanted to include the language, they knew how to do it. The

Commission agreed with Staff that the OPEB contra-liability had never been considered a

regulatory asset, and the Commission need not reiterate the myriad of cases cited by Staff that

were consistent with that decision. The Commission further noted that it rejected a similar

argument from Ameren in Docket No. 20-0308.

¶ 52 The Commission also rejected Ameren’s alternatives because Ameren continued to treat

OPEB contra-liability as a rate base asset or suggested removing the contribution. The

Commission noted that it never separated funds from a pension asset and then treated the portions

20 differently because federal law required the asset to be considered as a whole. The Commission

further noted that case law disallowed a return on funds based on utility customer payments

without additional investment by the stockholders. The Commission also noted that because

Ameren failed to provide sufficient evidence on which to determine a rate base given the rejection

of Ameren’s Grid Plan, the Commission determined that the rate base for all test years would be

based on the Ameren’s last-approved revenue requirement in Ameren Illinois Co., Ill. Comm.

Comm’n No. 23-0320 (Order-Final Nov. 30, 2023) (Docket No. 23-0320). 4

¶ 53 3. ROE

¶ 54 Ameren requested the Commission modify the ALJs’ order to approve an ROE of 9.85%

which it stated was “well below the 10.50% ROE” previously rejected by the ALJs. Ameren stated

that it was making the proposal to “protect its credit ratings and its ability to achieve the goal of

CEJA” claiming both were at risk by the ALJ’s “radical departure” from Commission practice.

Ameren further asserted that the ALJs’ order manipulated the record evidence “to recommend the

lowest Illinois non-formula ROE in recent memory” during “a time of volatile and rising interest

rates.” Ameren noted that the ALJs’ order rejected, in large part, all three expert opinions and in a

novel maneuver performed its own CAPM calculation using averages of data from Staff and

IFCUP. Ameren then complained that the ALJs made a credit risk assessment reduction, noting

that the 9.24% ROE was “nearly 50 basis points lower than the EIMA formula.” Ameren claimed

the ALJs’ decision was “frequently inconsistent with the substantial weight of the evidence” and

disputes the conclusion that the resulting ROE satisfied the requirements set forth in U.S. Supreme

Court precedence because there was no analysis of actual returns for investments of comparable

4 It is important to note that the decision in Docket No. 23-0320 was under the EIMA and therefore allowed for inclusion of pension and OPEB responsibilities in the rate base. 21 risk or consideration of the effect of the ROE on Ameren’s cash flow or credit ratings. Ameren

claimed that ALJs’ decision was also inconsistent with Commission practice and law by failing to

recognize the non-competitive nature of the ROE. Ameren disputed the ALJs’ use and reliance on

the NCDCF, claimed the ALJs manipulated the CAPM, and used the wrong adjustment for risk.

Ameren requested the Commission set the ROE at 9.85%.

¶ 55 Staff argued that the Commission should determine the ROE by using the formula from

the EIMA, which would set the ROE at 8.914%. Staff contended that use of the EIMA formula

was consistent with Commission practice and law. It agreed with the State, which believed the

ALJs’ interpretation of the ROE statute was too narrow and read into the statute a nonexistent

restriction on the Commission’s discretion to determine the appropriate ROE. Staff argued that

Ameren’s rates were set pursuant to the EIMA formula for a decade and employing the formula

ensured that Ameren’s ROE for the four-year Rate Plan would meet constitutional and statutory

requirements. It stated with Ameren’s current financial health and outlook, the traditional models

inflated the ROE well beyond the return that an investor would reasonably expect from a similarly

situated utility. It further noted that the EIMA formula was sufficient to sustain Ameren’s financial

health.

¶ 56 IFCUP stated that it supported the ALJs ultimate conclusion adopting a 9.24% ROE.

However, it disagreed with the ALJs’ conclusion related to RPMs that found the use of historical

data per se unreasonable. IFCUP argued that the finding was inconsistent with the use of historical

data in other parts of the ROE analysis section.

¶ 57 The State did not directly address the ROE in its initial brief. However, its reply brief

requested rejection of Ameren’s request to increase the ROE to 9.24%. In response Ameren’s

claim that it was too low and non-competitive, is merely an assumption of the results and was not

22 based on evidence. The State further noted that Ameren’s claim of difficulty attracting capital at

that rate was contradicted by recent history where Ameren’s ROE was 200 basis points lower than

the gas ROE and further was able to attract “hundreds of millions of dollars for plant additions”

by their own admission. The State noted that in 2021 and 2022, Ameren’s electric ROE was 8.38%

and 7.36% respectively and was able to attract enough capital to double its annual spending from

2012 to 2020 and increase it further from 2021 to 2023. The State argued that the 9.24% ROE was

adequate to meet U.S. Supreme Court requirements.

¶ 58 Walmart argued that the ALJ decision incorrectly stated its ROE recommendation. It noted

that ALJ’s decision had a Walmart recommendation of an ROE no greater than 9.13%. However,

Walmart recommended no higher than 9.14% as the ROE. It further argued that the ALJ’s decision

failed to recognize the relevance of Walmart’s evidence and the customer impact as it related to

the 9.24% ROE and requested that the relevance be noted in the decision.

¶ 59 The Commission noted that Ameren’s risk under the Rate Plan would be lower than under

both the EIMA formula and traditional ratemaking. The Commission stated that the Jobs Act

neither required nor prohibited the use of the formula rate plan that was used to determine ROE

for the past 11 years. The Commission stated that it had broad discretion to determine just and

reasonable rates and the methods to determine the rate of return reflected in such rates. Therefore,

the Commission agreed that it could use the formula rate plan if it provided a fair and reasonable

rate of return. However, the Commission decided that it would rely on market-based financial

models instead.

¶ 60 The Commission found the utility proxy group a reasonable sample but rejected Ameren’s

non-price regulated proxy group as having no value. After addressing the DCF model, the

Commission rejected Ameren and IFCUP’s DCF analyses because they both relied on outdated

23 historical stock prices. It also rejected Staff’s average of the constant growth DCF (9.75%) and the

NCDCF (8.59%) equating to an ROE of 9.17%. Instead, the Commission adopted Staff’s ROE

estimate of 8.48%. The Commission rejected all of the RPM model data because it improperly

based the equity risk premium on historical data which the Commission found were not reasonable

predictors of the current equity risk premium required by investors. It further noted that Ameren’s

calculation did not use current rates but used forecasted rates which the Commission found

improperly inflated the estimated risk premium. Therefore, the RPM models were rejected. The

Commission addressed the various CAPM analyses provided by Ameren, IFCUP and Staff. It

adopted a CAPM using Staff’s risk-free rate of 4.19%, the monthly beta of 0.705, and an MRP of

6.60 which resulted in an ROE estimate of 8.84%. The Commission refused to consider the

ECAPM model data noting that it was “a duplicative adjustment that only serve[d] to increase the

resulting ROE estimate.” The Commission rejected Ameren’s requested adjustment for size and

flotation costs but agreed to a credit risk downward adjustment of 0.10% based on Ameren’s higher

average long-term issuer rating from Moody’s than the rating for the utility proxy group.

¶ 61 The Commission noted its previous use of DCF and CAPM models in determining

common equity. It adopted Staff’s NCDCF estimate of 8.59 and the revised CAPM estimate of

8.84 which resulted in an ROE of 8.72%. The Commission acknowledged that Ameren’s last ROE

in the 2023 filing year was 7.852%, and in years 2017 to 2022 ranged from 7.36% to 8.91%. It

further acknowledged that Ameren’s credit rate was upgraded multiple times while it was under

the formula rates. The Commission opined that the lower risk required the ROE to be on the lower

end of the spectrum and adopted an ROE of 8.72% in each of the four test years, finding the

decision consistent with the constitutionality principles set forth in U.S. Supreme Court precedent.

24 ¶ 62 C. The Commission’s Amendatory Order

¶ 63 Ameren moved for entry of a corrected order. Ameren noted that the final order and

appendices did not accurately reflect the order’s adoption of the rate base approved in Docket 23-

0320. It also noted that the weighted cost of common equity should be 4.36% based on cost of

common equity at 50% and the rate of equity at 8.72%. Staff took issue with the Commission’s

use of two decimal points for the ROE stating it should be 8.715% and Ameren responded arguing

that the decision repeatedly used 8.72%. The Commission granted Ameren’s motion in part on

January 17, 2024, and changed the ROE to 8.715%.

¶ 64 D. The Commission’s order on rehearing

¶ 65 Ameren also filed an application for rehearing from the Commission’s final order.

