Articles Posted in Utility Law

On October 21, 2022, the Indiana Court of Appeals held that objections to condemnation proceedings must state specific facts that support the assertions raised by the objections, noting that the special statutory character of eminent domain proceedings and inaction by the Indiana General Assembly necessitate greater factual specificity than what is required of pleadings under Indiana Trial Rule 8. The case involved a condemnation action brought by Duke Energy, LLC (“Duke”) in which it sought to take a perpetual and non-exclusive easement running across certain real estate owned by Bender Enterprises, LLC (“Bender”). The complaint alleged that the easement was necessary for Duke to connect its 11^th Street substation to its Rogers Street Substation in Bloomington and that efforts to purchase the easement interest from Bender had been unsuccessful. Bender filed objections to the complaint, arguing that the easement interest was unnecessary and that the designated location of the easement was “capricious, arbitrary, and not based upon accepted engineering and industry standards.” Bender Enterprises, LLC v. Duke Energy, LLC, 22A-PL-1230 at 3 (Ind. Ct. App. 2022). The trial court overruled Bender’s objections, finding that they failed to include additional facts to support the assertions raised. Bender appealed the trial court’s ruling.

The single issue before the Court of Appeals was whether the trial court erred in overruling Bender’s objections on the grounds that they did not allege specific support facts. The court began by noting while I.C. 34-24-1-8 does not explicitly require objections in condemnation proceedings to state specific supporting facts, Indiana precedent has long established that such facts must be included, observed by the Indiana Supreme Court’s 1947 holding in Joint Cnty. Park Bd. of Ripley, Dearborn and Decatur Cnty.s v. Stegemoller that “[i]f facts exist in addition to those disclosed by the [condemnation] complaint which would defeat plaintiff’s recovery, they should be affirmatively pleaded.” Stegemoller, 88 N.E.2d 686, 688 (Ind. 1949). According to the court, Bender’s objections failed to state “why or how the condemnation was unnecessary, arbitrary, and capricious,” and similarly failed explain why the condemnation was not based on “accepted engineering and industry standards” or what those specific standards were. Bender Enterprises, 22A-PL-1230 at 6 (Ind. Ct. App. 2022).

Bender next argued that, because Stegemoller was decided prior to Indiana’s change to notice pleading in 1971, its objections should have been evaluated on the same basis as pleadings in civil actions under Indiana Trial Rule 8. The court disagreed with this assertion for two reasons. First, the court noted that, unlike standard civil pleadings, the statutes governing eminent domain proceedings specify that they are two be conducted in two stages, with the first stage “being a summary proceeding in which the trial court may rule on the legality of the proposed condemnation based solely on the complaint and objections thereto.” Bender Enterprises, 22A-PL-1230 at 8 (Ind. Ct. App. 2022). As such, the court determined that the condemnation complaint and the objections “clearly…must articulate all the facts necessary for the factfinder to rule on the legality of the action before proceeding to the second stage” of the proceedings. Id. at 9. Finally, the Court found that the Indiana General Assembly’s silence following the Indiana Supreme Court’s decision in Stegemoller to be indicative of “the General Assembly’s acquiescence and agreement with the judicial interpretation” that objections to a condemnation complaint must allege specific supporting facts. Id. at 8. Therefore, the court affirmed the overruling of Bender’s objections, reaffirming the longstanding precedent that objections to a condemnation complaint must state specific supporting factual allegations.

On January 4, 2023, the Indiana Supreme Court affirmed the Indiana Utility Regulatory Commission’s (“IURC”) approval of Southern Indiana Gas & Electric Company’s (“Vectren”) new instantaneous netting method (“Rider EDG”) of determining the amount of credit Vectren customers receive for their excess distributed generation of electricity, overruling the Indiana Court of Appeals. The central issue before the Court was whether the IURC’s approval of Vectren’s Rider EDG satisfied the requirements of I.C. 8-1-40-5, which defines excess distributed generation as “the difference between: (1) the electricity that is supplied by an electricity supplier to a customer that produces distributed generation; and (2) the electricity that is supplied back the electricity supplier by the customer.”  I.C. 8-1-40-5. Once that difference is calculated, utility companies are required to compensate distributed generation customers (“DG customers”) 125% of the wholesale price of the customer’s excess distributed generation. Ind. Office of Utility Consumer Counselor v. Southern Indiana Gas & Electric Co., 22S-EX-00166 at 8 (Ind. 2023) (citing I.C. 8-1-40-17).

