AMEREN ILLINOIS COMPANY v. ILLINOIS COMMERCE COMMISSION LLC IGS MC USA LLC LLC NRG NRG NRG NRG NRG (2025)

OPINION

¶ 1 Petitioner, Ameren Illinois Company d/b/a Ameren Illinois (AIC), seeks review of the Illinois Commerce Commission's November 23, 2023, order in AIC's rate case. On appeal, AIC argues that the Commission's reduction of AIC's cost of investments related to gas transmission and distribution was against the manifest weight of the evidence and the Commission's requirement that AIC submit a detailed gas infrastructure plan was outside the Commission's authority. AIC also argues that the Commission's calculations for its return on equity (ROE) and long-term debt rate were erroneous. Finally, AIC argues that the Commission's adoption of the AG's low-income tariff proposal was contrary to law and unsupported by the record. For the following reasons, we affirm in part and reverse in part.

¶ 2 I. BACKGROUND

¶ 3 On January 6, 2023, AIC filed proposed tariff sheets, based on a future test year ending December 31, 2024, proposing an increase in its rates and revising other terms and conditions of service for the company, pursuant to section 9-201 of the Public Utilities Act (220 ILCS 5/9-201 (West 2022)). An order suspending the proposed tariff sheets was issued and a case management plan was filed. Numerous parties intervened and voluminous evidence was submitted at the evidentiary hearing held on July 25 and 26, 2023.

¶ 4 On September 28, 2023, an administrative law judge (ALJ) issued a lengthy proposed order addressing both the uncontested and contested issues posited by AIC's filing. On November 16, 2023, the Illinois Commerce Commission issued its final order addressing those same issues. For the sake of brevity, we address only the evidence and findings related to the issues raised on appeal, namely capital investment spending related to AIC's gas distribution and gas transmission plant,¹ the Commission's calculation of AIC's ROE and long-term debt cost, as well as the Commission's long-term infrastructure gas plan mandate and low-income customer tariff.

¶ 5 A. Capital Investment—Gas Distribution Plant

¶ 6 AIC requested $186 million for its gas distribution pipeline investment budget for 2023 and 2024. The State of Illinois Attorney General (AG) requested a $45.5 million disallowance of AIC's requested capital investment spending. AIC's request was based on its Distribution Integrity Management Program (DIMP) which was designed to assess the integrity of AIC's gas system in response to gas pipeline integrity, management, and updated safety requirements issued by the U.S. Department of Transportation (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) (see 49 C.F.R. Part 192 et seq.). The PHMSA regulations address higher risk of gas leaks associated with certain types of leak-prone pipe and provided guidelines related to mitigation of risk related thereto. AIC asserted that its continued investment in the distribution line was necessary to comply with the PHMSA regulations, stating that its distribution lines use mechanically coupled steel, which was prone to leakage as noted by the PHMSA and Illinois statute (see 220 ILCS 5/9-220.3(b)(1) (West 2022)). AIC further asserted that its DIMP analysis also identified that AIC's mechanically coupled steel mains and services were a “top threat to the integrity of the distribution system,” were “prone to leakage,” and were “two of the Company's top leak risks per the DIMP analysis.” AIC estimated having between 600-800 miles of mains with mechanically coupled steel out of its total 8,900 miles of steel mains. AIC's witness testified that investments in those areas proved to reduce leaks and noted that AIC identified over 6,000 leaks per year. He further stated that the methodical replacement strategy targeted at assets with known leakage and identified as prone to leakage by AIC's DIMP accomplished two things: (1) it eliminated current and future leaks caused by mechanical joint failures; and (2) ensured each new service had an excess flow valve installed which protected “the public and employees from a blowing gas situation should excavation damage occur to the service in the future.” AIC further asserted that the capital funding was necessary to replace, test, or monitor those parts of the distribution pipeline in the interest of public safety and reliability of its gas pipeline noting that there was a decrease in leaks from 2016 to 2022.

¶ 7 In response, the AG argued that AIC did not use leak-prone pipe like bare steel, unprotected steel, cast iron, ductile iron and/or copper pipe and that AIC's mechanically coupled steel was not as prone to leakage as the aforementioned materials. The AG further argued that AIC previously completed a large part of the gas distribution line remediations and were well ahead of the deadlines scheduled in the PHMSA regulations. The AG noted that AIC had already completed remediation on 533 miles of mechanically coupled steel pipe out of the estimated 1,233 miles containing that piping. The AG further argued that AIC failed to identify—with specificity—which projects compiled the proposed increase in AIC's main and services category or identify and quantify the alleged risk AIC sought to mitigate in order to determine if its proposed replacements were necessary. The AG argued that AIC should slow the remediation process and a reduction in AIC's capital investment was warranted.

¶ 8 The Illinois Commerce Commission Staff (Staff) recommended approval of AIC's proposed distribution plant infrastructure spending as prudent, reasonable, and necessary for the provision of adequate, safe, and reliable natural gas service. Staff argued, citing City of Chicago v. People of Cook County, 133 Ill. App. 3d 435, 442-43 (1985), that for a disallowance to be approved, the party should address the proposed projects identified by AIC and explain why the investments for those specific projects were imprudent. It further asserted, citing Business & Professional People for the Public Interest v. Illinois Commerce Comm'n, 279 Ill. App. 3d 824, 829 (1996), that the Commission could only disallow costs if the evidence established unreasonableness or imprudence in AIC's business decisions. Staff noted that AIC's focus on removing mechanically coupled steel was because AIC's 600-800 miles of mechanically coupled steel was still one of the top leak risks per AIC's internal integrity management analysis and contributed to over 6,000 leaks annually on AIC's facilities.

¶ 9 IFCUP ² supported the AG's recommendation for AIC plant disallowances. The support was based on adjustments to AIC's revenue requirements.

¶ 10 PIO ³ also supported the AG's recommendation to reduce AIC's plant allowances by 33% for the same reasons as stated by the AG. These included the lack of high risk associated with the AIC gas system, the lack of leak-prone piping, and the lack of project specificity. It argued that AIC failed to meet its burden to demonstrate through the preponderance of the evidence that its investments were prudently incurred. PIO further contended that the investments were not just and reasonable, especially considering the likely reduction in future gas services based on Illinois's decarbonization goals.

¶ 11 The ALJ noted that the general prudence standard was utilized to determine whether AIC's capital investments were reasonable. The ALJ found that AIC's continued replacement of 600-800 miles of mechanically coupled steel pipeline would continue to improve the safety and reliability of AIC's system. The ALJ further noted the dispute between Staff and the AG regarding whether AIC's mechanically coupled steel mains were sufficiently risky to require continued replacement. The ALJ found that the Commission could only disallow costs if the evidence established unreasonableness or imprudence in a utility's business decisions. It noted that the AG and PIO requested the Commission disallow costs “incurred in complying with safety regulations” and the ALJ specifically declined to do so. The ALJ found that neither the AG, nor PIO, refuted the evidence that AIC's investments were necessary to maintain a safe and reliable system or comply with governing pipeline safety regulations. The ALJ found that the AG and PIO failed to meet their burden to show that AIC's capital investments were unreasonable, noting their positions disregarded the need for AIC to replace infrastructure to improve the safety and reliability of its system. The ALJ's proposed order stated,

“Therefore, the Commission rejects the AG's distribution-related plant disallowances for 2023 and 2024. The Commission finds that Ameren Illinois met its burden of proof to show that the costs resulting from AIC's continued replacement of mechanically coupled steel facilities costs were prudently incurred, because the record shows that guidance from PHMSA supports continued replacement of mechanically coupled steel facilities. Because AIC made a prima facie case that these costs were reasonably and prudently incurred, the burden shifts to the AG to make a showing that a specific distribution-related capital project cost should be disallowed. The AG did not do this; instead, the AG made a general distribution-related recommendation that is intended to ‘slow the pace of non-QIP pipeline replacements’ in 2023 and 2024. The Commission notes that the adjustments proposed would deny AIC the recovery of costs prudently incurred to comply with safety regulations, which is an outcome the Commission cannot support. The Commission finds that the distribution-related capital investments proposed by AIC are designed to comply with state and federal safety requirements and address infrastructure that is demonstrated to be prone to leakage. The Commission concludes that these investments are prudent and reasonable and are hereby approved.”

¶ 12 At oral argument before the Commission panel, the AG argued that AIC started with a healthy system that contained very little high-risk pipe. Because of that, AIC aggressively targeted its lower risk mechanically coupled steel or pipe, successfully eliminating its worst offender segments. It argued that “[a]bsent good cause, the company must now slow down to a more sustainable and affordable pace.” The AG further argued that its witnesses fully refuted AIC's narrative that the PHMSA somehow supported continued accelerated replacement of mechanically coupled steel pipe and provided substantial evidence that PHMSA did not characterize mechanically coupled steel as high-risk pipe, but merely suggested utilities consider whether to replace it. It further argued that its witness testified that the alleged risks AIC claimed to reduce through its continued accelerated replacements were negligible, predictable, and could be addressed using traditional integrity management, as the PHMSA demonstrated.

¶ 13 The parties addressed the issue of AIC's distribution plant budget and provided similar arguments to a full Commission panel. The Commission panel disagreed with the outcome in the ALJ's proposed order. More specifically, the Commission found the testimony provided by the AG's expert “persuasive” and “reasonable.” The Commission clarified the issue stating,

“The question before the Commission is not whether pipeline replacements generally improve safety and reliability, but what types of pipes are to be replaced, to what degree safety and reliability are affected, at what pace, and at what cost. The Company has failed to provide information about these factors: it requests to spend $186 million on unspecified mains and distribution plant. The burden is on the utility to prove that its costs are prudently incurred, and it must provide evidence demonstrating why. For these reasons, the Commission adopts the AG's recommendation to disallow $45.5 million in distribution capital additions, which represents a 33% reduction to the 2023 and 2024 distribution main and services capital budgets.”

¶ 14 B. Capital Investment—Gas Transmission Plant

¶ 15 Arguments related to AIC's gas transmission plant were similar to those provided for the AIC's gas distribution system, except that they involved AIC's Transmission Integrity Management Program (TIMP), PHMSA standards related to the Maximum Allowable Operating Pressure (MAOP) of gas transmission pipelines, and High Consequence Areas (HCAs). AIC's proposal requested $348.8 million to “replace existing transmission main with new main to reconfirm the MAOP pursuant to federal regulations.” AIC argued that material and construction costs more than doubled from 2016 to 2023. It further argued that of the 25 projects listed on AIC's revised Schedule F-4,⁴ 18 were investments to either reconfirm or establish the MAOP of the identified transmission pipeline. AIC also argued that the PHMSA transmission regulations required AIC to evaluate and address threats to the integrity of its transmission pipelines, many of which also presented a failure risk due to seam issues, wrinkle bends, construction defects, and pipe manufacturing defects caused by internal, external, and stress corrosion cracking as well as manufacturing, welding, fabrication, and construction defects. It argued that sufficient information was contained in the revised Schedule F-4 as the document was compliant with regulatory requirements.