Ameren’s application for rehearing, inter alia, disputed the ROE of 8.72%. Ameren argued that

the ROE was contrary to law, jeopardized Ameren’s credit ratings, and requested an ROE of 9.82%

or the acceptance of additional evidence on rehearing. Ameren further disputed the Commission’s

rejection of the Grid Plan, and the implementation of a placeholder Rate Plan.

¶ 66 On January 31, 2024, the Commission granted Ameren’s application, in part. Rehearing

was granted as it related to the placeholder rate base and OPEB. However, rehearing on the ROE

was denied and Ameren timely appealed from the Commission’s December 14, 2023, order,

January 17, 2024, amendatory order, and the January 31, 2024, order denying rehearing.

¶ 67 Hearings on the granted rehearing were held before the ALJs on April 11, 2024, and April

25, 2024. On June 20, 2024, the ALJs sent a memorandum to the Commission recommending

denial of the rehearing. The order on rehearing also issued on June 20, 2024, denied Ameren’s

request for rehearing. The order on rehearing confessed error by the Commission’s adoption of the

2022 rate base as a proxy for rates until Ameren refiled it Grid and Rate Plans because that would

25 have allowed Ameren to include OPEB in the rate and further found no basis to reach a different

conclusion on rehearing stating that “a return on the OPEB contra-liability would not result in

reasonable rates.” Ameren filed an appeal from this decision and also requested a second rehearing

arguing that the OPEB’s inclusion in the 2022 rate plan was not an issue raised and therefore, the

Commission did not have authority to address that issue. However, the Commission denied

Ameren’s second request for rehearing on August 1, 2024 and Ameren filed another timely appeal

from the rehearing decisions.

¶ 68 E. Ameren’s refiled Grid and Rate Plans before the ALJs.

¶ 69 On March 13, 2024, Ameren submitted a voluminous refiled Grid and Rate Plan. Hearings

on the refiled Plans were held before the ALJs on April 11, 2024, and on April 25, 2024.

¶ 70 1. Storm Hardening

¶ 71 Ameren’s refiled Grid Plan requested $11.745 million for storm hardening every fifth pole

to avoid cascades during extreme weather events. It noted this was a significant reduction from its

initial request of $40.315 million in the initial filing. Ameren requested the full amount because it

was “critically important for resiliency, reliability, affordability, and safety, especially when

considering the potential for more frequent and severe storms” due to climate change. It explained

that the composite poles could absorb the impact from combined wind and ice loading better than

the existing poles. Therefore, shoring up the line at every fifth pole limited the damage caused by

the storms. As support for the projects, Ameren addressed the cost savings with proactively placing

the fifth pole compared to restoration of the area after a storm. It further addressed the Arthur to

Lovington 69kv that cascaded during a storm in the late 1990s, early 2000s, that took out 99 poles.

The repair used the same lower strength poles and a second storm in 2002 took the lines and over

70 poles down with it. It stated the cost of the two repairs was over $4.37 million. Ameren argued

26 that after the second event the composite poles were used and no further cascading had occurred

on that line. Ameren also addressed other lines and provided the cost to repair and the proactive

replacement cost, as follows: (1) Gibson City to Fairbury, $5.59 million to repair, $1.6 million to

replace; (2) Gilman to Fairbury, $3 million to repair, $460,000 to replace; (3) Chatsworth to Piper

City, $494,000 to repair, $80,000 to replace; (4) Hoopeston to Watseka, $1.35 million to repair,

$200,000 to replace; (5) Gilman to Paxton, $936,000 to repair, $146,000 to replace; and

(5) Gilman to Watseka, $1.86 million to repair, $280,000 to replace. Ameren argued that limiting

the projects would harm customers by making the grid less resilient and subjecting customers to

increased restoration costs, longer outages, and safety issues due to cascading lines.

¶ 72 Ameren’s reply brief contended that Staff’s requested reduction should be denied. Ameren

relied on Adams’ testimony that explained the need and priority was the customers based on the

engineer-identified weakness in the grid. It argued that the requested amount of $11.7 million was

lower than anyone’s originally recommended budget and was also responsive to the original Grid

Plan reviewed. It complained that the conflicting stances requesting reduction to the amount failed

to address Ameren’s expertise, experience, and informed judgment on this issue. The evidence

presented showed that storm hardening worked as evidenced by the Gibson City to Fairbury line

that cascaded nine times in 10 years but did not have another cascade once it was hardened. Due

to the indisputable fact that Ameren’s customers were experiencing more frequent and more severe

weather events, it logically followed to support the system in this manner. Ameren requested the

ALJs approve the full amount to harden the lines.

¶ 73 Staff requested the ALJs reduce Ameren’s $11.745 million request by $4.477 million. It

stated that while Ameren produced a list of eight lines proposed for hardening, it was not possible

to trace those lines to the list proposed by Ameren. It further contended that Ameren failed to

27 provide meaningful data addressing the risks and consequences of cascading failure events or an

analysis of costs and benefits showing that proactive hardening would prove more effective than

post-event restoration and repair. Staff witness Antonuk testified that if the project started in 1988,

Ameren would have spent $105 million on storm hardening when the repair costs would only have

amounted to $20.31 million. Staff recommended allowing $7.269 million toward the project,

which was an amount commensurate with the historical expenditures on similar work with

increases based on current value. Staff also noted a lack of reliance as to Ameren’s predictability

for where the hardening should occur. Staff’s reply brief stated that Ameren brought no new

argument, and the Commission should accept Staff’s adjustment because Ameren failed to show

it was more cost effective to reinforce existing poles through prediction than repairing and

strengthening those poles after they fell.

¶ 74 The State requested the ALJs reduce Ameren’s request by $3.49 million. The State argued

that proactively replacing the wood poles with composite every fifth pole was unnecessary because

the poles were routinely inspected or tested and if it failed the inspection or test, it would be

repaired or replaced. The State argued that Ameren produced no evidence showing proactive pole

replacement was more cost-effective than replacing them as part of its maintenance. The State

further argued that there was no assurance that every fifth pole would avoid service interruptions

or reduce duration of service interruptions because back-up capacity existed for a majority of the

subtransmission circuits. The State contended that Ameren could not predict where the weather

would hit to avoid the cascading effect. The State’s reply brief again requested a reduction of $3.49

million from Ameren’s requested funds. It further agreed with the testimony from Staff witness

Antonuk. The State argued that Ameren could not predict which lines would cascade with 100%

28 foresight. The State requested a minimum reduction of $3.49 million or adoption of Staff’s

recommended reduction of $4.47 million.

¶ 75 IFCUP provided no specific argument on this issue in its initial brief. However, its reply

brief contended that if Ameren’s critical infrastructure was deficient due to aging, then the

Commission should consider opening an investigation into why or how Ameren allowed its critical

infrastructure to become inadequate. IFCUP further found Ameren’s claim “difficult to accept in

light of the funding of massive investments that took place during EIMA” and included $1.9 billion

investment from September 2012 to December 2022. IFCUP contended that either Ameren was

wrong about the aged critical infrastructure or had been a “poor shepherd of ratepayer funds during

EIMA period and need[ed] to be held accountable.” As to the storm hardening, IFCUP argued that

the Commission should note that in the last 10 years, across its entire system, Ameren reported

just eight incidents of cascading with each incident occurring in extreme wind conditions or ice.

IFCUP argued that “[p]redicating significant capital expenditures on potentially bad weather is

bad policy.” (Emphasis in the original.).

¶ 76 On October 8, 2024, the ALJs found that the storm hardening should be approved at

Ameren’s requested level of $11.745 million. The ALJs found that the program would improve

the reliability and resiliency of Ameren’s subtransmission system consistent with the intent of the

Jobs Act. They acknowledged the difficulty of assessing the financial benefits of work that was

intended to address severe weather, noting the unpredictability of where and when it would strike.

However, the ALJs found the project was reasonably expected to provide significant benefits for

customer affordability given that the cost of restoring lines was significantly higher than

proactively hardening those same lines. Noting that the funds should be used on the lines at the

29 highest risk of cascading, it found it appropriate to rely on the experience of Ameren’s engineers

to determine the best candidates for hardening to fully realize the benefit of the program.

¶ 77 2. Inclusion of OPEB in the rate base.

¶ 78 Ameren again requested inclusion of the OPEB contra-liability in the rate base, stating that

the Commission found that Ameren shareholders made a $100 million contribution to the OPEB

fund. It cited passages from the 2011 docket decision but none of them use the word shareholder.