Under the Rider EDG, the difference between electricity supplied by DG customers to Vectren and the electricity supplied by Vectren to DG customers is measured almost instantaneously. In reversing the IURC’s approval of the Rider EDG, the Indiana Court of Appeals determined that the Rider EDG “focuses and assigns credit based only on the outflow of electricity from the customer to the utility rather than the specific difference between inflow and outflow proscribed by the statute,” and reasoned that “a longer period to find the difference between inflow and outflow was more beneficial to the DG customers.” Southern Indiana Gas & Electric Co., 22S-EX-00166 at 5 (internal citation omitted). The Indiana Supreme Court disagreed, noting that I.C. 8-1-40-5 neither “direct[s] utilities on how often excess distributed generation must be measured” or “mandate[s] a specific time when the difference between inflow and outflow must be measured.” Id. at 8. Rather, the court found that Vectren’s meters “are perpetually and instantaneously finding the difference between the inflow of power to the customer and outflow of power to the utility company,” which the court found to satisfy the two components of I.C. 8-1-40-5. Id. Therefore, the court held that the IURC’s approval of Vectren’s Rider EDG was proper and not contrary to the requirements of I.C. 8-1-40-5.

Jeremy Fetty is a partner in the law firm of Parr Richey Frandsen Patterson Kruse with offices in Lebanon and Indianapolis. He often advises businesses and utilities (for profit, non-profit and cooperative) on organizational, human resources, and transactional matters and drafts and reviews commercial contracts.

On December 28, 2021, the Indiana Utility Regulatory Commission (“Commission”) approved a Transmission, Distribution and Storage System Improvement Charge (“TDSIC”) plan submitted by Northern Indiana Public Service Company (“NIPSCO”). Part of NIPSCO’s TDSIC plan included certain system deliverability projects, specifically NIPCO’s need to upgrade its Marktown substation and improve the distribution and transmission related system deliverability in the Nappanee area. The NIPSCO Industrial Group and the Office of the Utility Consumer Counselor (collectively “Appellants”) appealed the Commission’s approval of the TDSIC plan, arguing that the Commission misinterpreted the statute governing TDSIC plans – I.C. 8-1-39 – because it did not conduct a cost-benefit analysis for each individual project in the TDSIC plan.

The Indiana Court of Appeals disagreed with Appellants’ interpretation that I.C. 8-1-39 required the Commission to conduct a cost-benefit analysis on an individual project basis. In its September 29, 2022, opinion, the Court focused on the statutory language of I.C. 8-1-39-10, finding that subsection 10(1) required the Commission to include a best estimate of cost “of the eligible improvements included in the plan” rather than a best estimate of cost for each individual improvement. Second, the Court noted that subsection 10(3), requiring the Commission to determine “whether the estimated costs of the eligible improvements included in the plan are justified by incremental benefits attributable to the plan,” is satisfied when the eligible improvements collectively are justified by the proffered benefits as applied to TDSIC plan in its entirety as opposed to individually, noting that “[h]ad the General Assembly wished to require more detailed findings, it could have easily required them but did not do so.” In a similar vein, the Court concluded that Appellants’ policy arguments regarding the purposes of subsection 10(3) were “best addressed to the General Assembly, not this court.”

Jeremy Fetty is a partner in the law firm of Parr Richey Frandsen Patterson Kruse with offices in Lebanon and Indianapolis. He often advises businesses and utilities (for profit, non-profit and cooperative) on organizational, human resources, and transactional matters and drafts and reviews commercial contracts.

On March 10, 2022, the Indiana Supreme Court concluded that a utility cannot be reimbursed for a deferred asset, even if it is properly accounted for, without violating Ind. Code § 8-1-2-68 bar against retroactive ratemaking. The case involved the utility regulation commission’s approval of Duke Energy Indiana’s (“Duke”) 2019 request to increase its rates for retail consumers in order to recover about $212 million for coal-ash site closures, coal-ash site remediation, and other financing costs associated with the 2015 Environmental Protection Agency’s new rules for treating coal ash and remediating ash ponds. Duke accounted for these compliance efforts using asset retirement obligation accounting, which represents a legal obligation associated with the retirement of a tangible long-lived asset that must be settled under a newly enacted statute.

The issue before the Court was whether the utility regulation commission had the authority to approve the reimbursement sought by Duke without violating the statutory ban on retroactive ratemaking. Finding that the commission had established Duke’s rate and adjudicated depreciation rates for the cost of decommissioning its plant assets, including coal-ash costs, in its 2004 rate order, the Court concluded that the utility regulation commission exceeded its statutory authority by granting Duke’s request to re-adjudicate its coal-ash costs that were already governed by the commission’s 2004 rate order.

Jeremy Fetty is a partner in the law firm of Parr Richey Frandsen Patterson Kruse with offices in Lebanon and Indianapolis. He often advises businesses and utilities (for profit, non-profit and cooperative) on organizational, human resources, and transactional matters and drafts and reviews commercial contracts.