¶ 16 Opposition was again based on the AG's request that AIC “slow the pace of unnecessary replacements,” noting that the PHMSA regulations required a utility to complete 50% of the transmission pipeline remediations by July 3, 2028, and 100% of the transmission pipeline remediations by July 2, 2035 (see 49 C.F.R. § 192.624(b)(1), (2)). The AG recommended a 75% disallowance ($262 million) to AIG's proposed system investments. It argued that AIC's request was unreasonable and unnecessarily expensive due to replacing pipe instead of less costly alternatives, opining that replacement should only be used as a last resort on the 67.1 miles at issue of AIC's 73.3 miles of transmission assets. It further argued that, at its current pace, AIC would reach 100% PHMSA regulation compliance by 2028, with less than one mile to remediate at that time. The AG further noted that PHMSA estimated the total average cost of compliance with the MAOP rule would be $25.9 million in 2017 or approximately $30 million in 2022, and questioned AIC's estimate of $348 million through 2024 as inexplicably far and above the national average, arguing that AIC's plan lacked justification. The AG argued that PHMSA estimated that only 0.18% of the 168,000 miles of pipeline (300 miles) would require replacement under the MAOP rule. However, AIC planned to rely on replacement for 65% of its MAOP pipeline at issue. The AG recommended opportunistic sampling instead and noted AIC's lack of documentation related to alternative approaches. The AG clarified that it was concerned about rate payers funding unjustified replacement projects and, therefore, also recommended a requirement that AIC develop a comprehensive, cost-efficient plan for MAOP compliance. After AIC complained that the AG witness was relying on outdated data, the witness reconstructed his analysis using June 2023 data obtained from the Oil and Gas Journal and the United States Energy Information Administration (EIA). The revised analysis increased the cost; however, the amount was still significantly less than AIC's request and claimed that AIC's projects exceeded the benchmark by as much as 300% with no justification for the excessive overages. It argued that presenting incurred or budgeted costs was not evidence of prudence.

¶ 17 Staff recommended approval of AIC's proposed gas transmission improvements. Staff expressed concern with AG testimony, noting that the AG's request was improper, in part, because many of the projects it recommended delaying were already completed. It further argued that PHMSA's intent in setting deadlines was consistent with completing the requirements, not delaying them. Staff also indicated that some of the AG's recommended options to confirm MAOP were not included in the federally approved methods enunciated by PHMSA. Staff argued that AIC gave reasoned explanations related to the necessity of the investments in its last rate case and nothing had materially changed regarding the reasonableness and necessity of the projects since that time.

¶ 18 PIO argued that the AG witness testimony was conservative for certain factors including geography, siting, and financial alignment, but even with those factors included, AIC's transmission projects were significantly more expensive than necessary. PIO further argued that because AIC's gas throughput would likely decrease in the future due to movement toward clean energy, it should control its capital spending because the costs of AIC's investments would be socialized across lower sales in the future. PIO recommended a disallowance of $125,483,974 of AIC's proposed transmission capital project rate base due to the speed with which AIC planned to complete MAOP compliance as well as the method of compliance. PIO also relied heavily on non-pipeline alternatives (NPAs) claiming they would be critical in coming years to manage AIC's future risk of stranded assets.

¶ 19 The ALJ's proposed order, citing 83 Ill. Adm. Code 285.6100, found that AIC's analysis of the MAOP reconfirmation methods for the Schedule F-4 transmission projects satisfied Part 285 of the Commission rules related to plant additions in rate cases. The ALJ further found that AIC's evidence was sufficient because AIC provided “the specific descriptions of its capital investments, submitted the required schedule, forms, and descriptions, and AIC's evidence [was] comparable to evidence the Commission has considered in the past.” The proposed order further found that the transmission-related capital investments proposed were designed to comply with pipeline safety requirements and address infrastructure that was prone to leakage. It concluded by stating,

“As this work is being done in accordance with federal rules or as the result of safety concerns and public works projects the costs are reasonable, prudent, and included in rate base. It is for these reasons that the Commission declines the AG's request to order [AIC] to develop and file an MAOP and records compliance plan before proceeding with any significant replacement work for MAOP reconfirmation or material verification. The Commission concludes that these investments are prudent and reasonable and are hereby approved.”

The ALJ's proposed order further stated that the potential use of NPAs would be an appropriate subject to investigate during the Future of Gas Process proceedings.

¶ 20 At oral argument before the Commission, the AG argued, regarding the MAOP reconfirmation, that the ALJ's proposed order was in “lockstep with its flawed approach to distribution” by approving the entire AIC request. It claimed that the ALJ's proposed decision ignored facts demonstrating that AIC was abusing the PHMSA regulations to the detriment of its rate payers. In support, the AG argued that AIC was using the replacement—which was the most expensive method available—despite PHMSA's significantly cheaper alternatives and was ignoring the regulatory directive to only use replacement as a last resort when pipe reached the end of its useful life. It further argued that AIC provided no evidence that it was fairly assessing the alternatives, and was essentially saying, “trust us, we checked.” It further addressed the likelihood of needing to replace that much pipeline when PHMSA estimated that only 0.18% of the nation's onshore transmission pipeline would require replacement and AIC was replacing 65% of its line. It also argued that AIC's MAOP replacements were not cost-effective with some being 300% higher than the industry benchmark and that AIC was front loading the work by achieving 100% compliance nearly seven years earlier than necessary. The AG argued that the ALJ's proposed order regarding MAOP was neither grounded in fact, nor law, and demonstrated the need for significantly more transparency and a plan that utilized the time available to moderate the effect of the costs on consumers. Transparency and a plan would ensure that AIC was not unreasonably driving up costs by ignoring key protections and options provided by PHMSA.

¶ 21 Following additional briefing, the Commission disagreed with the ALJ's proposed order. Instead, the Commission found the record was insufficient to approve AIC's proposed MAOP budget, further finding the AG demonstrated AIC's lack of detail on a per-project basis and other reasonable potential (and less costly) alternatives. The Commission further found that the information provided by AIC did not “enable the Commission, Staff, or stakeholders to recreate, verify, or assess [AIC's] analysis” and held that AIC failed to satisfy its burden to justify its test year project costs, citing section II of its order addressing the legal standard which specifically stated that it was declining to follow decisions in earlier dockets that reflected a misreading of City of Chicago v. People of Cook County, 133 Ill. App. 3d 435, 443 (1985).

¶ 22 The Commission also found that the AG demonstrated that AIC would reach the 50% of the MAOP reconfirmation in 2023 and would complete the MAOP work by 2028, nearly seven years before the 2035 compliance deadline. While the Commission acknowledged AIC's “responsibility to ensure its system is safe, reliable and in compliance with all federal and state regulations,” it found that AIC must also consider the costs and timing of investments to meet those responsibilities. The Commission noted the usefulness of benchmark analysis, but was unwilling to apply the benchmark test to AIC's MAOP reconfirmation projects already in service because those projects ensured AIC was complying with PHMSA regulations. However, the Commission found the AG's benchmark analysis and witness testimony supported the Commission's concerns “with the cost and pace of the Company's MAOP reconfirmation efforts and is relevant when scrutinizing AIC's test years costs.” Therefore, the Commission applied the AG's 75% disallowance but limited application to AIC's $63.35 million MAOP test year budget for 2024, thereby reducing the 2024 budget by $47.51 million, leaving AIC $15.84 million to apply to MAOP in 2024. The Commission order also required AIC to develop an MAOP and Records Compliance Plan to assist the Commission in assessing whether AIC was fairly considering its options when pursuing MAOP reconfirmation work. The Commission declined to adopt the requested NPA analysis but noted it was an important topic for “further refinement in the ‘Future of Gas’ proceedings.”

¶ 23 C. Mandated Long-Term Infrastructure Gas Plan 5

¶ 24 In addition to requesting disallowance of AIC's gas distribution and gas transmission working capital budget, the AG requested the Commission require AIC to file a long-term infrastructure gas plan and set forth nine items, some of which were duplicative with the information required to be filed in a Schedule F-4, to be addressed for all planned projects and five topics to be addressed regarding completed projects.

¶ 25 PIO also recommended the filing of a long-term infrastructure plan. In support, it argued that while AIC likely had an internal system plan, the lack of any transparent planning process made it challenging for anyone to determine whether AIC was prioritizing least-cost, least-risk, prudent investments that were likely to be used and useful. PIO argued that long-term gas system planning was particularly critical considering Illinois's decarbonization goals and the likely impacts of electrification on natural gas distribution infrastructure. It argued that rate cases were not a sufficient substitute for this type of planning but noted that “long-term planning can aid the Commission in future rate cases.” They asserted that a long-term integrated infrastructure planning process would give the Commission valuable information that would aid its prudence review in “future rate cases.” It argued that other states, including New York, Colorado, Minnesota, Washington, and Oregon already required these filings. PIO further asserted that the Commission could not, and should not, rely on AIC to plan its system in a manner that was consistent with the state's affordability, safety, reliability, and climate goals without oversight. PIO noted that while AIC had a net zero emission goal, it had not presented any coherent plan to achieve that goal, and its aggressive planned gas infrastructure plant investments could not be squared with its rhetoric. PIO requested the Commission initiate transparent planning processes that, among other things, would help the Commission assess the impacts of electrification on AIC's system, manage the pace of AIC's investments, and mitigate customer bill impacts. PIO also recommended two planning processes: the first being a one-time statewide “Future of Gas” proceeding that would commence shortly after the conclusion of AIC's rate case and the second being a utility-specific biennial integrated infrastructure process starting in 2025.

¶ 26 AIC argued there was no legal authority to mandate an infrastructure gas plan. It noted that while Public Act 102-0662 (eff. Sept. 15, 2021), more commonly known as the Climate and Equitable Jobs Act (CEJA), imposed certain planning requirements for electric utility service, it did not impose the same requirement for gas utilities, which could be indicative of legislative intent. It further argued that any long-term infrastructure gas plan was beyond the scope of AIC's rate case, especially since the plans proscribed by the AG and PIO were intended for use by the major gas utilities in Illinois.

¶ 27 Staff argued that an additional, comprehensive infrastructure plan was unnecessary noting that AIC was already required to file significant support for its infrastructure spending in its rate cases pursuant to 83 Ill. Adm. Code 285.110 et seq. Staff noted that the Code provided a detailed list of standard information requirements designed to assist in review of filings for rate increases under the Public Utilities Act. Staff also argued that any long-term infrastructure gas plan was beyond the scope of AIC's current rate case.

¶ 28 The ALJ's proposed decision found the requested requirement was “beyond the scope of this case” stating,

“These proposals relate to future filing requirements and have no bearing on the Commission's review of the reasonableness of [AIC's] rates proposed here. Furthermore, the Commission cannot approve policies in this case that would apply to or impact other utilities where those utilities have not had notice and an opportunity to participate in this proceeding.”

Therefore, the ALJ's proposed decision rejected the AG's and PIO's recommendation regarding such plans and stated such topic was better suited in other manners.

¶ 29 Oral argument was presented to the Commission on this issue. PIO argued that its case boiled down to its claim that AIC's spending was not prudent or reasonable, particularly considering affordability challenges already faced by AIC's customers and “the anticipated impacts of electrification on [AIC's] system.” As to the long-term gas infrastructure planning, PIO's argument was based on a study by Electric Power Research Institute that ultimately determined that there would be a 19 to 40% “decrease in natural gas use in [AIC's] service territory by 2050” for “buildings, transportation, and industry” based on the CEJA requirements. More specifically, it argued that AIC's customers for homes and businesses, i.e., “buildings” would decrease 38 to 56% by 2050. It was this expected decrease in gas usage that was the basis of PIO's request for a long-term gas infrastructure plan. The plan would address “electrification scenarios, forecast changes in its infrastructure needs, based on changes to its gas, sales, peak demand, and customer count potentially on a neighborhood by neighborhood basis.” PIO further argued that this sort of detailed analysis would “ensure that [AIC's] capital investments aligned with the state's goals” toward electrification. PIO noted AIC's argument that such a request was improper in a rate case and PIO essentially replied that a long-term plan was required because AIC's current capital investment schedules failed to address future electrification and was instead spending money on plant currently in existence that might not be in existence in the future.