Instead, Ameren relied on the fact that if the $100 million source was from ratepayer funds, the

$100 million would have included in the OPEB liability deducted from rate base, not subtracted

from it. Therefore, it claimed that the Commission’s conclusion that Ameren failed to show that

the $100 million to the OPEB fund was sourced from shareholder funds was demonstrably wrong.

Ameren also argued that the shareholders were going to have to finance the cash flow shortfall

given as a credit to customers in the amount of $93 million through 2027. It claimed this would

result in a shortfall of Ameren’s cashflow, which shareholders must fix. Ameren stated that under

the EIMA, the contra-liability was allowed in the rate base. It further noted that money could not

be withdrawn from the overfunded Trust to cover the cash flow deficiency.

¶ 79 Ameren’s reply brief claimed that OPEB liability was consistently reflected in the rate

based from 2006 to the present. It argued that either the expense and contra-liability should both

be reflected in the rates or neither should be reflected in the rates. It stated that no party disputed

that the liability was prudently incurred and reasonable in amount and under section 16-

108.18(d)(3)(A) of the Jobs Act should be included. Ameren continued to disagree with the

conclusion that the amount was not shareholder funded and further stated that the arguments

against inclusion failed to address the negative cash flow stemming from the customer credits as

well as Ameren’s inability to access the funds in the OPEB trust.

30 ¶ 80 Staff again recommended that OPEB contra-liability not be included in the rate base

because Ameren failed to demonstrate that the asset was created with shareholder funds. It claimed

the funds came from ratepayers and therefore, any return on the asset was unwarranted. Staff noted

that the asset was only previously allowed under the EIMA, and Ameren was no longer under the

EIMA, it was under the Jobs Act. It stated that the provisions allowing OPEB in the rate base were

not included in the Jobs Act. No new evidence was submitted in the refiled Plans that indicated

the OPEB asset was shareholder funded and Ameren’s request should be denied. Staff’s reply brief

addressed the issue with argument similar to that in its initial brief.

¶ 81 IFCUP requested denial of Ameren’s request to include OPEB contra-liability in the rate

base should be denied. IFCUP argued that its witness, Michael Gorman, explained that Ameren

failed to offer new evidence justifying why a reversal of the Commission’s prior decisions should

occur, and instead, Ameren contended that disallowance coupled with the ROE compounded the

unreasonably low ROE. IFCUP agreed that Ameren failed to show that the asset was funded by

shareholder capital. IFCUP’s reply brief continued to argue that Ameren failed to credibly show

that the OPEB contra-liability was funded using shareholder capital. IFCUP agreed with Staff’s

position on this issue.

¶ 82 On October 8, 2024, the ALJs found that the issue was fully briefed in both the original

filing and rehearing docket. They found no reason to reach a different conclusion here. The ALJs

agreed with Staff to find that because ratepayers funded the OPEB asset and inclusions in the rate

base would essentially require ratepayers to pay for the asset twice. The ALJs further noted that

Ameren provided no additional evidence to show the funds were from the shareholders. The ALJs

stated that the prudency and reasonableness of the asset were not the issue; the issue was the lack

of evidence showing the funds came from shareholders. The ALJs also rejected any short-term

31 alternative plan that would allow for inclusion in the rate base. Ameren was disallowed from

including the OPEB contra-liability asset in its rate base for all four years.

¶ 83 3. ROE

¶ 84 Ameren also argued that the Commission’s previous ROE of 8.715% was inadequate,

noting it was lower than any of the recommended ROEs and was also lower than the 2022 ROE

calculated under the EIMA. Ameren also argued that the ROE awarded to Commonwealth Edison

Company (ComEd) was higher than Ameren’s ROE despite both operating under the same

statutory framework. Ameren also argued that investor reaction to the December 2023 order was

“swift, severe, measurable, and overwhelmingly negative.” Ameren noted a drop in stock price for

Ameren’s parent company and contended that the stock continued to lag six months later. Ameren

disputed that the stock drop was merely a “one-day blip,” and claimed the parent company had not

recovered the drop in value “relative to its peers” and investors were viewing other utilities more

favorably. Ameren argued that the lack of investors was undermining its achievement of the Jobs

Act goal due to a lack of adequate capital investment. Ameren requested the Commission consider

ROEs in other states with comparable rate plans, noting ROEs of 9.25% in Minnesota and New

York as well as 9.8% in North Carolina. Ameren requested the Commission raise the ROE to

9.24%. Ameren further argued that ComEd’s higher ROE violated constitutional principles

enunciated in U.S. Supreme Court law because the higher rate denied Ameren investors the

opportunity to earn a rate commensurate with the return offered on an investment of comparable

risk.

¶ 85 Ameren’s reply brief addressed the more favorable rates in other areas of the country. It

further contended that the Commission failed to explain why Ameren’s resultant ROE was nearly

20 bps lower than the one awarded to ComEd which faced the exact same risks as Ameren, stating

32 the discrepancy was an obvious violation of legal precedent. Ameren further contended that neither

Staff, nor any intervenor, attempted to provide justification for the difference and instead

contended that the ROE was previously determined and could no longer be addressed. Ameren

argued that there is no reason why the Commission could not address the requested revision

whether raised by Ameren or the Commission itself. Ameren stated that at the very least, the

Commission should increase Ameren’s ROE to match that awarded to ComEd.

¶ 86 Staff argued that the parties were bound by the ROE previously established in the initial

filing. It further argued that Ameren was only entitled to a return sufficient to maintain its financial

integrity and attract capital on reasonable returns. It relied on testimony from Staff witness, Janice

Freetly, stating that the current ROE was sufficient to support Ameren’s financial strength and

ability to access capital. Staff further argued that Freetly’s testimony was supported by IFCUP

witness Gorman who testified about Ameren’s credit standing and ability to fund rate base

investments as well as its overall rate of return. Staff’s reply argument on ROE was similar to its

initial argument and again argued that the ROE issue was closed, noting that the issue had already

been appealed to the appellate court.

¶ 87 The State also argued that the Commission should reject any attempt by Ameren to reopen

the ROE in the refiled proceeding. The State further claimed that even if the issue was not beyond

the scope, Ameren failed to demonstrate that any modification was prudent. The State also relied

on Staff witness Freely who opined that Ameren’s claim of an ROE at 8.715% would harm

Ameren’s financial integrity, had no merit, and the rates approved in the previous order were

“sufficient to support Ameren’s financial strength and ability to access capital and maintain its

investment grade credit rating.” The State also noted IFCUP witness Gorman testified that the

stock price for Ameren Corporation had not noticeably suffered since the December order was

33 issued. The State’s reply brief continued to argue that the issue was beyond the scope because it

was previously determined. As to Ameren’s claim that it was “docked” based on ComEd’s higher

ROE, the State clarified that the different rates were based on the Commission’s use of “market-

based financial models” that incorporated numerous factors. It classified Ameren’s argument as a

“blatantly incorrect swipe” and “collateral attack on the well-reasoned analysis and conclusion” in

the previous decision.

¶ 88 IFCUP agreed that the matter of a proper ROE was resolved. It stated that the current ROE

was in the same range as that allowed from 2018 to 2023. During that time, Ameren’s credit

remained the same with the “stable” outlook. IFCUP further argued that Ameren’s claims were

also undermined by the fact that its ratemaking capital structure contained among the highest

percentage of common equity, which was not seen with the utility companies in Texas, New York,

or New England. It further noted that those companies had overall costs of capital lower than

Ameren. Gorman explained that the ROE was consistent with the view of market participants that

utilities need to manage construction programs in a manner that mitigated the impact on customer

bills and relied on supportive regulatory mechanisms. IFCUP argued that the Commission’s ROE

was consistent with that outlook. IFCUP further argued that even if consideration of the ROE was

appropriate, Ameren’s request to raise the ROE should be denied.

¶ 89 IFCUP’s reply stated that it, Staff, and the State were all in agreement that the Commission

should make no adjustment to the 8.715% ROE because it was already decided. IFCUP further

noted that Ameren previously complained that an ROE of 9.24% was too low but now found it

“reasonable.” IFCUP opined that Ameren’s only objective was to increase the ROE regardless of

fairness and reasonableness to customers. IFCUP further argued that any drop in stock price due

34 to the December 2023 decision was recovered and investments under the Jobs Act were less risky

than under the EIMA.

¶ 90 On October 8, 2024, the ALJs found that Ameren’s ROE would remain at 8.715%. They

agreed with Staff, IFCUP, and the State, that the matter was not within the scope of the refiling

proceeding. The ALJs also found Ameren’s comparison to ComEd’s ROE unpersuasive and that

the latter’s ROE was irrelevant, noting that the Commission performed its own separate analysis

of ComEd’s financial outlook to develop ComEd’s ROE and did the same for Ameren.