Indiana Code §8-1-8.5-3.1(b) in 2019 ordered the Indiana Utility Regulatory Utility Commission (IURC) to conduct a study of statewide impacts of:

• Transitions in the fuel sources and other resources used to generate electricity by electric utilities; and
• New and emerging technologies on local grids or distribution infrastructure; on electric generation capacity, system reliability, system resilience, and cost of electric service for consumers. The IURC shall consider timelines for transitions in fuel sources and other resources and for implementation of new and emerging technologies.

On August 5, 2020, the Indiana Utility Regulatory Commission (IURC) approved $1,110,000 in civil penalties for pipeline safety violations in 2018 for Northern Indiana Public Service Company, LLC (NIPSCO).  NIPSCO failed to locate or mark its pipelines in the two days required by safety procedures.  Mr. Boyd, the Division’s Director, claimed NIPSCO committed 230 violations in 2018.

In 2017, the IURC approved a settlement agreement that outlined the cost of each violation NIPSCO commits in 2017, 2018 and 2019 with respect to locating underground gas pipelines and facilities subject to approval.  Each side recommended the Commission approved $1,110,000 in damages.  The Division’s deadline to file the petition for approval of 2019 penalties is December 31, 2020.

To access the order, visit this website: https://www.in.gov/iurc/files/44970%20S2%20PSD%20NIPSCO%20Order.pdf.

A California court of appeals recently held that utility companies operating in rural areas of the state do not collect a higher cost of capital, also referred to as a rate of return, than other utility companies.

In Ponderosa Telephone Co. v. California Public Utilities Commission, several small, rural, privately-owned telephone companies asked the California court of appeals to review a decision of the California Public Utilities Commission (“PUC”).[1]  The PUC’s ruling related to the companies’ cost of capital, “a measurement of the cost of obtaining debt and equity financing, and it reflects the amount investors would demand to compensate them for the risks of investing capital in the company.”[2]  This is also referred to as the rate of return, as it provides the target return on the utility’s capital.[3]  The number is a factor in determining a company’s rate base and is calculated by examining (1) the cost of debt, (2) the cost of equity, and (3) the capital structure.[4]

The companies filed a petition to the PUC proposing that their rates of return be reviewed and altered to approximately 14.6%. The proposed amount represented a significant increase from the previous figure of 10% and reflected special risk factors the companies faced, including their small size, industry risks, and regulatory risks.[5]  However, following its review, the PUC denied the companies’ requests and lowered their rates of return to approximately 9%. The companies sought a review of the ruling, arguing that the PUC’s conclusion was arbitrary and capricious, and was unsupported by substantial evidence.[6]

On June 27, 2019, the Indiana Supreme Court concluded that Indiana utility companies may be estopped from challenging the use of customer class revenue allocation factors under Indiana’s Transmission, Distribution, and Storage System Improvement Charge statute (the “TDSIC Statute”)[1] if such companies demonstrate uncontested support of the factors’ use in prior proceedings and the challenge would cause injury to an opposing party. The TDSIC Statute was enacted in 2013 and encourages energy utilities to replace their aging infrastructures by allowing them (1) to seek IURC pre-approval for certain gas or electric infrastructure projects and (2) to recoup the costs by submitting rate-increase petitions.[2]

Typically, base utility rates are set through a general ratemaking case before the IURC.[3] This type of review allows the IURC to ensure that utility rates are fair to both the utility company and to its customers.[4] However, rates can also be adjusted to reflect certain infrastructure projects and costs through the Commission in what is known as “tracker” or “rider” proceedings.[5]  Specifically, the TDSIC Statute provides two such proceedings under Section 9 and Section 10, both of which are distinct yet still related.[6] Under Section 10, utilities may seek approval of a multi-year plan from the IURC “for eligible transmission, distribution, and storage improvements.”[7]  Based on this multi-year plan, Section 9 subsequently permits utilities to petition the IURC for periodic rate adjustments to recover 80% of approved capital expenditures and TDSIC costs.[8] Section 9 petitions further require that customers use “the customer class revenue allocation factors based on firm load approved in the pubic utility’s most recent retail base rate case order.”[9]

At issue in NIPSCO Industrial Group v. Northern Indiana Public Service Co. was whether the IURC improperly approved of the use of customer class revenue allocation factors based on total load rather than firm load as required by the TDSIC Statute.[10] Initially, NIPSCO Industrial Group (the “Industrial Group”) and the Northern Indiana Public Service Company (“NIPSCO”) agreed to two expansive, multi-year settlements, which specified how rate increases should be calculated and allocated among the utility company’s various rate classes under the TDSIC Statute.[11] Ultimately, the IURC approved the agreements. However, despite being a party and approving the first Section 9 petition, the Industrial Group opposed NIPSCO’s second Section 9 petition. Specifically, the Industrial Group argued that the customer class revenue allocation factors included in NIPSCO’s second Section 9 petition were based not on firm load, but on total load. The IURC rejected the Industrial Group’s argument, leading the Industrial Group to seek judicial review.[12]