¶ 30 Commission Chairman Scott noted that in a different case presenting oral argument on the same issue that it was argued that “CEJA went out of its way to prescribe long-term planning—infrastructure planning on the electric side,” but “went out of its way to not prescribe that on the gas side.” Chairman Scott asked, either from a CEJA or legal perspective, for a basis of authority to require long-term planning for infrastructure. PIO's counsel responded that he did not believe “the legislature considered this and thought it was a bad idea.” He argued that section 10-101 of the Public Utilities Act (220 ILCS 5/10-101 (West 2022)) granted the Commission the power to hold investigations, inquiries, and hearings concerning any matters covered by the act. He also relied on section 8-101 (id. § 8-101),⁶ stating that the statute should be interpreted broadly to include requiring AIC to prepare the plan. PIO's counsel also stated that Michigan and Minnesota granted infrastructure plans for electricity without any statutory authority. Chairman Scott noted that Minnesota had a statute that directed the gas utilities to provide a decarbonization plan and therefore did not believe Minnesota was the best example. PIO's counsel acknowledged that CEJA did not contain a “specific delineated gas distribution planning requirements,” stating “certainly the legislature might consider that at some point, but we don't have that yet.” Chairman Scott also noted that CEJA did not include “electrification of the building sector.” PIO's counsel argued that while there was no “mandate” there were “signals regarding electrification.”

¶ 31 Ultimately, the Commission agreed with the AG and PIO recommendation to require AIC to file a detailed infrastructure plan. The Commission agreed with PIO that while AIC likely engaged in internal system planning, AIC “does not submit a public long-term system plan, which creates an inherent information asymmetry between [AIC] and the Commission.” It noted that “AIC's lack of transparent planning processes” made it “challenging for the Commission, customers, and other stakeholders to determine whether AIC” was prioritizing “prudent investments that were likely to be used and useful.” The Commission agreed “that AIC's capital spending (and associated planning, budgeting, and project section processes) merits careful consideration in this and future rate cases.” It found authority for its mandate pursuant to sections 4-101, 9-201(c), 9-211, and 8-501 of the Public Utilities Act (220 ILCS 5/4-101, 9-201(c), 9-211, 8-501 (West 2022)), and Abbott Laboratories, Inc. v. Illinois Commerce Comm'n, 289 Ill. App. 3d 705, 712 (1997). The Commission mandated AIC to file a long-term infrastructure plan every two years, identifying 12 topics for inclusion, beginning July 1, 2025, “to aid in the Commission's informed review of this and the Company's future rate increases.”

¶ 32 D. Return on Equity Calculation

¶ 33 Numerous models to determine the return on equity (ROE) were submitted and contained ranges determined by the experts. AIC's expert created a range between 10.30% to 11.35%. AIC proposed an ROE of 10.30%. The AIC expert's analysis was based on “market-based common equity cost rates of companies of relatively similar, but not necessarily identical, risk to the Company” which was the Utility Proxy Group comprised of United States natural gas utilities. AIC's witness then used three market-based models to develop the ROE range: (1) the discounted cash flow (DCF) model, (2) the risk premium model (RPM), and (3) the capital asset pricing model (CAPM). Thereafter, the witness applied several AIC-specific risk adjustments. Notably, each of the models were based on additional data. The witness found the DCF model had an ROE of 9.54% using both projected and current interest rates but noted that, despite Commission preference for values based on current market rates, he preferred using projected interest rates. The RPM revealed values of 11.73% using projected interest rates and 11.63% for current interest rates and was based on the “fundamental principle that greater risk required greater rewards” for investors. The final method used was the CAPM which was based on a risk-free rate of 4.03% based on the average of the Blue-Chip consensus forecast of the expected yield on 30-year U.S. Treasury bonds for six quarters ending with the first calendar quarter of 2024 and long-term projections for years 2024 to 2028 and 2029 to 2033. A second CAPM analysis used a risk-free rate of 3.87% based on the three-month average for 30-year Treasury bonds yield ending November 2022. The market risk premium was derived from an average of three historical data-based market risk premiums, two Value Line data-based market risk premiums, and one Bloomberg data-based market risk premium. The CAPM results were 11.75% using projected interest rates and 11.69% using current rates. Once the AIC witness determined the results, he then adjusted the values for size, credit risk, and flotation costs, and determined the ROE range of 10.60% to 11.60% using projected interest rates and 10.56% to 11.56% using current interest rates.

¶ 34 Staff proposed an ROE of 9.89%. The difference between Staff's ROE and AIC's values stemmed from different inputs in the DCF and CAPM analyses, AIC's reliance on the bond yield plus risk premium, ECAPM models not traditionally relied on by the Commission, and what were designated as “inappropriate adjustments to the ROE for size risk, credit risk, and flotation costs.” Staff's DCF estimate was 8.81% and its CAPM estimate was 10.96%. Its final ROE was based on an average of those values. It also used a gas company proxy but eliminated companies that did not have investment grade credit ratings for either the S&P or Moody's, did not pay quarterly dividends, did not have growth rate estimates from the S&P or Zacks Research Wizard, and were a party to a merger or other significant transaction. Thereafter, Staff used a multi-stage DCF that considered stock price, dividends, and an average of DCF growth (9.40%) and quarterly non-constant growth DCF (NCDCF) models (8.23%) to reach its DCF rate of 8.81%.

¶ 35 Staff's CAPM model considered an estimate of the risk-free return, the expected rate of return on the market portfolio, and a security or portfolio-specific measure of market risk. It used the 4.19% yield on four-week U.S. Treasury bills for the first factor. It relied on an analysis of the S&P 500 firms for the expected rate of return, after eliminating non-dividend paying companies and companies with growth rates greater than 30%. The estimated weighted average for expected rate of return for the remaining companies equaled 12.65%. It then determined the risk in the portfolio using Zachs beta estimate and regression beta estimate because they relied on monthly, as opposed to weekly data. The regression beta estimate was 0.76, the Value Line beta was 0.86, and the Zacks beta average was 0.72. Staff found the estimated CAPM ROE was 10.96%. Staff recommended no adjustment and further argued that AIC's RPM analysis was contrary to Commission decisions addressing the factors included in those analyses.

¶ 36 IFCUP proposed an ROE of 9.50%. It believed that AIC's 10.30% rate drastically overstated AIC's cost of capital and would impose exorbitant costs on rate payers for no purpose other than to increase AIC's profit margins. It stated that Staff's ROE of 9.89% was a more reasonable alternative but argued that its analysis was skewed by the inclusion of an outlier CAPM result that was based on an unreasonable growth rate, i.e., growth rates greater than 30%.⁷ IFCUP presented five separate models. The first model was a constant growth DCF model using consensus analysts’ grown rate projects and revealed average and median returns of 9.52% and 9.42%, respectively. The constant grown DCF model using sustainable growth rate estimates revealed average and median DCF results of 9.84% and 9.96%, respectively. This model was based on the FERC method of estimating the expected return on a market by performing a constant growth DCF analysis on each dividend paying company of the S&P 500 index excluding those with growth rates greater than 20%. After determining the weighted average (8.70%) and adjusting the dividend yield (2.09%), the DCF-derived expected return was determined by adding those two values, i.e., 10.79%. The multi-stage growth DCF model suggested a reasonable ROE of 9.2%. The Risk Premium model used a bond yield plus risk premium model. After addressing all the possible inputs, IFCUP found the reasonable ROE would be 9.80%. Finally, IFCUP also presented a CAPM that resulted in an 11.71% expected return.

¶ 37 Walmart provided no specific financial analysis but urged no increase from the previously authorized 9.67%. PIO provided no financial analysis but recommended an ROE below 10.30%.

¶ 38 The ALJ's proposed order disfavored rate models submitted by the AIC and IFCUP, for relying on bases that the Commission previously found were unreliable. Thereafter, the ALJ's proposed order stated,

“The Commission has consistently approved the use of DCF and CAPM models in determining the cost of common equity. Staff's ROE analysis, using DCF and CAPM models, is consistent with the Commission's preferred and accepted methods and does not suffer from the use of repeatedly rejected adjustments or data that introduces unnecessary measurement error or bias. The Commission finds Staff's DCF and CAPM models meet the goals of Hope [Federal Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944)] and Bluefield [Bluefield Waterworks & Improvement Co. v. Public Service Comm'n of West Virginia, 262 U.S. 679, 692-93 (1923)] in allowing Ameren Illinois to attract capital yet charge reasonable rates. Therefore, the ALJ's proposed decision adopted Staff's proposed ROE of 9.89%”

¶ 39 Oral argument before the Commission also addressed this issue. Commissioner Carrigan asked about the impact on AIC if either the Staff or AG ROE was adopted. AIC's counsel did not have an exact dollar figure but stated that

“with respect to credit impact the *** company is not sitting here telling you that it will absolutely face a downgrade if you approve Staff's 9.89 percent. But we would point out that to the extent that cash flows are lower than they would otherwise be, there is some credit pressure we can't predict the precise outcome.”

¶ 40 The Commission's order noted that “[d]etermining the cost of equity capital [was] one of the more challenging tasks in ratemaking,” noting that competing interests required it to authorize an ROE that was neither too low to restrict the utility's access to capital at a reasonable cost, nor too high resulting in rates that were unjust and unreasonable. The Commission noted that AIC used three adjustments and noted that the Commission previously rejected the size and flotation cost risks in previous orders and found the credit risk adjustment unnecessary. The Commission also noted that AIC's ROE relied on weekly beta estimates instead of both weekly and monthly beta estimates and reasserted its preference for five-year betas over two-year betas for CAPM analyses. The Commission also found AIC's ECAPM analysis was flawed because it used adjusted betas instead of raw betas, which rendered the results meaningless. Therefore, the Commission rejected AIC's proposed CAPM and ECAPM analyses. It also rejected AIC's DCF analysis for using a 60-day average stock price instead of using current or spot market prices.

¶ 41 The Commission found little favor with the IFCUP analyses, noting its DCF analysis used outdated stock prices and its CAPM analyses used forecasted Treasury bond yields and weekly beta estimates, all of which were previously rejected by the Commission. It was equally displeased with the non-constant growth DCF models produced by IFCUP and Staff.

¶ 42 The Commission approved of Staff's DCF and CAPM models, finding them consistent with its preferred and accepted methods of determining ROE. The Commission's only issue was the Staff's use of its 12.65% forward-looking market risk premium which was “significantly higher” than the FERC's method, and the expected market returns published by U.S. financial institutions. The Commission found that substitution of Staff's 12.65% with the 10.79% FERC value resulted in a “more reasonable market risk premium estimate, which in turn results in a revised Staff CAPM estimate of 9.47%.” The Commission then averaged Staff's 9.47% CAPM estimate with the Staff's constant growth 9.40% DCF estimate to result in a 9.440% ROE.

¶ 43 E. Long-Term Debt Cost Calculation

¶ 44 AIC requested a 2024 cost of long-term debt of 4.265%. The request was based on coupon rates of long-term debt expected to be outstanding as of December 31, 2024. AIC argued that its recommendation reflected actual pricing terms from 2023, noting that on May 23, 2023, it priced a $500 million 10-year coupon at 4.95%. AIC also expected it would issue an additional $40 million of debt later in 2023 at the same rate. As for 2024, AIC expected to issue $430 million of debt which it forecast at an interest rate of 5.45%.

¶ 45 Staff recommended a 2024 proposed cost of long-term debt of 4.232%. Its recommendation was based on interest rate estimates based on Moody's Daily Long-Term Corporate Bond Yield Average for A-rated utilities as of April 11, 2023, which was 5.07%. It adjusted the long-term yield between 10-year and 30-year U.S. Treasury bonds to account for the difference in maturity leading to a 0.19% reduction from Moody's for a 4.88% 10-year yield and used 5.07% for long-term 30-year debt expected in 2024.

¶ 46 The ALJ noted that the difference between AIC and Staff calculations was the interest rate applied to future issuances. AIC estimated an interest rate of 4.95% based on “actual pricing terms of the 2023 issuance,” i.e., a forecasted interest rate and Staff calculated its rate based on current market interest rates. The ALJ noted that the Commission regularly relied on “current, observable market interest rates rather than forecasted interest rates given the difficulty of accurately forecasting interest rates.” The ALJ also found reliance on those rates because AIC “failed to provide supporting documentation of the debt being issued at 4.95%.” Therefore, the ALJ approved Staff's proposed long-term debt rate of 4.232%.