¶ 91 F. Ameren’s refiled Grid and Rate Plans before the Commission

¶ 92 Ameren, Staff, the State, and IFCUP all filed briefs of exceptions related to the ALJs’ order.

The Commission issued an order on December 19, 2024, approving Ameren’s refiled Grid and

Rate Plans. The arguments raised on the issues raised on appeal here and the Commission’s

determination, were as follows:

¶ 93 (1) Storm hardening

¶ 94 Ameren did not address this issue in its Statement of Exceptions. However, Ameren’s reply

brief requested that the amount allowed by the ALJs remain the same. Ameren noted that its current

request was below the amount previously recommended by Staff in the original plan. It further

addressed the previous rebuilds that occurred following weather events, the costs associated with

hardening, and what the expenses were after the rebuild.

¶ 95 Staff argued that its proposed adjustment of $4.477 million to Ameren’s $11.74 million

request should be granted. It contended that Ameren’s inability to predict line failures at a high

enough success rate made hardening prior to, as opposed to after, cascading far more expensive.

Staff contended that predicting which lines would fail in extreme weather was too speculative and

spending funds to harden lines that may never fail was not cost effective. It stated that action after

35 the cascade would mitigate the risk of future cascading. It noted that, historically, Ameren only

hardened one line a year and insufficient evidence was presented to show why more funding should

be allowed beyond Staff’s rate which allowed funding that doubled the previous historical rate.

¶ 96 The State requested that $3.49 million be removed from the storm hardening program. It

argued that the record showed that the project was not cost effective when considering the $11.74

million requested for the plan. It further argued that cascading events were relatively rare and there

was only limited evidence that proactive hardening would reduce service interruptions given that

back up capacity existed for the majority of subtransmission circuits. No argument regarding this

issue was addressed in the State’s reply brief.

¶ 97 IFCUP also requested a reduction to the storm hardening program, noting that Staff found

that Ameren failed to provide meaningful additional data addressing the risks and consequences

of cascading failure events or an analysis of the costs and benefits showing that proactive

hardening would prove more cost effective than post-event restoration and repair. IFCUP urged

the Commission to address the deficiency in Ameren’s evidence.

¶ 98 On October 23, 2024, the Commission approved the storm hardening program with Staff’s

$4.477 million adjustment to Ameren’s $11.75 million request for the program. It found that the

program, as adjusted, would allow Ameren to “maintain and improve the reliability and resiliency”

of its subtransmission system in a manner consistent with the intent of the Jobs Act. The

Commission acknowledged the difficulty of assessing the financial benefits of work that was

intended to address severe weather, noting the unpredictable nature of when and where it would

strike as well as the growing threat of extreme weather caused by climate change. However, it

found that despite the increased winds, cascading pole failures had decreased since 2000.

Therefore, the Commission agreed with Staff that the record did not support the level of investment

36 proposed when Ameren’s current programs were appropriately protecting its system from

changing weather.

¶ 99 The Commission also found that Ameren could not successfully predict cascading events

with the confidence needed to support inclusion in its Grid Plan, stating that without the ability to

realistically identify at-risk lines, proactive replacement was not more cost-effective than

reactionary repair. The Commission further found that Ameren did not produce evidence sufficient

to demonstrate that it would suffer material impairment in sustaining and improving reliability if

the amount was reduced by Staff’s requested adjustment. It stated that Staff’s adjustment allowed

Ameren to complete two line hardenings a year, which doubled its historical annual work in this

category. Therefore, the Commission found that Staff’s adjustment would support and improve

the reliability and resiliency of Ameren’s system consistent with the objectives of the Jobs Act and

it was adopted.

¶ 100 (2) OPEB inclusion in the rate base

¶ 101 Ameren requested the Commission reject the ALJs’ proposed order removing the OPEB

asset from rate base. It argued that the decision did not balance the removal with the fact that over

the four test years customers would receive $93 million in credits due to the negative OPEB

expense. As a result, Ameren complained that the order failed to recognize the symmetry resulting

from including the asset in the rate base because ratepayers would receive a benefit, retirees would

have the benefit of a fully funded plan, and Ameren would be compensated for its capital outlay

and inability to access the OPED funds for everyday use.

¶ 102 Staff did not address this issue in its Statement of Exceptions following issuance of the

ALJs’ proposed order. However, its reply brief requested rejection of Ameren’s request to include

OPEB in the rate base, stating that Ameren failed to show that the asset was created from

37 shareholder funds. Staff also argued that the Commission had long held that OPEB assets were not

included in the rate base. It contended that Ameren’s inability to withdraw funds did not change

the source of the funds or justify earning a return on funds that did not represent shareholder

investments. It further stated that that disallowance was not asymmetrical because there was

insufficient evidence of shareholder initiated funds and the negative expense rightfully flowed to

the customers because they initially funded the OPEB. Finally, Staff argued that cash flow

challenges did not justify creating a return to shareholders where none was warranted.

¶ 103 IFCUP agreed with the ALJs’ order and requested continued rejection of Ameren’s

position. It requested the Commission’s order place reliance on IFCUP’s previously issued

position to bolster the decision on appeal. IFCUP’s reply brief continued to argue that the OPEB

asset should not be included in the rate base, noting that Ameren submitted no relevant evidence

on the issue in the refiling.

¶ 104 The Commission’s order on refiling again removed the OPEB contra-liability for all four

years, finding the issue had been fully briefed previously and there was no reason to come to a

different conclusion. The Commission rejected the accounting symmetry argument, stating that

ratepayers funded the asset and including it twice in the rate based would require ratepayers to

fund the asset twice. The Commission also found that Ameren failed to provide any additional

evidence that would convince the Commission that ratepayers and trust fund investments caused

the OPEB growth. The Commission agreed that the overage stemmed from prudently incurred

costs and reasonableness in maintaining the program but rejected the argument due to the lack of

evidence showing the overage was from shareholding funding. The Commission also rejected

Ameren’s alternative proposal due to the lack of a showing that the OPEB asset contra-liability

was funded by shareholders.

38 ¶ 105 (3) ROE

¶ 106 Ameren requested the Commission revisit and upwardly adjust the 8.715% ROE because

the ROE was materially lower than any other applicable electric utility in the country that faced

comparable risks, especially when ComEd was given a higher ROE. Ameren requested the ROE

be adjusted to 9.24%.

¶ 107 Staff did not address this issue in its Statement of Exceptions following issuance of the

ALJs’ proposed order. Staff’s reply brief requested rejection of any modification of the ROE

because no additional information regarding the capital analysis was provided. It stated the issue

was previously addressed on rehearing, denied, and was now pending before the appellate court.

¶ 108 The State did not address this issue in its Statement of Exceptions either. However, the

State’s reply brief requested rejection of Ameren’s request to increase the ROE because the request

was beyond the scope of the refiling. The State further argued that even if it was within the scope,

Ameren would be able to access capital, so no adjustment was necessary.

¶ 109 IFCUP did not address this issue in its Statement of Exceptions. However, IFCUP’s reply

brief contended that Ameren’s request to revisit the issue was beyond the scope of the proceedings,

as the issue was currently pending before the appellate court, which removed the issue from the

Commission’s jurisdiction. IFCUP further stated that even if the issue was within the

Commission’s jurisdiction, the ROE was sufficient as it was comparable to the ROEs set for the

last six years, during which time Ameren remained financially stable.

¶ 110 The Commission adopted the ALJs’ conclusion that found the issue was not within the

scope of the proceeding, noting that the issue was currently on appeal at the appellate court. The

Commission also found that Ameren’s claim of comparability to ComEd unpersuasive and

irrelevant. The Commission stated that previous decision was neither arbitrary nor capricious when

39 it provided a 9-page analysis explaining, in detail, how it determined the ROE. It further noted a

lack of evidence of market reaction and that Ameren’s credit rating remained the same and retained

its “stable” outlook.

¶ 111 G. The Commission’s order on rehearing.

¶ 112 On January 21, 2025, Ameren filed an application for rehearing. Ameren’s application

addressed three issues: (1) the reduction to Ameren’s requested 11.74 million for storm hardening,

(2) the refusal to include the OPEB contra-liability in the rate base, and (3) the 8.715% ROE.

¶ 113 Ameren’s contended that the refiling final order was against the manifest weight of the

evidence and requested a rehearing to provide Ameren “with an opportunity to submit additional,

newly obtained evidence to support [Ameren’s] wood-pole subtransmission line rebuild program.”

It sought hearings to emphasize that Staff’s review of the program set a harmful precedent to both

Ameren’s ability to work to further the goals of the Jobs Act and Ameren’s customers.