¶ 47 The Commission decision noted that Staff did not update the 2023 issuances because AIC “failed to provide supporting documentation of the debt being issued at 4.95%.” The Commission also noted that the record contained no supporting documentation of the debt being issued at 4.95%. Therefore, the Commission affirmed that ALJ's long-term debt rate of 4.232%.

¶ 48 F. Low-Income Customer Consideration and Rider LICA

¶ 49 Public Act 102-0662 (eff. Sept. 15, 2021), commonly referred to as CEJA, contained a mandate to the Commission to “conduct a comprehensive study to assess whether low-income discount rates for electric and natural gas residential customers [were] appropriate.” 220 ILCS 5/9-241(d) (West 2021). The Commission study was required to address: (1) eligibility requirements; (2) rate structures, including tiered discounts based on income; (3) appropriate recovery mechanisms, including volumetric charges and customer charges; (4) appropriate verification mechanisms; (5) measures to ensure customer confidentiality and data safeguards; (6) outreach and education procedures; and (7) “the impact that a low-income discount rate would have on the affordability of delivery service to low-income customers and customers overall.” Id.

¶ 50 The Commission presented its study on December 15, 2022. The recommendations included utilities offering a tariffed low-income discount rate if they met the threshold for applicability.⁸ The recommendations also included tiered discounts based on different income levels (applicable only to the delivery services charges), a cost recovery mechanism consistent with Illinois law and Commission practice, support for the clean energy goals and policies of Illinois, and leverage of existing programs and processes to streamline administrative processes and minimize costs related to eligibility requirements, verification mechanism, and outreach, without sacrificing the confidentiality of sensitive customer data. Id. Once the study was complete, the legislature provided the Commission with “the authority to permit or require electric and natural gas utilities to file a tariff establishing low-income discount rates.” Id.

¶ 51 As part of its rate case, AIC filed a proposed low-income customer rider. AIC's proposal was two-tiered and was based on residential customers who qualified for LIHEAP ⁹ or PIPP ¹⁰ benefits under the Energy Assistance Act (305 ILCS 20/1 et seq.). Under AIC's proposed rider, customers—based on income—would receive monthly credits in fixed amounts. A customer whose income did not exceed 200% of federal poverty levels (FPL) would receive a monthly credit of $10 (Tier 2 customers). If the customer's household income was 50% or less of the LIHEAP qualifying metric (e.g., 100% FPL), the fixed monthly credit would increase to $20 (Tier 1 customers). AIC's proposal would reach approximately 22% of its residential customers and would provide monthly credits that created a revenue loss ranging from $9.4 to $26.7 million.

¶ 52 Staff proposed a similar plan as AIC but recommended a $30 credit for Tier 1 customers and a $20 credit for Tier 2 customers. Staff's plan also included a third tier for customers with income up to 300% of the FPL who would receive a $10 credit (Tier 3). AIC noted that this plan would increase eligibility from 22% of its customer base to 37% of its customer base. The increase would also increase the range of revenues required to offset the credits on the high end from $26.7 million to $60.7 million. Residential customers who did not receive the credit would have an increased monthly bill ranging from $1.55 to $3.53. Non-residential customers using less than 4,000,000 therms ¹¹ per year would see an increase in their bill ranging from $15.50 to $35.30, and non-residential customers using more than 4,000,000 therms per year would see an increase in their bills ranging from $581.25 to $1,323.75.

¶ 53 The AG proposed a five-tier system based on FPL criteria. It expanded eligibility to residential customers with household incomes up to 300% of FPL and proposed a percentage discount for both service and delivery that correlated with the customer's income. Under the AG proposal, customers with income 0-50% of the FPL would receive a 75% discount of the bill (Tier 1), customers with income between 50-100% of the FPL would receive a 55% discount of the bill (Tier 2), customers with income between 100-150% of the FPL would receive a 25% discount of the bill (Tier 3), customers with income between 150-200% of the FPL would receive a 10% discount of the bill (Tier 4), and customers with income between 200-300% of the FPL would receive a 5% discount on their bill. AIC argued that this proposal was even more expensive than Staff's proposal.

¶ 54 PIO proposed a two-tier system, but it relied on the state median income (SMI) instead of the FPL. For customers below 30% of SMI, PIO proposed a 60% monthly credit. Customers between 30 and 60% would receive a 20% monthly bill credit. AIC projected that 30% of its residential customers would be eligible for the credits and PIO's proposal would exceed the costs of Staff's proposal by over $20 million. Residential customers not receiving the discount would see increases as high as $4.88 on their monthly bill. Non-residential customers under 4,000,000 therms would have monthly increases as high as $48.80, and non-residential customers using over 4,000,000 therms would have monthly increases as high as $1,830.

¶ 55 All the proposed riders would place recovery responsibility on non-qualifying residential and business customers. The ALJ's decision adopted AIC's proposed rider with the Staff's proposed modification to include a three-tier system. The ALJ found that Staff's proposal was consistent with the Commission's report and would provide significant discounts to low-income customers while mitigating the adverse impacts to non-participants. The ALJ further found that Staff's proposal was more expansive than AIC's proposal, would aid more low-income customers, was easier to implement than the AG or PIO proposals because it would rely on LIHEAP for two of the three tiers for verification, and allowed for self-certification for the third tier. The ALJ also noted that the PIO and AG proposals were inconsistent with the Commission study in applying a percentage discount, instead of just a delivery discount.

¶ 56 At oral argument before the Commission, the AG argued that the Illinois legislature granted the Commission considerable flexibility when it authorized implementation of discount rates. It recommended the Commission take the opportunity to not “simply trim around the edges of unaffordable utility service” but provide “transformational support to struggling rate payers.” The AG noted that its proposal was similar to those in other gas rate cases, and this would give the Commission “the opportunity to approve consistent transformational discount rates across the state.” It argued that AIC and Staff's proposals were “not sufficiently targeted to ensure that the bulk of the benefit goes to those who need it the most.” It stated that its proposal provided an additional $235-$355 per year to a customer with a household income of 99% of the federal poverty level, which was significantly more than AIC or Staff's proposals. The AG further stated,

“Further and importantly, the People proposed that the company recover the cost of the program from rate payers on a per therm basis rather than through a fixed charge as proposed by the company and Staff. This means that those who use more gas will pay more toward the program. As a result, the People's proposal would actually cost the average residential rate payer less than Staff's less expansive program. In summary, the People ask the Commission to adopt their proposal because it is targeted to help those that need it the most, provides a greater benefit than the Company and Staff's proposals, and can be implemented at a reasonable cost to other rate payers.”

¶ 57 Commissioner Reddick asked the AG to elaborate on the position that its plan cost less than Staff's plan. In response, the AG explained that its proposal would cost approximately $19.25 per year and the Staff's proposal would cost $28.22 to the average residential customer. The AG clarified that the amount would be higher for higher-use customers. Chairman Scott also addressed the LIDR ¹² rider and asked if there was an issue, since they were talking about the whole bill, concerning the tax portion of the bill. He asked if there was “any legal prohibition against including taxes in that, under a theory that you're asking someone else to assume another person's tax obligation?” The AG responded that it did not get into the tax issue and stated if it was an issue, the proposal could be easily amended to exclude the taxes. However, the AG stated the “full bill discount” was the most equitable way to provide the discount.

¶ 58 The Commission rejected the ALJ's proposed decision on this issue, adopted the AG's proposal, and directed AIC to implement the proposal by October 1, 2024. The Commission concluded that the AG's proposal was consistent with the “Commission's report to the General Assembly on low-income rates and would provide significant discounts to low-income customers, while mitigating the adverse impacts to non-participants.” The Commission stated that it only “tentatively recommended” that the low-income programs apply to “delivery services only.”

¶ 59 The Commission recognized that applying the discount to the entire bill would increase the amount to be paid by non-eligible customers, but also noted that the program introduced potential utility system benefits and encouraged AIC to prioritize energy efficiency programming to reduce bills overall. The Commission found that the AG's five-tiered system was more expansive than any other proposal and would provide more targeted relief to the lowest-income customers, including those that were not LIHEAP or PIPP eligible. The Commission also noted that having the fifth tier self-certify would reduce administrative costs and increase program effectiveness. The Commission required AIC to annually audit those Tier 5 enrollees to verify eligibility. However, the Commission precluded AIC from removing any ineligible customers from the program based on the audit stating, “that information would be used in the future to determine success or potential misuse of the program,” and the Commission might revisit or revise its decision depending on the audit results.

¶ 60 On December 15, 2023, AIC moved for rehearing, listing as its issues the Commission's decisions related to AIC's maintenance of its distribution and transmission systems, the mandate to prepare a detailed long-term gas infrastructure plan, AIC's recovery of costs, AIC's cost of long-term debt, AIC's common equity ratio, AIC's return on equity, and the Commission's adoption of the AG's low-income rider. Additional requests for rehearing were presented collectively by IIEC/FEA related to revenue allocation and IFCUP related to cash working capital. On January 3, 2024, the Commission denied all the requests for rehearing. AIC timely appealed.

¶ 61 II. ANALYSIS

¶ 62 Our review of the Commission's order is limited to that statutorily proscribed. 220 ILCS 5/10-201(e) (West 2022). This court is required to 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, or (4) the Commission proceeding was in violation of state or federal constitution or laws and prejudiced the appellant. Id. § 10-201(e)(iv). This court presumes the Commission's decision is “prima facie reasonable,” and the burden of proof on all issues raised in the appeal is on the appellant. Id. § 10-201(d). The Commission decision is “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).

¶ 63 A. Capital Investment—Gas Distribution Plant

¶ 64 AIC first argues that the Commission erroneously disallowed $45.5 million of AIC's gas distribution capital additions, which represented as a 33% reduction to the 2023 and 2024 distribution main and services capital budgets. In support, it argues that the Commission's decision did not sufficiently explain its reasoning for accepting the AG's recommendation, which contravened the Commission's prior practice of rejecting unsupported recommendations. It further argues that the Commission's finding that AIC did not support its distribution plant investments was contrary to the record and the Commission erred by adopting the AG's argument that state and federal law did not warrant investments in replacing mechanically coupled steel facilities because the evidence revealed the opposite.

¶ 65 An Illinois public utility is entitled to recover the prudent and reasonable costs of delivering service. 220 ILCS 5/1-102(a)(iv) (West 2022). “ ‘Prudence is that standard of care which a reasonable person would be expected to exercise under the same circumstances encountered by utility management at the time decisions had to be made.’ ” Illinois Power Co. v. Illinois Commerce Comm'n, 339 Ill. App. 3d 425, 428 (2003) (quoting Illinois Power Co. v. Illinois Commerce Comm'n, 245 Ill. App. 3d 367, 371 (1993)). “When a court considers whether a judgment was prudently made, only those facts available at the time judgment was exercised can be considered.” Id. “Hindsight review is impermissible.” Id. (citing Illinois Power Co., 245 Ill. App. 3d at 371). “[T]he prudence standard recognizes that reasonable persons can have honest differences of opinion without one or the other necessarily being ‘imprudent.’ ” Id. at 435.

¶ 66 While AIC's brief cites four Commission decisions in which the Commission rejected the AG's argument requesting disallowances of capital expenditures (Ameren Illinois Co. d/b/a Ameren Illinois, No. 20-0323 (Dec. 15, 2022); Northern Illinois Gas Co. d/b/a Nicor Gas Co., No. 21-0098 (Nov. 18, 2021); Northern Illinois Gas Co. d/b/a Nicor Gas Co., No. 19-0294 (June 10, 2021); Ameren Illinois Co. d/b/a Ameren Illinois, No. 20-0308 (Jan. 13, 2021)), the Commission found that the utility presented sufficient evidence to justify the disputed capital projects in each of those cases. Notably, AIC does not argue that the same type of evidence presented in those cases was presented for its distribution plant evidence in the current case. Further, as to the prior decisions involving AIC, it is well established that the Commission is not bound by its prior orders under the doctrine of res judicata. United Cities Gas Co. v. Illinois Commerce Comm'n, 163 Ill. 2d 1, 22-23 (1994); Commonwealth Edison Co. v. Illinois Commerce Comm'n, 2016 IL 118129, ¶ 24. Accordingly, we find no merit in AIC's argument that the Commission's order in this case was contrary to its prior practice of rejecting unsupported recommendations.