¶ 114 As to the OPEB asset, Ameren argued that the Commission’s reliance on orders that

allowed for inclusion of the OPEB contra-liability in the rate basis, i.e., the placeholder Rate Plan,

and a reversal of that decision in a later decision, i.e., the amendatory order removing the OPEB

contra-liability from the rate base, was contrary to law and failed to address the substantial

ratepayer benefits. It further argued that the Commission’s conclusions were against the manifest

weight of the evidence, misconstrued the nature of the OPEB contra-liability as to its origin, and

its reliance on contrary decisions created a decision that was contrary to law.

¶ 115 As to the ROE, Ameren disagreed that it was outside the scope of the refiling. It further

claimed that the Commission’s finding that Ameren’s request for a 9.24% ROE arbitrary and

capricious, was in error. It also argued that the Commission erred by rejecting Ameren’s

comparisons of its ROE with the ROE recently provided to ComEd by the Commission.

40 ¶ 116 On February 6, 2025, the Commission issued an order. The order denied Ameren’s

requested for rehearing on refiling. Ameren also filed a notice of appeal from this ruling.

¶ 117 II. ANALYSIS

¶ 118 In these consolidated appeals, Ameren argues that the Commission order reducing funding

for storm hardening was reversible error because the decision (1) did not articulate, analyze, or

apply specific provisions of the Grip Plan in section 16-105.17 of the Utilities Act or the Rate Plan

under section 16-108.18 of the Jobs Act; (2) violated the Jobs Act which required the Commission

to approve Grid Plans designed to improve reliability, resiliency, and affordability; (3) violated the

Utilities Act provisions requiring that the Rate Plan provide for the recovery of the forecasted rate

base that met the Jobs Act requirements; and (4) was against the manifest weight of the evidence.

Ameren also contends that the Commission’s decision to reduce Ameren’s rate base by the amount

of the OPEB asset requires remand because (1) the refiling order was not supported by substantial

evidence, (2) prior Commission orders confirmed that the $100 million was shareholder funded,

(3) the refiling orders violated Illinois law, (4) the issue was improperly decided on rehearing, and

(5) the Commission order was arbitrary. Finally, Ameren argues that the Commission setting the

ROE at 8.715% constituted reversible error because the established ROE level was below return

on investments at comparable risks, and disfavored investment in electric operations in central and

southern Illinois.

¶ 119 A. Standard of Review.

¶ 120 Our review of the Commission’s orders is limited to that proscribed by statute. See 220

ILCS 5/10-201(e) (West 2022). We will reverse a Commission decision, in whole or in part, only

if (1) the Commission findings are not supported by substantial evidence, (2) the decision is

outside the Commission’s jurisdiction, (3) the decision violated state or federal constitution or law,

41 or (4) the Commission proceeding violated state or federal constitution laws and prejudiced the

appellant. Id. § 10-201(e)(iv). We presume the Commission’s decisions are “prima facie

reasonable” and the burden of proof for all issues remains with the appellant. Id. § 10-201(d). The

Commission’s decisions are “entitled to great weight as being the judgment of a tribunal appointed

by law and informed by experience.” Village of Apple River v. Illinois Commerce Comm’n, 18 Ill.

2d 518, 523 (1960).

¶ 121 B. Storm Hardening.

¶ 122 Ameren first argues that the Commission’s order failed to properly evaluate a proposed

grid hardening investment, which resulted in drastic cuts to the budget for a reasonable and prudent

program that would prevent outages over time and save customers money while doing so. It

contends that the Commission’s decision is “in direct contravention of the Utilities Act’s

applicable reliability, resiliency, affordability, and ratemaking provisions” and constitutes

reversible error. We disagree.

¶ 123 First, while Ameren contends the reduction in funding constituted reversible error, it fails

to state which of the four bases provided by statute would support reversal. There is no claim that

the Commission acted outside its jurisdiction or that any of Ameren’s constitutional rights were

violated. This leaves us with the only remaining basis for reversal that would require the

Commission findings to not be supported by substantial evidence. Substantial evidence exists “if

a reasoning mind would accept the evidence as sufficient to support the challenged finding.” City

of Elgin v. Illinois Commerce Comm’n, 2016 IL App (2d) 150047, ¶ 25. To warrant reversal, it is

not enough that the evidence could “support a different conclusion; it must be shown that the

opposite conclusion is clearly evident.” Continental Mobile Telephone Co. v. Illinois Commerce

Comm’n, 269 Ill. App. 3d 161, 171 (1994).

42 ¶ 124 Ameren’s initial argument regarding the subtransmission line hardening project is based

on a misplaced belief that when some of the requirements of section 16-105.17 of the Utilities Act

are met, the requested budget for the grid improvement must be approved. However, approval of

any and all improvements under section 16-105.17 are tempered with providing delivery services

at affordable rates. See 220 ILCS 5/16-105.17(a) (West 2022). Here, Ameren’s initial Grid Plan

included storm hardening and requested approval of $40.3 million to place a fifth composite pole

to strengthen lines that could cascade in severe weather events. Staff and Intervenors requested a

reduction of the requested amount due to a lack of a reliable predictive ability that would determine

which lines were most likely to cascade and where the severe weather would occur. Staff and

Intervenors further noted Ameren’s lack of diligence in addressing the alleged problem in the past.

¶ 125 Ultimately, the initial Grid Plan was rejected and Ameren’s refiled Grid Plan requested

$11.745 million for storm hardening. Again, Staff and the Intervenors objected to the amount

requested. Ameren relies on section 16-105.17(d) of the Utilities Act (id. § 16-105.17(d)) that

states the grid plans “shall be designed to *** optimize utilization of electricity grid assets and

resources to minimize total system costs” and “provide delivery services at rates that are affordable

to all customers.” Id. § 16-105.17(d)(2), (11). However, Ameren ignores the requirement in the

section 16-105.17(d)(1) that specifically addresses a utility’s distribution system investments. Id.

§ 16-105.17(d)(1). That section states the plan should “ensure coordination of the State’s

renewable energy goals, climate and environmental goals with the utility’s distribution system

investments, and programs and policies over a 5-year planning horizon to maximize the benefits

of each while ensuring utility expenditures are cost-effective.” Id. As such, consideration of the

cost-effectiveness of Ameren’s distribution system investments was integral to determining

whether Ameren’s plan should be adopted. Therefore, contrary to Ameren’s contention that limited

43 the Commission’s consideration to whether the plan maximized “consumer, environmental,

economic, and community benefits over a 10-year horizon (see id. § 16-105.17(f)(5)(A)(6)), the

Commission was also required to consider whether Ameren’s distribution system investments

were cost-effective. See id. § 16-105.17(f)(5)(A)(1) (requiring the Commission to determine the

proposed plan “met the objectives of this Section.”). We further note that the Commission’s

statutory evaluation only sets the bare “minimum” considerations for the plan (see id. § 16-

105.17(f)(5)(A)) and therefore, even if cost-effectiveness was not a statutorily proscribed

requirement, the Commission addressing cost effectiveness would not be in error.

¶ 126 Ultimately, the Commission found that the $11.745 proposed investment would “allow the

Company to maintain and improve reliability and resiliency of Ameren’s subtransmission system

consistent with the intent of P.A. 102-0662 [the Jobs Act].” However, in adopting Staff’s

recommended reduction, the Commission noted the difficulties associated with predicting both the

location and timing of severe weather undermined proper assessment of the financial benefits of

the plan. It further noted a decrease in cascading pole failures since 2000, as well as the fact that

proactive replacement, without an ability to realistically identify at-risk lines, was not more cost-

effective than reactionary repair. Because the Commission addressed the cost-effectiveness of the

proposed program, we disagree that the Commission’s decision contravened the Jobs Act where

the decision properly assessed one of the most critical considerations thereunder. Accordingly,

substantial evidence supports the Commission decision.

¶ 127 Ameren also argues that the Commission decision violated the Utilities Act’s provisions

that the Rate Plan provide for the recovery of forecasted rate base that met the applicable

requirements. It claims that because the program represented the “kind of prudent and reasonable

44 investment that the Commission should approve” and the storm hardening program was approved

as part of Ameren’s rate base since 2012, the decision was contrary to law. We again disagree.

¶ 128 There was no dispute that adding a composite fifth pole would increase reliability and

resiliency of the system. However, the Commission found that the projected costs, with no possible

way to determine which lines would actually be affected by severe weather in any given year,

undermined a carte blanche approval of any or all requested amounts toward the proposed project.