¶ 67 The Commission's order found “[i]n this case, numerous elements of AIC's prima facie case have been sufficiently met with opposing evidence.” Some of that opposing evidence included the AG's bases for disallowing AIC's continued and accelerated pace of replacing its distribution plant. These reasons included: (1) the fact that AIC had very little high-risk leak-prone pipe ¹³ (LPP) on its system; (2) AIC was pushing replacement of mechanically coupled steel (MCS), which was of lower risk than LPP; (3) AIC failed to identify, with specificity, what projects (pipe segments) made up the proposed increase in its main and service category spend; and (4) AIC failed to identify or quantify the alleged risk it sought to mitigate, or provide evidence demonstrating that the proposed replacements were needed.

¶ 68 While AIC contends it presented sufficient evidence, the record reveals that in response to the AG's questions regarding the level of risk associated with LPP and MCS, AIC took no position and had “not compared the level of risk for mechanically couple steel to [LPP] materials.” Similarly, despite the AG establishing that there were several subsets of MCC with different associated risk levels, AIC declined to provide evidence as to which subset was at issue in any of its proposed distribution projects. Instead, it agreed with the AG witness that there were different subsets of MCS facilities on the system for AIC to address; however, it found that “all of those facilities” might be considered for replacement pursuant to the PHMSA Advisory Bulletin. Further, while the AG classified leaks on a scale of 1 to 3 with 1 being the worst, despite AIC's claiming that it had more specific information related to its leaks in its PHMSA filings and its internal performance metrics, we do not see where any leak information, beyond a claim that 6,000 leaks were found annually, was submitted in this case. We do not see where AIC graded its risks on a scale or provided information as to where any of the 6,000 leaks were found annually landed on the 1 to 3 scale, what part of the system was most prone to leak, and what part of the system had the highest-risk leaks. Instead, the AG's questions related to AIC's request for capital on its distribution system were met with a response from AIC that the bases of its requested plant expenditure were “safety and reliability.” While the responses are noble in theory, they are seriously lacking in detail. Accordingly, we cannot find that the Commission's conclusion that AIC failed to support its distribution plant investments was contrary to the manifest weight of the evidence.

¶ 69 Finally, AIC argues that the Commission erred in adopting the AG's disallowance of distribution investments based on the AG's claim that state and federal law no longer warranted investment in replacing MCS facilities. While the AG made assertions that “the QIP regime is over” and alleged a misapplication of “PHMSA regulations to support continued accelerated replacement of MCS,” we do not read, and AIC provides no cite from, the Commission decision where the Commission “adopted” those statements by the AG. Our review of the Commission decision shows that the Commission simply found the AG's “arguments and rationale persuasive” after generally addressing the four issues raised by the AG in response to AIC's requested capital expenditure. More specifically, the Commission's finding the AG's arguments and rationale persuasive was provided immediately following the AG's argument that AIC “failed to identify any ‘unknowns related to its coupling in service’ or demonstrate that either leak reporting or these unknowns (if any) in the aggregate rise to a level necessitating a replacement program.”

¶ 70 We further read the Commission decision to only find that the Commission agreed with the AG that AIC “did not describe or identify individual MCS replacement projects in testimony but only provided a general category of spend—MCS—making analysis of individual projects difficult.” As noted by the Commission, it was AIC's obligation to support its proposal “in whole or in part” and its choice in presenting “bundled or individual projects does not alter the requirements of section 9-201.” At most, the testimony cited by AIC was provided in general terms except for noting the number of repairs related to equipment failures in 2020, 2021, and 2022.

¶ 71 The Commission specifically stated that the issue was not whether AIC's replacements improved safety and reliability, the issue was “what types of pipes are to be replaced, to what degrees safety and reliability are affected, at what pace, and at what cost.” The Commission found that AIC failed to provide specific information regarding those factors despite requesting to spend $186 million on “unspecified mains and distribution plant.” At no point did the Commission disallow AIC's planned distribution plant because the QIP statute came to an end or the PHMSA regulations were irrelevant. The Commission found that AIC failed to meet its burden of proving the costs were prudently incurred by failing to provide evidence supporting the requested costs. As nothing more than general statements were provided, despite AIC claiming that it had more specific information, we cannot find that the Commission's order disallowing $45.5 million in distribution capital additions was against the manifest weight of the evidence.

¶ 72 B. Disallowance of AIC's Gas Transmission Maintenance

¶ 73 AIC next argues that the Commission erroneously disallowed $47.51 million of AIC's transmission plant capital additions associated with five specific MAOP ¹⁴ transmission projects AIC proposed to place in service in 2024. AIC argues that the Commission's disallowance was contrary to Illinois law, unsupported by the record, and arbitrary and capricious.

¶ 74 In support, AIC first claims, citing Citizens Utility Board v. Illinois Commerce Comm'n, 166 Ill. 2d 111, 121 (1995), that the Commission failed to apply the appropriate legal standard in its review of the plant additions. “A public utility is entitled to recover in its rates certain operating costs” that are “prudently and reasonably incurred.” Id. (citing 220 ILCS 5/1-102(a)(iv) (West 1992)). AIC claims that there “is simply no discretion involved where a utility has established prudence and reasonableness.” We agree. However, prudence and reasonableness must first be established. As noted above, AIC failed to show prudence and reasonableness with its gas distribution capital allocation.

¶ 75 Here, the projects at issue are found in AIC's Schedule F-4. Notably, 18 of the 25 total projects listed on AIC's Schedule F-4 projects were investments in work to either reconfirm or establish the MAOP of the identified transmission pipeline. As to the Commission's disallowance of AIC's 2024 budget related to its transmission lines, five of the seven projects involved MAOP, and are more specifically addressed below.

¶ 76 The first project involved replacement of 3.83 miles of main between Eden and Tilden, Illinois, at a cost of $23.42 million. AIC stated the current pipeline was from the 1970s. It further stated that alternatives considered included maintaining the status quo, retiring the pipeline, de-rating the MAOP pipeline, or pressure testing the pipeline. AIC then provided reasons why those alternatives were rejected. Maintaining the status quo was not facilitating compliance with pipeline safety standards. Retiring the pipeline would require construction of a new pipeline to ensure continuity of service to AIC's customers. De-rating would not allow for adequate services during peak day load and would not resolve the gaps in design and material records, legacy construction techniques, and lacked pressure test documentation, i.e. traceable, verifiable and complete (TVC) records required by PHMSA. Pressure testing was also rejected due to gaps in material design and material records necessary to perform a pressure test.

¶ 77 The second project involved pressure testing seven miles of main, and replacing 0.4 miles of main near Peoria, Illinois at a cost of $16.25 million. This section of pipeline was from the 1960s and lacked the required TVC records. The alternatives of maintaining the status quo, retiring pipeline, and de-rating the MAOP were again considered and rejected for reasons similar to those listed in the first project.

¶ 78 The third project involved replacement of 0.56 miles of main near Bartonville, Illinois. The cost for the replacement, along with a station rebuild, and new pig traps was listed at $11.73 million. There was no breakdown of the $11.73 million cost between the main replacement, station rebuild, and pig traps. It was noted that the pipeline being replaced was from the 1960s and had no TVC records, as required by PHMSA. The alternatives included maintaining the status quo, retiring pipeline, de-rating the MAOP of the pipeline, and pressure testing. The rejection of those alternatives was similar to that seen in the first project.

¶ 79 The fourth project involved replacement of 1.75 miles of main near Henry, Illinois, at a cost of $6.36 million. This pipeline was also from the 1960s and had no TVC records as required by PHMSA. The same four alternatives considered and rejected in the first project were also listed for this project.

¶ 80 The fifth project involved replacing 0.89 miles of main near Mapleton, Illinois, at a cost of $5.59 million. This pipeline was also from the 1960s and had no TVC records as required by PHMSA. Maintaining the status quo was not even considered for this project; however, retiring the pipeline, de-rating the MAOP of the pipeline, and pressure testing were considered and rejected for the same reasons seen in the first project.

¶ 81 The Pipeline Safety Act empowered the Secretary to require owners and operators of a pipeline facility to reconfirm MAOP “as expeditiously as economically feasible.” 49 U.S.C. § 60139(c)(1)(A) (2018). To ensure the MAOP was reconfirmed timely, the regulations provided deadlines that required completed reconfirmation of 50% of identified pipelines by July 3, 2028, and 100% completion of all identified pipelines by July 2, 2035. 49 C.F.R. § 192.624(b) (eff. July 1, 2020). The PHMSA approved six methods to reconfirm a pipeline segment's MAOP including: (1) pressure testing, (2) pressure reduction, (3) engineering critical assessment, (4) pipe replacement, (5) pressure reduction for pipeline segments with small potential impact radius, and (6) alternative technology. Id. § 192.624(c).

¶ 82 In addition to the above information found on AIC's Schedule F-4 submissions, AIC explained that the appropriate method of confirmation depended on numerous factors, including age, condition, construction and materials of the pipeline, capacity requirements, the system's hydraulic configuration, operational considerations, and documentation of pressure test records and material properties records meeting TVC standards. It further noted that the inability to remove a pipeline from service for hydrotesting due to the system's hydraulic configuration was a limiting factor. AIC argued that it was addressing pipeline that had a higher risk of failure.

¶ 83 As stated above, Staff noted that in AIC's last rate case, the Commission concluded that AIC provided reasoned explanations on the necessity of its investments for MAOP reconfirmation requirements, and “nothing materially changed since then.” Staff asserted that AIC's projects were still necessary and nothing in the record supported a departure from the Commission's past decisions on MAOP reconfirmation. Staff recommended the Commission approve AIC's proposed transmission infrastructure spending.

¶ 84 Again, it was the AG who asked the Commission to reject AIC's MAOP budget. The AG claimed that replacement should be the last resort and stated that AIC should be required to provide sufficient justification and alternatives analysis for the MAOP/material verification replacements. The Commission again accepted the AG's 75% disallowance proposal but limited it solely to AIC's 2024 proposals due to prior projects already being completed. The Commission found that AIC failed to satisfy its burden to justify its test year project costs.

¶ 85 Despite this conclusion, we note that the Commission order specifically addressed the F-4 plant updates on page 9 and found AIC's “updates to the Schedule F-4 for plant costs, as accepted by Staff, reasonable and they are hereby approved.” Unlike the gas distribution capital expenditures, AIC provided information in the required F-4 filings about each MAOP project and addressed at length why it was using replacement to address the MAOP reconfirmation requirements. The Commission decision ignores the evidence where AIC explained why it chose each MAOP reconfirmation method. AIC explained that the appropriate method of reconfirmation depended on numerous factors, “including age, condition, construction and materials of the pipeline, capacity requirements, system configuration, operational considerations, and the documentation of pressure test records and material properties records meeting the TVC standards.”

¶ 86 AIC also provided a timeline for its planned MAOP reconfiguration. Of the remaining 73.3 miles of transmission pipeline assets that required remediation as of January 2023, 6.2 miles would be reclassified or abandoned. The remaining reconfirmation would take place over the next eight years and would be completed as follows: 2023-20.3 miles, 2024-11.2 miles, 2025-11.4 miles, 2026-6.5 miles, 2027-14.2 miles, 2028-8.9 miles, and 2030-0.9 miles. AIC further explained that while some alternative methods would meet a portion of the PHMSA MAOP requirements, it would not meet all of them and, in those instances, replacement would fix every issue. It further explained that pressure testing could take the gas service out for several days or even an extended period, which was rarely feasible for transmission lines of a local distribution company. It explained that planned gas service outages were different from the power industry because each gas customer had to be manually turned off at the meter by a gas company representative, the entire system had to be purged of air, then manually turned back on, and appliances relit. AIC said those actions were “costly, resource intensive, and not welcomed by our customers.” AIC further stated that older vintage pipe could also fail during the pressure test which would then require repairs further extending the time and cost of the project.