¶ 129 Once again, Ameren contends the Commission ignored another statutory responsibility,

this time under section 16-108.18(d)(3)(A) of the Jobs Act. 220 ILCS 5/16-108.18(d)(3)(A) (West

2022). Ameren argues that the section requires that the rate plan approved by the Commission

‘provide for the recovery of the utility[’s] forecasted rate base, based on the 4-year investment plan

and the utility’s Integrated Grid Plan *** [with] costs that are prudently incurred and reasonable

in the amount consistent with Commission practice and law.’ ” Id. § 16-108.18(d)(3)(A), (B).

Ameren argues that since the program had been in place since 2012 and was previously approved

for inclusion in the Rate Plan,” the Commission’s failure to approve Ameren’s requested budget

was contrary to the statute.

¶ 130 Ameren again ignores important objectives related to performance-based ratemaking and

a utility’s distribution system. See Id. § 16-108.18(c)(1)-(9). More specifically, the objectives

include directing the electric utility “to make cost-effective investments that support achievement

of Illinois' clean energy policies, including, at a minimum, investments designed to integrate

distributed energy resources, comply with critical infrastructure protection standards, plans, and

industry best practices, *** while mitigating the impacts.” Id. § 16-108.18(c)(3). Once again,

because the Commission’s decision was based on the cost-effectiveness of the proposed project,

we cannot find that the Commission’s decision violated the Jobs Act.

45 ¶ 131 Finally, Ameren contends that the Commission decision reducing the amount allocated to

the subtransmission storm hardening program was not supported by substantial weight because

full approval in the amount of the requested budget was evident. We again disagree.

¶ 132 There is no dispute that the evidence consisted of Ameren’s list of subtransmission lines

supported by poles with inferior resiliency compared to composite poles. Additional evidence

comparing the cost of proactive hardening with repair once the lines cascaded was also provided.

Unquestionably, storm hardening was cheaper than the ultimate repair. However, while Ameren

ranked the most serious areas in need of hardening, no analysis or testimony was provided

regarding the likelihood of whether those poles would be affected by severe weather. Equally

deficient was any evidence of Ameren’s predictive ability to forecast the weather.

¶ 133 What became apparent through the testimony provided was that numerous annual

catastrophic weather events were required to justify the amount requested by Ameren to harden

the subtransmission lines. However, the evidence failed to support the conclusion that these types

of storms occurred annually or that the cascading poles occurred with such frequency that

immediate action was required. Equally evident was either the lack of diligence or necessity

Ameren associated with this project in past years. Testimony revealed that Ameren limited the

number of storm hardening line projects to two annually. No testimony was provided to clarify or

substantiate what appears to be a sudden and immediate need to perform storm hardening given

Ameren’s historical lackluster performance with this project. Accordingly, we disagree that

substantial evidence fails to support the Commission’s decision to reduce Ameren’s requested

$11.745 million budget to $7.269 million. Therefore, we affirm the Commission’s decision.

46 ¶ 134 C. Inclusion of OPEB in the rate base.

¶ 135 Ameren next argues that the Commission decision to disallow the OPEB asset from rate

base should be remanded because it was not based on substantial evidence, contrary to the

requirements of section 16-108.18 of the Jobs Act for setting Rate Plan rate base and was arbitrary

because the disallowance was a departure from prior practice. Ameren requests we reverse the

Commission decision and remand the issue with direction to the Commission to consider the

financial impact of the treatment of OPEB costs on Ameren.

¶ 136 Ameren first contends that the refiling order erringly states that Ameren can access funds

in the OPEB trust. It quotes the Refiling Order as stating,

“The inclusion of negative OPEB expenses in rates reduces the utility’s cash

flow because the cash expenditures for operations do not decrease; yet the

Company claims that it cannot recover cash from the OPEB Trust to offset the

negative OPEB reduction in rates. The Commission agrees with Staff and IFCUP

that Ameren is incorrect.”

While there is no dispute that this language was included in the Refiling Order, Ameren

conveniently ignores both the initial and final sentences in that paragraph. The initial sentence

stated, “Ameren argues that the issue is accounting symmetry—an OPEB expense and an OPEB

contra-liability must be treated the same way—either reflected in rates or not reflected in rates.”

The last sentence stated, “Because the ratepayers funded the OPEB asset, including the asset in

rate base would essentially require ratepayers to pay for the asset twice.”

¶ 137 Our review of the Commission decision fails to support Ameren’s interpretation, and we

believe the quoted material is taken out of context. The Commission was not classifying Ameren’s

claim that it cannot remove funds from the OPEB trust as incorrect. The Commission was

47 classifying Ameren’s argument that the OPEB asset should be included in the rate base as incorrect

because inclusion in the rate base would require ratepayers to pay for the asset twice.

¶ 138 Ameren also contends that the Refiling Order ignored the financial impact on the utility by

reducing rates for the negative OPEB expense. We disagree. At no point did the Commission

ignore the fact that Ameren’s shareholders would have to make up any cash flow deficiency

stemming from the reduction in rate due to the overfunded OPEB trust. The Commission’s

decision did not deny inclusion in the rate base because it failed to comprehend, or ignored, the

financial impact to Ameren’s shareholders. The Commission denied inclusion because Ameren

failed to show that the overfunded OPEB asset was due to shareholder contributions.

¶ 139 While Ameren contends that “[t]here should still be compensation to shareholders for

making up the cash flow reduction,” no citation to authority for such claim was provided. Ameren

contends that inclusion of OPEB contra-liability would compensate investors for making up the

cash flow shortfall caused by the negative expense, not ratepayers paying for the asset a second

time. It then cites 33 pages of spreadsheets that reveal the disallowance reduced the rate base by

$105,185 in 2024, $124,537 in 2025, $142,424 in 2026 and $159,213 in 2027. Following further

accumulated deferred income tax (ADIT) liability reductions, the net loss to the rate base amounted

to $102,488 in 2024, $121,939 in 2025, $137,820 in 2026 and $151,015 in 2027. The reductions

equated to less than a 3% reduction in each year’s rate base. Further, Ameren’s spreadsheets

addressing the cash working capital requirement values remained positive in all four years as did

the company’s overall rate of return. As such, without citing to testimony regarding the schedules,

that would interpret them in a different manner, we find Ameren’s argument is not supported by

its evidence.

48 ¶ 140 Ameren also argues that the Commission’s finding that the $100 million payment in 2011

was not shareholder funded was not supported by substantial evidence. Ameren relies on Docket

No. 11-0282, and the language therein that stated, “After contributing $100 million toward OPEB

expenses during the course of these proceedings, AIC argues that the remaining balance of the

liability represents funds not yet collected through rates.” Id. While the decision indubitably

provided the above statement, nothing in that statement indicates anything more than the evidence

submitted here, i.e., that Ameren issued a draft of $100 million to the OPEB trust in 2011.

¶ 141 Further, the issue in Ameren involved the utility’s attempt to parse out which portions of

the trust stemming from the legacy utilities remained unfunded due to ratepayers failing to issue

payments, which the Commission found “wholly inappropriate.” It is equally notable that even

after the $100 million payment, the OPEB fund remained underfunded due to “funds not yet

collected through rates.” Now, over 10 years later, the trust is overfunded, but there was no

evidence showing that no payments were made by ratepayers after 2011. Nor has Ameren even

attempted to show how the underfunded trust liability evolved into an asset with no assistance

from ratepayers. The $100 million payment is not disputed. Ameren needs to realize, however,

that the fund contains ratepayer funds as well as that provided by its parent company and that a

copy of the treasury note moving the funds into the OPEB trust does not validate Ameren’s claim

that shareholders made the payment, especially when its witness confirmed that ratepayer and

shareholder funds were included in the trust and the reason for the overfunding stemmed from

excellent investment strategy related to the fund.

¶ 142 Ameren also argues that the Refiling Order violates Illinois law because it violates the Jobs

Act requirements for a rate plan and is inconsistent with Commission practice and law. While

Ameren contends the standard of review is de novo, it provided no basis for the requested reversal

49 of four options statutorily provided. With no claim that constitutionality was at issue or that the

Commission was acting without jurisdiction, we will only review the decision to determine if the

Commission findings are supported by substantial evidence.

¶ 143 The basis of the rate basis is statutory. See 220 ILCS 5/16-108.18(d)(3)(A) (West 2022).

“The forecasted rate base must include the utility’s planned capital

investments, with rates based on average annual plant investment, and investment-

related costs, including income tax impacts, depreciation, and ratemaking

adjustments and costs that are prudently incurred and reasonable in amount

consistent with Commission practice and law.” Id.