¶ 87 Equally concerning is the fact that the Commission decision simply eliminated all five of the MAOP projects without noting that most of the work on the Peoria project, i.e., seven miles of main, would utilize pressuring testing for MAOP and only 0.40 miles would be replaced. Similarly, the Bartonville project was only replacing 0.56 miles of the main while the remainder of the funds were to rebuild a station and provide new pig traps. As such, we find that the Commission's order reducing the AIC 2024 budget by 75% with the intent to stop all MAOP reconfirmation based on replacement is arbitrary as it includes MAOP reconfirmation work that was not based on main replacement as well as projects that did not involve MAOP reconfirmation. Accordingly, as to this issue, the Commission's order was not supported by substantial evidence, but was instead controverted by substantial evidence as detailed information was provided by AIC in its Schedule F-4 filings and testimony by its witnesses regarding the MAOP reconfirmation projects. Moreover, we find it disingenuous for the Commission to penalize AIC for allegedly failing to the meet a standard not previously required, i.e., a MAOP and Records Compliance Plan, prior to the issuance of the Commission decision, especially when it provided the statutorily required information. Accordingly, we vacate those portions of the Commission order that removed $47.51 million from AIC's 2024 MAOP budget.

¶ 88 C. Mandate to Prepare Gas Infrastructure Plan

¶ 89 After addressing AIC's distribution and transmission capital project deficiencies, the Commission ordered AIC to prepare and file a “Long-Term Gas Infrastructure Plan” (LTGIP). AIC argues that the Commission exceeded its statutory authority by requiring the plan, that the LTGIP is beyond the scope of a rate case and allows the Commission to evade the notice and comment requirements of a rule under the Illinois Administrative Procedure Act.

¶ 90 The issue of the Commission's authority to require a LTGIP was discussed during oral argument. Allowances by other states were addressed, and one Commissioner pointed out that one of the states provided the authority by statute and was therefore unhelpful in determining whether the Commission had similar authority without statutory guidance.

¶ 91 AIC relies on Harrisonville Telephone Co. v. Illinois Commerce Comm'n, 176 Ill. App. 3d 389 (1988), to argue that the Commission's directive was beyond the scope of its jurisdiction. The AG argues that Harrisonville is distinguishable. In Harrisonville, the telephone company petitioned for an order authorizing it to operate and maintain telecommunications equipment along a prior roadway and to acquire the necessary easement rights. Id. at 391. It filed a report of compliance as to Commission Rules 300.20 and 300.30 and filed, in the alternative, a request for a variance as to those rules pursuant to Commission Rule 300.70 (83 Ill. Adm. Code 300.70 (1985)). Id. The Commission ultimately granted the telephone company its requested relief, including the variance, but also required the telephone company to comply with rules 300.20 and 300.30 “in all future projects *** unless a variance is obtained.” On review, this court found that the Commission's requirement related to future projects was beyond the scope of Commission authority after it granted the variance and was therefore an unauthorized declaratory ruling on the duties of the telephone company. Id. at 393.

¶ 92 Here, the Commission is requiring AIC to prepare a long-term infrastructure plan for future rate cases. While the AG argues that the requirement was because AIC's filing documents were insufficient, the mandate does not affect the current rate case because the Commission already issued its decision in the current case. The mandate is wholly inapplicable to the case at bar. Therefore, like Harrisonville, the Commission requirement in the case at bar is not applicable to the current case and it provides a requirement solely for future cases. While it is clear the Commission has authority to require certain information necessary to clarify costs involved in a ratemaking case, we question the Commission's use of an order to do so, especially considering that the legislature specifically required a long-term plan for electric companies in a statute.

¶ 93 The AG argues that CEJA did not address gas companies and, therefore, the legislature had no reason to provide any statute regarding gas companies. We find no merit in the AG's argument that CEJA did not address gas companies. CEJA issued several requirements for both electric and gas companies. For example, section 8-201.5(b) precluded both electric and gas utilities from shutting off utilities for service members while deployed for military service. 220 ILCS 5/8-201.5(b) (West 2022). Similarly, CEJA prohibited both electric and gas utilities from requiring deposits from low-income customers as a condition for standard services (see id. § 8-201.7(a)), precluded both utilities from charging late fees or penalties for late payment to low-income customers (see id. § 8-201.8(a)), and prohibited both utilities from charging credit card convenience fees (id. § 8-201.9(a)). Additionally, CEJA included mandates related to ethical conduct and transparency that applied to both electric and gas public utilities. See id. § 4-604. However, when it came to long-term plans, the legislature only created the requirement for electric companies when it authored CEJA. See id. § 16-105.17(f). Further, CEJA did not simply recommend a long-term plan for electric companies and direct the Commission to determine what information should be included. The legislature specifically included 12 topics setting forth the minimum information to be included in the electric company's infrastructure plans. Id. § 16-105.17(f)(2)(A)-(L).

¶ 94 The Illinois Commerce Commission is an agency “created by statute and has no general of common law powers.” Harrisonville, 176 Ill. App. 3d at 392. It “derives its power and authority solely from the statute creating it, and its orders which are beyond the purview of the statute are void.” Id. (citing Illinois Power Co. v. Illinois Commerce Comm'n, 111 Ill. 2d 505, 510-11 (1986)). While the Commission is assigned many functions, including investigative, prosecutorial, advocacy, and decision-making and rule-making roles (see Alhambra-Grantfork Telephone Co. v. Illinois Commerce Comm'n, 358 Ill. App. 3d 818, 823 (2005) (citing Business & Professional People for the Public Interest v. Illinois Commerce Comm'n, 136 Ill. 2d 192, 201-03 (1989))), its authority is limited to that granted by statute. 220 ILCS 5/1-102, 4-101 (West 2022).

¶ 95 Even though the legislature did not include gas companies in the CEJA multi-year integrated plan requirements, the AG argues that the exclusion was not intentional and should not be read in such a manner. “The primary rule of statutory construction is to give effect to legislative intent by first looking at the plain meaning of the language.” Davis v. Toshiba Machine Co., America, 186 Ill. 2d 181, 184 (1999). Courts may assume that the legislature “did not intend absurdity, inconvenience or injustice” to result from legislation. Burger v. Lutheran General Hospital, 198 Ill. 2d 21, 40 (2001). “[W]here the language of a statute is clear and unambiguous, a court must give it effect as written, without reading into it exceptions, limitations, or conditions that the legislature did not express.” Land v. Board of Education of City of Chicago, 202 Ill. 2d 414, 426 (2002). “One of the fundamental principles of statutory construction is to view all provisions of an enactment as a whole.” People v. O'Brien, 197 Ill. 2d 88, 91 (2001) (citing Michigan Avenue National Bank v. County of Cook, 191 Ill. 2d 493, 504 (2000)). Here, our review of CEJA reveals no obligation for gas utilities to prepare a long-term infrastructure plan.

¶ 96 The AG also contends the Commission correctly found the agency had sufficient authority—aside from the CEJA—to require gas utilities to prepare long-term infrastructure plans. However, had the legislature believed the Commission had the authority to order long-term infrastructure or grid plans for utilities, it would have been unnecessary for the legislature to include the electric utility infrastructure plan, and the numerous requirements for such plan, in the CEJA.

¶ 97 It is equally relevant that the Commission rules already set forth the required information each gas utility must provide in support of its capital recovery requests. See 83 Ill. Adm. Code 285.6100. The Commission mandate is closely associated with current regulations, and therefore, assuming this issue was one within Commission authority, the Commission could just amend its rules to require the additional information.

¶ 98 “Not every action taken by an administrative agency constitutes a rule.” Northwestern Illinois Area Agency on Aging v. Basta, 2022 IL App (2d) 210234, ¶ 56. “The Act defines a ‘rule’ as an ‘agency statement of general applicability that implements, applies, interprets, or prescribes law or policy.’ ” Id. (quoting 5 ILCS 100/1-70 (West 2020)). “A rule or regulation of an administrative agency or department may impose a duty to comply upon the person to whom it is directed which is equivalent to a duty imposed by law.” Fox v. Inter-State Assurance Co., 84 Ill. App. 3d 512, 515 (1980). In Illinois, agency requirements that prescribe law or policy affecting the private rights or procedures of people or entities outside that agency is a rule. 5 ILCS 100/1-70 (West 2022). Here, the Commission's requirement that large gas utilities provide long-term infrastructure plans clearly affected entities outside of the Illinois Commerce Commission.

¶ 99 “Ratemaking” or “ratemaking activities” is defined under the Illinois Administrative Procedure Act (IAPA) as “the establishment or review of or other exercise of control over the rates or charges for the products or services of any person, firm, or corporation operating or transacting any business in this State.” 5 ILCS 100/1-65 (West 2022). The IAPA further states that, “Every agency that is empowered by law to engage in ratemaking activities shall establish by rule, not inconsistent with the provisions of law establishing its ratemaking jurisdiction, the practice and procedures to be followed in ratemaking activities before the agency.” Id. § 5-25.

¶ 100 Here, it is not possible for the Commission's mandate to escape the rule-making rubric established by the IAPA. Indeed, the Illinois Administrative Code is replete with schedules addressing revenue and financial summary schedules (83 Ill. Adm. Code 285.100 to 285.1025), rate base schedules (83 Ill. Adm. Code 285.2000 to 285.2200), operating income schedules (83 Ill. Adm. Code 285.3000 to 285.3700), rate of return schedules (83 Ill. Adm. Code 285.4000 to 285.4090), rate and tariff schedules (83 Ill. Adm. Code 285.5010 to 285.5315), as well as planning and operating schedules for gas and/or electric utilities (83 Ill. Adm. Code 285.6000 to 285.6320). Included in these schedules are the requirements for Schedule F-4 regarding additions to plant in service since the last rate case. See 83 Ill. Adm. Code 285.6100.

¶ 101 None of the requirements for the Commission's new long-term infrastructure plans are found in the regulations. Further, based on the Commission's order, the new long-term infrastructure plans are newly required filings related to ratemaking cases addressing additions to plant in service, for all large gas public utilities. Assuming the Commission has authority to issue the mandate, we do not see how such requirement would be anything other than a rule. The Commission is not authorized to bypass the rule-making process when the IAPA specifically requires agencies “empowered by law to engage in ratemaking activities” to “establish by rule *** the practice and procedures to be followed in ratemaking activities before the agency.” 5 ILCS 100/5-25 (West 2022).

¶ 102 Here, the long-term gas infrastructure plan requirement is clearly a practice and procedure to be followed in all future ratemaking cases as the Commission's order specifically stated as such. Further, the requirement was not limited to AIC. See North Shore Gas Co./The Peoples Gas Light & Coke Co., Ill. Comm. Comm'n Nos. 23-0068, 23-0069 (cons.) (Nov. 16, 2023) (“To remedy the difficulty of obtaining information in this case and to aid in the Commission's informed review of the Companies’ future rate increase requests, *** PGL and NS shall file a long-term infrastructure plan (‘Long-Term Gas Infrastructure Plan’) with the Commission every two years beginning July 1, 2025 ***.”); see also Northern Illinois Gas Co. d/b/a Nicor Gas Co., Ill. Comm. Comm'n No. 23-0066 (Nov. 16, 2023) (“As such, to aid in the Commission's informed review of this and the Company's future rate increases *** Nicor Gas shall file a long-term infrastructure plan (‘Long-Term Gas Infrastructure Plan’) with the Commission every two years beginning July 1, 2025 ***.”). The “Long-Term Gas Infrastructure Plan” requirements for all four companies were identical and were tied to future rate increase filings requiring, at a minimum, a rule under the IAPA. See 5 ILCS 100/5-25 (West 2022).

¶ 103 The Illinois Administrative Procedure Act sets forth public notice and comment requirements which administrative agencies must follow in enacting rules. See 5 ILCS 100/5-40 (West 2022). “Unless a rule is promulgated in conformity with the public notice and comment requirements of the Act and is filed with the Secretary, it is not valid or effective against any person or party and may not be invoked by an administrative agency for any purpose.” R.L. Polk & Co. v. Ryan, 296 Ill. App. 3d 132, 142 (1998). Given the Commission's lack of compliance with the IAPA, we vacate the Commission's requirement to prepare a long-term gas infrastructure plan as void for being outside the Commission's authority. We provide no opinion on whether such requirement must be provided through legislation as stated by the governor or by rule under the IAPA.

¶ 104 D. Return on Equity

¶ 105 On appeal, AIC contends that the Commission erroneously approved AIC's return on equity at 9.44% The return on equity is closely tied to the utility's rates. Our deference to the Commission is especially appropriate in the area of fixing rates. Iowa-Illinois Gas & Electric Co. v. Illinois Commerce Comm'n, 19 Ill. 2d 436, 442 (1960). “Simply put, we are judges, not utility regulators.” People ex rel. Madigan v. Illinois Commerce Comm'n, 2015 IL 116005, ¶ 22. The General Assembly entrusted the function of determining rates to the Commission. Id. ¶ 23. “ ‘[T]he determination of rates is not a matter of formulas but one of sound business judgment.’ ” Id. (quoting Cerro Copper Products v. Illinois Commerce Comm'n, 83 Ill. 2d 364, 371 (1980)). This is because the Act requires the rates for utility services to be “just and reasonable.” 220 ILCS 5/9-201(c) (West 2022). To determine whether the rates are just and reasonable, the utility's revenue requirement must be determined using the sum of the company's operating costs and the rate of return on its invested capital. People ex rel. Madigan v. Illinois Commerce Comm'n, 2011 IL App (1st) 100654, ¶ 26.

¶ 106 The United States Supreme Court stated that,

“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.

“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.” Id. at 693.

¶ 107 The United States Supreme Court language is reiterated in the Act's findings and intent. See 220 ILCS 5/1-102 (West 2022). To meet the state's goal of efficiency, the Act provides that

“the provision of reliable energy services at the least possible cost to the citizens of the State; in such manner that: *** utilities are allowed a sufficient return on investment so as to enable them to attract capital in financial markets at competitive rates;” and setting tariff rates so “that they accurately reflect the cost of delivering those services and allow utilities to recover the total costs prudently and reasonably incurred.” Id. § 1-102(a)(iii), (iv).

On appeal, AIC contends that the Commission erroneously approved AIC's return on equity at 9.44% and adopted a long-term debt rate of 4.232%, thereby undermining the state's efficiency goal.

¶ 108 “A utility's return should be reasonably sufficient to permit confidence in the utility's financial soundness and, with economical and efficient management, to support the utility's credit and raise funds necessary to properly discharge the utility's public duties.” Citizens Utility Board v. Illinois Commerce Comm'n, 2018 IL App (1st) 170527, ¶ 45. Further, “ ‘the return to the equity owner should be commensurate with returns on investments in other enterprises having corresponding risks.’ ” Id. (quoting Federal Power Comm'n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944)). “That return, moreover, should be sufficient to assure confidence in the financial integrity of the enterprise, so as to maintain its credit and to attract capital.” Hope, 320 U.S. at 603. Return on equity is part of the equation used to determine the revenue requirement.¹⁵ Madigan, 2015 IL 116005, ¶ 29.

¶ 109 The parties involved in this case provided evidence regarding the appropriate return on equity. AIC initially requested an ROE of 10.7% but later reduced it to 10.3%. The Commission Staff recommended an ROE of 9.89% and IFCUP,¹⁶ recommended an ROE of 9.50%. The three recommendations were based on expert testimony that boosted its own ROE and set forth criticisms of the other ROEs. Ultimately, the Commission set the ROE at 9.44%.

¶ 110 AIC argues that the Commission's proposed ROE was “improper and unlawful,” stating the Commission disregarded all the evidence from AIC's expert and used an “unprecedented and facially improper methodology” by setting the ROE far below the return that an investor would expect on investments of comparable risk, as constitutionally required.

¶ 111 Numerous models were presented on this issue. The Commission order addressed each model, the factors included in each model, the adjustments, other parties’ criticisms of the models, as well as the rebuttal testimony related thereto. It then addressed factors that must be considered to determine reliability of the models, the competing interests and opinions. It found that reliance on non-utility proxy groups, size adjustments, higher credit risks, reliance on forecasted U.S. Treasury bond yield instead of current, observable market interest rates, use of the bond yield plus risk premium model, the use of adjusted betas in the ECAPM model and flotation adjustments were unwarranted.

¶ 112 The Commission order also noted its preference for CAPM and ECAPM analysis based on both weekly and monthly beta estimates, and CAPM analyses that used betas over a period of five years, DCF analyses using current or spot market prices (as opposed to a 60-day average of stock prices). For these reasons, the Commission rejected AIC's proposed DCF, CAPM, ECAPM analyses as well as its bond yield plus risk premium model. Notably, despite expressing criticism over the Commission's disregard of its expert testimony, at no time does AIC claim that the Commission's rejection of its expert testimony was erroneous.

¶ 113 Instead, AIC argues that the Commission's reliance on portions of the two remaining expert models was erroneous because it “selected an ROE at a level it desired and then attempted to support it post hoc by, in a marked departure from past practice, cherry-picking inputs to achieve the desired results.” We disagree. Our review of the Commission order on this issue, which encompassed over 50 single-spaced pages, does not reveal any predetermination of what the Commission believed the ROE should be. Instead, the decision focused on each expert's testimony, the criticisms bestowed thereon, and the expert's rebuttal to that criticism. After clearly indicating that all of AIC's models were deficient—some for reasons expressed numerous times in the past—it had only the models of the Staff and IFCUP to determine an ROE. However, the Commission was equally dismissive of most of IFCUP's analysis, some of which suffered from the same failures as AIC's expert testimony.

¶ 114 Therefore, AIC takes issue with the Commission's reliance on any data from the IFCUP CAPM model after rejecting the IFCUP analyses for some of the same reasons it rejected the AIC analyses. However, AIC's argument has little merit. Here, the Commission was concerned that the Staff's 12.65% forward-looking market return (Rm) estimate was “significantly higher than the 10.79% Rm estimate determined using the Federal Energy Regulatory Commission (FERC) method which, similar to Staff's method, estimate[d] the forward-looking market return through a constant growth DCF model applied to the dividend-paying companies of the S&P 500.” It further noted that the Staff's 12.65% Rm was higher than “long-term expected market returns published by U.S. financial institutions.” Again, AIC provides no argument as to why the Staff's 12.65% Rm value was more reliable than one based on the FERC method or why long-term expected market returns published by U.S. financial institutions should not be considered in determining a utility's proper ROE.

¶ 115 What the Commission concluded was that there were several diverse models that failed to ascribe to Commission preference when determining ROE. The most palatable models were presented by Staff and those were its DCF (constant growth) and CAPM models. Notably, the Commission was concerned with the inexplicably low DCF (non-constant growth model) values obtained by Staff and IFCUP and refused to consider them due to the lack of explanation associated with the divergence as they were “well below any ROE the Commission has ever approved for a natural gas utility.” Staff originally averaged its DCF (9.40%) and NCDCF (8.23) values to reach its DCF average value of 8.81%. However, in reaching the ROE here, the Commission eliminated the Staff's average (8.81%) and simply used the DCF constant growth value (9.40%) after discounting the unexplained divergence associated with the NCDCF.

¶ 116 More specifically, the Staff CAPM value contained a value based on a larger group of proxy companies eliminating companies with a 30% growth rate. IFCUP noted that this deviated from FERC which eliminated companies with growth rates greater than 20%. AIC provides no argument as to why the Commission's reliance on the FERC value was erroneous except to argue that was not used by Staff, but was used by IFCUP, in preparing their models. At no time does AIC argue that the Staff value should have been used because Staff's growth rate was more consistent with their proxy group than a proxy group based on FERC requirements.

¶ 117 Contrary to AIC's arguments, the Commission sufficiently explained why it substituted the FERC value in the Staff's calculation. As the Commission's finding was supported by the evidence and was not contrary to law, we affirm the Commission's substitution of FERC values in the Staff's calculation and the ROE derived therefrom.

¶ 118 E. Long-Term Debt Rate

¶ 119 AIC also argues that the Commission's setting of its long-term debt rate at 4.232% is not supported by substantial evidence and the Commission failed to adequately support its grounds for the amount provided beyond relying on Staff's recommendation. In support, AIC argues that Staff requested an increase in the long-term debt rate from 4.232% to 4.238% after confirming AIC's issuance of $500 million of long-term debt at an interest rate of 4.95%, which was why the long-term debt rate was originally set at 4.232%.

¶ 120 AIC argues that the Commission “improperly blames [AIC] for the Commission's decision to disregard the debt actually issued in 2023.” We disagree. Notably, AIC's entire argument is based on Staff statements regarding the debt issuance. When asked at oral argument if AIC presented evidence of the debt issuance, AIC conceded that it did not. Accordingly, we can find no error with the Commission's finding that AIC “failed to provide supporting documentation of the debt being issued at 4.95%.” As the record is devoid of any actual evidence submitted by AIC to the Commission on this issue, we affirm the Commission's setting of AIC's long-term debt rate at 4.232%.

¶ 121 F. Low-Income Customer Rider

¶ 122 Finally, AIC argues that the Commission's adoption of the AG's Low-Income Customer Rider (Rider LICA) should be reversed “because it creates unreasonable, unjust, and discriminatory charges in violation of Illinois law and arbitrarily rejects the Commission's prior recommendations on low-income discount rates.” The AG disagrees and argues that Rider LICA was just and reasonable.

¶ 123 When CEJA was issued, the legislature provided a mandate to the Commission that required it to “conduct a comprehensive study to assess whether low-income discount rates for electric and natural gas residential customers” was “appropriate and the potential design and implementation of any such rates” by January 1, 2023. 220 ILCS 5/9-241(d) (West 2021). The mandate provided seven issues to be addressed. Id. These issues included eligibility, rate structures, recovery mechanisms, applicant verification, customer data safeguards, outreach, and “the impact that a low-income discount rate would have on the affordability of delivery service to low-income customers and customers overall.” Id. Once the study was completed and presented to the General Assembly, the Commission was granted “authority to permit or require electric and natural gas utilities to file a tariff establishing low-income discount rates.” Id.

¶ 124 The Commission submitted its report on December 15, 2022. The Commission's study included five tentative recommendations:

“(1) Electric Utilities with more than 3,000,000 residential delivery services customers in Illinois, Combination Electric and Gas Utilities with more than 500,000 residential delivery service customers in Illinois, and Gas utilities with more than 100,000 residential delivery services customers in Illinois should offer a tariffed low-income discount rate. Further, all other electric and natural gas utilities in Illinois should be encouraged (but not required) to propose a tariffed low-income discount rate. (2) All such utility low-income discount rate proposals should include tiered discounts for different income levels, which are applicable only to the delivery services charges. (3) All such utility low-income discount rate proposals should include a cost recovery mechanism that is consistent with Illinois law and Commission practice. (4) All such utility low-income discount rate proposals should support the clean energy goals and policies of Illinois and should not include rate designs that undermine or are counterproductive to achieving the State's clean energy goals and policies. (5) All Utilities should leverage existing programs and processes to streamline administrative processes and minimize costs relating to eligibility requirements, verification mechanisms, and outreach/customer education procedures while maintaining the confidentiality of sensitive customer data.”