The statute further requires that the

“process used to develop the forecasts must be iterative, rigorous, and lead

to forecasts that reasonably represent the utility’s investments during the forecasted

period and ensure that the investments are projected to be used and useful during

the annual investment period and least cost, consistent with the provisions of

Articles VIII and IX of this Act.” Id.

¶ 144 The components of the revenue requirement have frequently been expressed in the formula

R (revenue requirement) = C (operating costs) + Ir (invested capital or rate base times rate of return

on capital).” (Internal quotation marks omitted.) Citizens Utilities Co. v. Illinois Commerce

Comm’n, 124 Ill. 2d 195, 200-01 (1988). As such, inclusion of the OPEB contra-liability in the

rate base would unquestionably increase the revenue requirement. Id.

¶ 145 Generally, costs are recoverable if they are reasonable and prudent. See Business &

Professional People for the Public Interest v, Illinois Commerce Comm’n, 146 Ill. 2d 192, 247

(1989). Rates should accurately reflect the cost of service delivery and allow a utility to recover

50 costs prudently and reasonably incurred. Citizens Utility Board v. Illinois Commerce Comm’n, 166

Ill. 2d 111, 121 (1995). Given the above-stated formula, it is axiomatic that “[a]ny increase to the

rate base (or invested capital) results in an increased revenue requirement.” Commonwealth Edison

Co. v. Illinois Commerce Comm’n, 398 Ill. App. 3d 510, 515 (2009). Therefore, an increased

revenue requirement is associated with increased rates for ratepayers.

¶ 146 Here, Ameren contends that no one disputed the reasonableness or prudence of the OPEB

contra-liability and cited previous decision by the Commission that allowed Ameren to include

OPEB liability and contra-liability in the rate base. Based on the statutory language, we

comprehend Ameren’s argument. However, there is no dispute that the current statutory language

stating what should be included in the rate base differs from that previously stated under the EIMA,

which specifically included the funding of OPEB and pensions. As such, reliance on previous

Commission decisions is predicated on whether the most recent decisions under the EIMA should

be included.

¶ 147 While typically we are not bound by the Commission on questions of law (Business &

Professional People for the Public Interest, 146 Ill. 2d at 204), we “give substantial weight and

deference to an interpretation of an ambiguous statute by the agency charged with the

administration and enforcement of the statute.” Illinois Consolidated Telephone Co. v. Illinois

Commerce Comm’n, 95 Ill. 2d 142, 152 (1983)). Here, that agency is the Illinois Commerce

Commission. Deference is “especially appropriate in the area of fixing rates” of which the rate

base is a key component. Iowa-Illinois Gas & Electric Co. v. Illinois Commerce Comm’n, 19 Ill.

2d 436, 442 (1960).

¶ 148 Our review of the Commission Refiling Order, as well as the Initial Final Order and Orders

on Rehearing, is that the Commission is taking the reduction of energy costs to consumer under

51 the Jobs Act seriously. The Commission’s interpretation of the statute is based on the fact that the

current statutory language failed to include costs related to pensions, etc., in the rate base, like it

did in the EIMA. We cannot disagree with its finding that if the legislature wanted to include

pensions and OPEB assets or liabilities in the rate base, it could have as it was able to previously

include such language.

¶ 149 Commission decisions are considered prima facie reasonable and the burden of proof for

all issues lies with the appellant. United Cities Gas Co. v. Illinois Commerce Comm’n, 163 Ill. 2d

1, 11 (1994). Here, we can find no error in the Commission’s interpretation of the statute due to

its compliance with rules of statutory interpretation, and given that interpretation, we cannot find

error with its decision to ignore recent precedent that allowed the OPEB asset or liability to be

included in the rate base. Accordingly, we cannot find that the Commission’s disallowance was

reversible error.

¶ 150 Finally, Ameren contends that we must reverse the Commission’s decision because the

Commission violated state law by improperly deciding the OPEB issue on rehearing, while

evidence was still being considered for the refiled Grid and Rate Plans in violation of due process

requirements that resulted in prejudice to Ameren. We strongly disagree.

¶ 151 Ameren’s argument is premised on the “placeholder” status implemented by the

Commission following its rejection of Ameren’s initial Grid and Rate Plans. Therein, the

placeholder initially selected by the Commission was from the most recent docket, which was an

EIMA docket that would have allowed for inclusion of the OPEB asset or liability. We do not find

the “placeholder” setting determinative of the issue and further find Ameren’s claim that the initial

order did not remove the OPEB asset from the rate base a gross misrepresentation of the

Commission’s initial order.

52 ¶ 152 As noted above, the initial order specifically found that Ameren’s proposal to include its

OPEB contra-liability (asset) in rate base was “inconsistent with Commission practice and law”,

as required by section 16-108.18(d)(3)(A) of the Jobs Act. 220 ILCS 5/16-108.18(d)(3)(A) (West

2022). Further, the Commission specifically found that Ameren failed to demonstrate that the $100

million to the OPEB fund was sourced from shareholder funds and noted that it had previously

made the same decision over ten years earlier. The Commission’s initial order also rejected

Ameren’s EIMA argument related to the inclusion of pension assets noting that the current statute

did not contain the same language and this was not an EIMA filing. The Commission also noted

that it had rejected Ameren’s similar argument in Docket No. 20-0308 and rejected Ameren’s

alternative options again rejecting Ameren’s claim that the funds were shareholder provided, as

well as stating that it would not allow the utility to make money off ratepayer funds. Any review

of that order as stating that OPEB would be included is truly misguided.

¶ 153 While it is clear that Ameren did not raise the issue in its request for rehearing, the issue

was raised by Staff in its responsive testimony. While Ameren claims it was deprived of any

opportunity to address the issue on rehearing, our review of the record fails to reveal any objection

to Staff’s comments or any request for leave to submit additional evidence that would have

afforded Ameren the opportunity to address the comments in Staff’s brief. As Ameren failed to

raise the issue before the Commission in any manner prior to its appeal, we find the issue forfeited.

See Village of Roselle v. Commonwealth Edison Co., 368 Ill. App. 3d 1097, 1109 (2006)

(arguments not presented below are forfeited and cannot be raised for the first time on appeal).

¶ 154 Ameren also argues that the refiling order improperly relied on the initial and rehearing

orders without assessing Ameren’s evidence and the Commission acted arbitrarily in in its refiling

order. The initial argument is based on Ameren’s mistaken conclusion that the initial order

53 included the OPEB asset in the rate base, when based on the specific language in the order, it

clearly did not. As such, we find no merit in this argument. Ameren’s second argument contends

that the Commission acted arbitrarily in three ways. The first is based on the Commission deciding

the issue in the rehearing and the lack of due process. As this issue was previously addressed, we

decline to address it further.

¶ 155 The second basis was that the Commission departed from “long-standing practice

regarding the treatment of this asset.” This issue was also previously addressed based on the

Commission’s interpretation of the statute and its elimination of considering EIMA-based

decisions that were based on a statute that specifically allowed inclusion compared with the new

statute that did not. As this issue was also previously addressed, we decline to address it further.

¶ 156 The third basis claimed that the Commission was arbitrarily treating the shareholder funds

that benefited customers and employees differently than other investments, with no valid basis for

the differing and adverse treatment. While certainly more compelling than the previous arguments,

we do not see that the argument was ever presented to the Commission.

¶ 157 A long-standing general rule prohibits advancing new issues and arguments on appeal.

Mabry v. Boler, 2012 IL App (1st) 111464, ¶ 15. Such arguments are classified as forfeited (id.)

except in certain circumstances not raised here. See Matthews v. Avalon Petroleum Co., 375 Ill.

App. 3d 1, 8 (2007). Here, even if the special circumstances were requested, no argument was

presented that contended that “ ‘the act complained of was a prejudicial error so egregious that it

deprived the complaining party of a fair trial and substantially impaired the integrity of the judicial

process itself.’ ” Id. (quoting Lange v. Freund, 367 Ill. App. 3d 641, 649 (2006)). Accordingly, we

decline to address the third issue due to Ameren’s forfeiture of the issue.

54 ¶ 158 D. ROE

¶ 159 Finally, Ameren argues that the Commission’s ROE for Ameren was at a level below the

returns on investment for comparable risks, and particularly, below ComEd, a utility facing

directly comparable risk, which disincentivized investment in Ameren. It therefore requests

reversal of the Commission decision.

¶ 160 The purpose of the Utilities Act is to provide “adequate, efficient, reliable, environmentally

safe and least-cost public utility services at prices which accurately reflect the long-term cost of

such services and which are equitable to all citizens.” 220 ILCS 5/1-102 (West 2022). The

Commission uses the Utilities Act’s rate of return principles to design and set just and reasonable

rates for Illinois’s least-cost public utility services. People ex rel. Madigan v. Illinois Commerce

Comm’n, 2015 IL 116005, ¶ 29. Those principles include consideration of prudent, reasonable

costs as well as a return on equity. Id. ¶ 30. As noted above, the ratemaking formula is “R (revenue

requirement) = C (operating costs) + Ir (invested capital or rate base times rate of return on

capital).” (Internal quotation marks omitted.) Id. ¶ 7.

¶ 161 Ratemaking “is not an exact science.” Amax Zinc Co. v. Illinois Commerce Comm’n, 124

Ill. App. 3d 4, 11 (1984). Determining rates is a matter of sound business judgment, which the

legislature has entrusted to the Commission. Iowa-Illinois Gas & Electric Co., 19 Ill. 2d at 442.

The Commission, in addition to following Illinois statutory requirements, must also adhere to

United States Supreme Court precedent set forth in Bluefield Water Works & Improvement Co. v.

Public Service Comm’n of West Virginia, 262 U.S. 679, 692-93 (1923) and Federal Power

Commission v. Hope Natural Gas Co., 320 U.S. 591, 603 (1994). It is the latter that is the basis of

Ameren’s contention that it was reversible error for the Commission to disincentivize investment

in one public utility relative to other utilities of comparable risk.

55 ¶ 162 Bluefield stated,

“A public utility is entitled to such rates as will permit it to earn a return on

the value of the property which it employs for the convenience of the public equal

to that generally being made at the same time and in the same general part of the

country on investments in other business undertakings which are attended by

corresponding[ ] risks and uncertainties.” Bluefield, 262 U.S. at 692.

It continued, stating

“The return should be reasonably sufficient to assure confidence in the

financial soundness of the utility and should be adequate, under efficient and

economical management, to maintain and support its credit and enable it to raise

the money necessary for the proper discharge of its public duties. A rate of return

may be reasonable at one time and become too high or too low by changes

affecting opportunities for investment, the money market and business conditions

generally.” Id. at 692-93.

Similarly, Hope held that “the return to the equity owner should be commensurate with returns on

investments in other enterprises having corresponding risks.” Hope, 320 U.S. at 603.

¶ 163 Ameren contends that because its ROE is lower than the one ascribed to ComEd, that

Ameren’s allotted ROE of 8.715% violates the constitutional requirements of Bluefield and Hope.

It argues that because Ameren and ComEd are subject to the identical regulatory regime under the

Jobs Act for the same period, have the same level of creditworthiness, and the ROE was issued on

the same day that “in the absence of any material factor that would lead investors to expect

differing returns, one would think that the Commission would authorize the same ROE for the two

companies.”

56 ¶ 164 We note, however, that Bluefield specifically stated that “no proper rate can be established

for all cases.” Bluefield, 262 U.S. at 693 (citing Wilcox v. Consolidated Gas Co., 212 U.S. 19, 48

(1909)). While Ameren is quick to claim similarities in risk and locality, it fails to address any

differences between Ameren and ComEd. It is public knowledge that Ameren provides service to

central and southern Illinois while ComEd services the northern section of the State. It is equally

well-established that Ameren provides electric delivery service to approximately 1.2 million

customers whereas ComEd services approximately 4 million customers.

¶ 165 At no time did Ameren submit evidence as to whether the customers of the two companies

have the same or similar rates, the age of the infrastructure for both companies, whether the

companies—given their locations—were experiencing similar electricity demand requests from

their customers, deficiencies in infrastructure or even whether both companies required similar

amounts of investment capital to operate. While Ameren claims that the Commission erroneously

found that the different ROEs for each company was “irrelevant,” given the lack of evidence

submitted about any similarity beyond the fact that both were public utilities in Illinois, and no

evidence submitted as to any element analyzed in the differing ROE models, we agree with the

Commission’s finding of irrelevancy.

¶ 166 While Ameren claims that no deference is required for the Commission’s ROE

determination in this case because no specialized knowledge is required for the issue, we disagree.

If, as suggested by Ameren, a single value ROE for each public utility in similar circumstances

was all that was required, there would be no need for the legislature to assign the task of

determining a proper ROE to any entity. The ROE would simply be a value contained within the

statute. However, no such value is found therein, revealing that such conclusion is not what the

legislature intended. Instead, the legislature deferred to the expertise of the Commission which, in

57 Ameren’s case, reviewed every model submitted by the parties, explained why each model was

relevant and accurate or irrelevant and inaccurate, addressed requested adjustments submitted by

Ameren, and determined the ROE. As such, the Commission’s decision on the applicable ROE is

entitled to deference. See United Cities Gas Co. v. Illinois Commerce Comm’n, 163 Ill. 2d 1, 12

(1994); Ameren Illinois Gas Co. v. Illinois Commerce Comm’n, 2025 IL App (5th) 240014, ¶ 105;

Iowa-Illinois Gas & Electric Co. v. Illinois Commerce Comm’n, 19 Ill. 2d 436, 442 (1960).

¶ 167 Ameren also argues that the opportunity cost represented by the difference in ROEs

between Ameren and ComEd is significant and harmful. In support, Ameren relies on the 19 basis

point difference between the two ROEs and the Commission’s reduction from the 8.72% ROE

established in the initial final order to the 8.715% ROE established in the amendatory order. It

claims that if the 0.5 basis points were significantly worthy of change, the difference between the

Ameren ROE (8.715%) and ComEd’s ROE (8.905%) is clearly significant too.

¶ 168 While we agree that the difference between 0.50 basis points and 20 basis points could be

considered significant in certain cases, we cannot find the difference significant here. Notably, in

the case at bar, Ameren initially requested a downward adjustment of 10 basis points due to credit

risk. Such voluntary reduction undermines a finding of significance here. We also note that no

argument was presented as to why the difference, even assuming it was significant, was harmful

to Ameren in this section of the brief. Nor did the section attempt to incorporate any argument

previously presented on appeal.

¶ 169 Finally, Ameren contends that the Commission orders unlawfully disfavor investment in

electric operations in central and southern Illinois. In support, Ameren states that its evidence

established a “continuing adverse effect on the ability of the Company to raise capital at a

reasonable cost and to maintain its financial strength while achieving the State’s energy goals.”

58 While the statement is well-phrased, no citation to the record was provided to support the claim or

address the evidence supposedly supporting the statement. See Ill. S. Ct. R. 341(h)(7) (eff. Oct. 1,

2020). Equally uncompelling is the uncited claim that the Commission’s order “favors ComEd and

imposes an opportunity cost in Ameren Illinois” by favoring electric operation investment in

ComEd instead of Ameren in central and southern Illinois. While we agree that the ROE is slightly

higher for ComEd, no evidence was submitted that more investors were now flocking to ComEd

than Ameren. Ameren points to Matthew Tomc’s June 7, 2024, testimony on refiling. We note

however, that this testimony was in response to Staff’s claim that the cost of capital was beyond

the scope of the refiled proceeding. In support of his disagreement about the scope of the refiling,

Tomc stated that the refiled Grid Plan required funding to meet the requirements of the Jobs Act

stating,

“a deficient rate of return relative to capital markets and utility peers gives

rise to the risk that it could become difficult to attract the capital needed to invest

in the clean energy transition on reasonable terms. The risk is particularly acute

because we find ourselves facing sustained, elevated interest rates and concerned

investors have been expressing negative opinions regarding the supportiveness of

the regulatory environment in Illinois.”

Nothing in Tomc’s testimony confirmed, four months after the ROE was set, that it actually

became difficult for Ameren to attract the needed capital for investment in the clean energy

transition. Further, the interest rates are no longer as high as they were in 2023 and early 2024 5

and no affidavit was provided from any investor expressing a negative opinion about the Illinois

We take judicial notice of the Federal Reserve that began reducing the Federal rate in 2024 and 5

2025 dropping from 5.25%-5.05% in July 2023 to a range of 3.50% to 3.75% as of January and February 2026. 59 regulatory environment. Accordingly, we find little merit in the argument. While the ROE for

Ameren was slightly lower than the ROE established for ComEd, we disagree with Ameren’s claim

that the Commission was rewarding one part of the State while penalizing another. Finally, because

no argument regarding how the ROE was determined in the initial Commission decision was

provided, we affirm the Commission’s ROE of 8.715%.

¶ 170 III. CONCLUSION

¶ 171 For the above-stated reasons, we affirm the Commission’s reduction in funding to

Ameren’s storm hardening project, disallowance of OPEB funds from the rate base, and setting

Ameren’s ROE at 8.715%.

¶ 172 Affirmed.