¶ 125 AIC's proposed Rider LICA contained two tiers, encompassed customers whose incomes fell between 0% and 200% of the federal poverty level (FPL), and provided predetermined credits of $10 or $20 each month. AIC's proposal was rejected by the Commission. Instead, the Commission approved the AG's proposed Rider LICA that contained five tiers, encompassed proposed recipients whose income fell between 0% and 300% of the federal poverty level, and provided percentage discounts between 5% and 75% of the total bill. Recovery of the discounted amounts would be obtained from AIC's non-participating residential and non-residential customers. On appeal, AIC argues that the AG's proposed Rider LICA resulted in unreasonable and unjust charges for non-participating customers and discriminatory credits for participating customers.

¶ 126 AIC argues that the AG's Rider LICA was unjust and unreasonable because it included more participants and therefore would increase the subsidies from non-participating customers. Further, the discount was not just applied to the delivery portion of the bill; the discount was applied to the total bill. AIC's estimates revealed that its proposed Rider LICA would cost between $9,345,240 and $26,677,680; its residential customers would see an increase in their bills between $0.54 and $1.55 monthly. AIC's non-residential customers using less than 4,000,000 therms/per year would see an increase in their bills between $5.40 and $15.50. AIC non-residential customer using more than 4,000,000 therms/year would see a monthly increase between $202.50 and $581.25 monthly in their bills. AIC further estimated that the AG's Rider LICA program based on total bill percentages had costs that ranged from $21,504,853 and $62,196,371. This plan would increase residential bills between $1.25 and $3.61 monthly. Non-residential customers using less than 4,000,000 therms a year would see an increase in their bills between $12.50 and $36.10 monthly and those using more than 4,000,000 therms a year would see an increase in their bills between $468.75 and $1,353.75 each month. AIC argues that using a percentage discount for both the delivery and supply portions of the bills requires non-participating customers to subsidize more of the participating customer's credits and because the AG Rider LICA plan is based on a percentage, it has no limit on how much the non-participating customers will have to subsidize and rewards customers in similar tiers with higher credits for using more of the utility's services. In response, the AG argued that the Commission's acceptance of its proposed Rider LICA was reasonable and should be affirmed.

¶ 127 The Rider LICA approved the AG's proposed “full bill discount.” The Commission acknowledged that “applying the discount to the entire bill will increase the amount to be paid by non-eligible customers” but also noted that the “program introduce[d] potential utility system benefits and encourage[d] [AIC] to prioritize energy efficiency programming to reduce bills overall.” Although only mentioned by the Commission during oral argument, we also note the Commission's concern with the non-participating parties paying the taxes associated with lower-income recipients of the credits.

¶ 128 In Shortino v. Illinois Bell Telephone Co., 207 Ill. App. 3d 52, 60 (1990), the appellate court found that Illinois Bell's shifting of its payphone tax liability to all its monthly billed customers was discriminatory and violated section 9-241 of the Act. Id. (“Plainly, the shifting of pay phone users’ tax burden onto monthly billed customers discriminates against billed customers in violation of section 9-241 of the PUA.”). The court clarified that while Illinois Bell had the right to pass its tax liability onto its customers, it was not authorized to shift the burden of the tax liability of one group of customers to another group of customers. Id. at 62. Given that the Commission's adopted Rider LICA is based on the “full bill discount,” we do not see how the Rider LICA escapes a finding of discrimination when it shifts the burden of the tax liability of one group of customers to another group of customers.

¶ 129 Equally concerning is AIC's argument related to the differences between the Rider LICA chosen and the recommendations of the Commission in its legislative-directed study. Of the four models recommended, the Commission-adopted Rider LICA is the model most inconsistent with the Commission's study recommendations. Namely, the Commission's study recommended the proposals apply only to delivery charges, should not undermine the state's clean energy goals and policies, and should leverage existing programs to streamline administrative processes and minimize costs. AIC correctly notes that the approved Rider LICA did not limit the proposal to delivery charges, it applies discounts to the total bill. Further, the approved Rider LICA did not disincentivize higher-use customers to use less gas because a percentage of the entire bill would be eliminated as opposed to the customer receiving a flat rate discount. Finally, AIC correctly notes that the additional tiers moved beyond the “leverage existing programs” recommendation because it created a tier that moved beyond the previously established LIHEAP and PIPP verification processes.

¶ 130 In response the AG argues that the Commission's tentative conclusions in the study were “irrelevant.” It further argues that AIC failed to cite any authority establishing precedential value of the study and therefore forfeited any related argument. It further argues, citing Commonwealth Edison Co. v. Illinois Commerce Comm'n, 2016 IL 118129, ¶ 24, that the Illinois Supreme Court has long recognized that the Commission has the “power to deal freely with each situation” regardless of how it may have previously dealt with a similar situation.

¶ 131 We do not dispute the Commission's “power to deal freely with each situation.” However, the Commission's authority is limited to that prescribed by law. Here, the legislature mandated the Commission to prepare a study addressing numerous topics and to provide its findings and recommendations to the General Assembly. 220 ILCS 5/9-241 (West 2021). Upon completion of the study, the Commission was granted “authority to permit or require electric and natural gas utilities to file a tariff establishing low-income discount rates.” We dispute the AG's contention that the study recommendations were “irrelevant” as they were required as a condition precedent to allow the Commission to permit or require utilities to file tariffs regarding low-income discount rates. Further, while the Commission's recommendations were classified as “tentative,” we find it concerning that the Commission was so easily persuaded to abandon three-fifths of its earlier recommendations to the General Assembly.

¶ 132 We also find it problematic that the Commission's basis for disallowing AIC's requested capital budget for its distribution and transmission lines—even though the budget was to improve safety and efficiency of gas service and delivery—was due to the increased cost that would be passed on to AIC's customers. However, concern of any increased cost to AIC's customers seemed to disappear when it was limited to addressing the increased costs to AIC's non-qualifying customers who will be footing the bill under the Rider LICA program.

¶ 133 Equally problematic is the lack of statutory authority provided to this court that would allow the Commission to direct a utility to mandate that a portion of that utility's customers were now required to pay the utility bills, or at least a portion of the utility bills, of that utility's other customers. This concern is further compounded by the Commission order requiring the utility to allow an allegedly qualifying customer to “self-verify” for the program and then disallowing the utility from removing that same customer when the self-verification was false, essentially requiring AIC's non-qualifying customers to also pay the utility bill for what should be another non-qualifying customer simply based on fraud, misuse, or abuse of the system. In such situation, discrimination against the non-qualifying customers footing the bill is obvious. See 220 ILCS 5/9-241 (West 2022). Therefore, pursuant to section 9-241 of the Act and Shortino, we vacate the Commission's adoption of the Rider LICA and remand this issue back to the Commission for further hearings that more adequately address the Commission's authority to issue a mandate requiring payment of a low-income rider by a utility's allegedly more affluent customers, and to consider the matter consistent with the Commission's own recommended guidelines, and to further consider its conclusion that requires the utility to keep the system in place despite evidence of fraud or abuse.

¶ 134 III. CONCLUSION

¶ 135 For the reasons stated herein, we hereby affirm the Commission's order denying AIC's gas distribution plant additions and its calculations setting AIC's return on equity and long-term debt rate. We reverse the Commission's denial of AIC's transmission plant additions as the decision was not supported by substantial evidence. We vacate the Commission mandate requiring gas utilities to prepare a long-term gas infrastructure plan requirement as part of its ratemaking procedure and the Commission's adoption of the AG's Rider LICA as being contrary to law and remand this case back to the Commission to issue a decision consistent with this opinion and for further hearings on the Rider LICA issue.

¶ 136 Affirmed in part, reversed in part, and remanded with directions.

FOOTNOTES

1.   Gas distribution lines are generally smaller and lead to residential and business customers; gas transmission lines are larger and run from the source of the natural gas.

2.   IFCUP is the acronym used to represent the following entities: Illinois Industrial Energy Consumers (IIEC), the Federal Executive Agencies (FEA), the Citizens Utility Board (CUB), United Congregations of Metro-East (UCM), and Prairie Rivers Network (PRN).

3.   PIO is the acronym used to represent the following entities: the Environmental Law and Policy Center (ELPC), Environmental Defense Rund (EDF), Natural Resources Defense Council (NRDC), and Illinois State Public Interest Research Group (ILPIRG).

4.   Schedule F-4 requires utilities to provide certain information related to plant additions since its last rate case. See 83 Ill. Adm. Code 285.6100. The top 10 costliest additions require information that includes: a description, when the project started, completion date, completion cost, the reason for the project, alternatives considered and reasons for rejected each alternative, and a list of reports relied upon by management when it decided to pursue the rate base addition. 83 Ill. Adm. Code 285.6100(b). AIC's revised Schedule F-4 was found to be reasonable and was approved by the ALJ and the Commission.

6.   Section 8-101 addresses “Duties of public utilities,” not duties of the Commission.

7.   Due to this difference, IFCUP contended that using the FERC values in Staff's CAPM model produced a more reasonable result of 9.96%, as opposed to 10.96%. Using the FERC value, the Staff CAPM would be 9.96%, its DCF would be 8.81%, and the average would be 9.39% as opposed to 9.885%.

8.   The threshold was based on the number of resident delivery service customers in Illinois. For electric utilities, the threshold was 3,000,000. Combined electric and gas utilities had a threshold of 500,000 and gas utilities had a threshold of 100,000. All other companies were encouraged, but not required, to propose a tariffed low-income discount rate.

9.   LIHEAP is the acronym for Low Income Home Energy Assistance Program, which assists “eligible low-income households pay for home energy services (primarily hearing during winter months).” See Illinois Department of Commerce and Economic Opportunity website https://dceo.illinois.gov/communityservices/utilitybillassistance.html (accessed Nov. 25, 2024).

10.   PIPP is the acronym for Percentage of Income Payment Plan, which is a benefit choice within LIHEAP in which the State pays a portion of the utility bill, and the customer would pay the rest. See PIPP Brochure available at Illinois Department of Commerce and Economic Opportunity website https://dceo.illinois.gov/content/dam/soi/en/web/dceo/communityservices/utilitybillassistance/documents/pipp-brochure-2019.pdf (accessed Nov. 25, 2024).

11.   A therm is the basic unit for measuring natural gas consumption. It is a measure of the energy content of natural gas and is equivalent to 100,000 British Thermal Units (BTUs). See https://www.ameren.com/illinois/account/customer-service/bill/understanding-your-bill/terms-and-definitions (accessed Nov. 25, 2024).

12.   LIDR is the acronym for Low Income Discount Rate.

13.   LPP includes bare and/or unprotected steel pipe, cast iron pipe, ductile iron pipe, or copper pipe. During these proceedings AIC advised that it had no cast iron, unprotected steel, or copper main and only 6 miles of its 17,456 miles of main contained any LPP.

14.   MAOP is the acronym for “Maximum Allowable Operating Pressure” and was the subject of PHMSA regulations. “MAOP means the maximum pressure at which a pipeline or segment of a pipeline may be operated.” 84 Fed. Reg. 52180-01, 52181 n.6 (Oct. 1, 2019). Pursuant to the 2011 Pipeline Safety, Regulatory Certainty, and Job Creation Act, (enacted Jan. 3, 2012) operators are required to report exceedances of the MAOP. See 49 U.S.C. § 60139(b)(2) (2018).

15.   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.) Madigan, 2015 IL 116005, ¶7.

16.   “IFCUP” was the designation applied to five entities that included Illinois Industrial Energy Consumers (IIEC), the Federal Executive Agencies (FEA), the Citizens Utility Board (CUB), United Congregations of Metro-East (UCM), and Prairie Rivers Network (PRN).

JUSTICE VAUGHAN delivered the judgment of the court, with opinion.

Presiding Justice McHaney and Justice Sholar concurred in the judgment and opinion.