Articles Posted in Utility Law

On February 21, 2023, the Indiana Court of Appeals reversed an Indiana Utility Regulatory Commission (“Commission”) order granting Duke Energy Indiana (“Duke”) recovery of costs pursuant to federal Environmental Protection Agency (“EPA”) rules for treating coal ash and remediating ash ponds because the Commission had not yet approved the project, which constituted impermissible retroactive ratemaking. The central issue before the court was whether the Commission’s order allowing Duke to recover costs incurred “before or during the pendency of the proceeding, [and] prior to the issuance of the [o]rder” violated the prohibition against retroactive ratemaking. Ind. Office of Utility Consumer Counselor v. Duke Energy Indiana, LLC, 21A-EX-2702 at 2 (Ind. Ct. App. 2023) (“Duke Energy”). The Commission’s order grating cost recovery was pursuant to Indiana’s Federal Mandate Statute, which permits utilities, subject to Commission approval, to “track and cover 80% of such federally mandated costs via periodic rate adjustments, with recovery of the remaining 20% deferred to the utility’s next general rate case.” Duke Energy, 21A-EX-2702 at 11. The court determined that this was a question of law because the focus of the challenge was “whether the Commission can approve the reimbursement of already incurred costs without violating the perceived prospective language of the Federal Mandate Statute.” Id. at 7-8.

The “perceived prospective language” was recognized by the Indiana Supreme Court in Duke’s traditional rate case, Ind. Off. Of Util. Consumer Couns. V. Duke Energy Ind. LLC., 183 N.E.3d 266 (Ind. 2022) (“DEI”), where it noted that the Federal Mandate Statute “is framed in the future tense and speaks of ‘projected’ costs for ‘proposed’ projects which would seem to require [C]omission approval before a utility incurs the cost.” DEI, 183 N.E.3d at 270 (internal citations omitted). While agreeing with Duke that the above language was ditca, the court viewed it as “an indication that our supreme court believes a utility can only recoup certain expenses incurred under the Statute after gaining authorization from the Commission to track the expenses.” Duke Energy, 21A-EX-2702 at 14. According to the court, this position “is grounded in the principle that ratemaking is prospective in nature, not retroactive, with the demarcation between retroactive and prospective costs being the date of the Commission’s order, not the filing date of the utility’s petition.” Id. at 9 (internal citations omitted). As such, because the Federal Mandate Statue does not specifically authorize the recovery costs prior to a utility receiving a certificate of public convenience and necessity (“CPCN”), id., permitting recovery of costs “incurred prior to the Commission’s authorization would undo the purpose of Commission oversight and would present a disservice to the utility’s customers.” Id. at 17.

Therefore, because the Federal Mandate Statute serves as an exception to the general prohibition against retroactive ratemaking and is only effective after a utility receive a CPCN from the Commission for the project, permitting Duke to recover costs it had incurred prior to the Commission’s order “failed to follow the prospective strictures of the Federal Mandate Statute,” requiring reversal. Id.

On February 14, 2023, the U.S. Court of Appeals for the District of Columbia Circuit upheld an order from the Federal Energy Regulatory Commission (“Commission”) granting Broadview Solar, LLC’s (“Broadview”) application for its Montana facility to be a qualifying facility under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), holding that FERC’s interpretation of 16 U.S.C. § 796(17)(A) was reasonable and well-supported, and its decision to classify Broadview as a qualifying facility was not arbitrary or capricious. Solar Energy Industries Association v. FERC, No. 21-1126 at 3 (D.C. Cir. 2023). The court further held that Solar Energy Industries Association (“SEIA”) lacked Article III standing to challenge the Commission’s denial of its motion to intervene in the adjudication of Broadview’s application. Id.

The Montana facility consisted of a 160 MW solar array and 50 MW battery storage system, which both produced and stored direct current (“DC”). Id. at 4. The facility also had inverters which converted the DC to alternating current (“AC”) in order to be compatible with the nation’s electric grid. Id. The inverters had a total net capacity of 80 MW, meaning that the maximum amount of AC power produced at the Montana facility fell within the maximum power production capacity of 80 MW under § 796(17)(A). Id. The Commission originally denied Broadview’s application, determining that the 160 MW solar array exceeded the maximum power production capacity of 80 MW, which was a departure from the Commission’s earlier focus on a “facility’s net output, or send-out, capacity.” Id. at 4 (internal quotations omitted). Following Broadview’s request for rehearing, the Commission set aside its prior order and granted Broadview’s application, determining that § 796(17)(A) was “ambiguous as to the proper measure of a facility’s power production capacity” and that the former send-out approach was the best interpretation because “it takes into account all of the facility’s components working together, not just the maximum capacity of one subcomponent, and focuses on grid-useable AC power.” Id. at 5 (internal citations omitted).

The central dispute on appeal hinged on the meanings of “facility” and “power production capacity,” neither of which was defined by PURPA. Id. The court found the Commission’s interpretation of “power production capacity” as “the facility’s net output to the electric utility” and “facility” as “all of the [facility’s] component parts as they work together as a whole,” to be reasonable because the only grid-compatible power that Broadview produced was AC power through the inverters, which “work with the solar array and battery as an integral component in producing that power.” Id. at 7. This interpretation was further supported by the purpose of § 796(17)(A) because “the measure used to determine whether a facility is eligible for qualifying facility status is the same used to determine benefits available to qualifying facilities,” namely the mandatory purchasing requirement which only applies to AC power. Id. at 8. As such, the court determined that excluding a facility that cannot send out more than 80 MWs of AC power, even though some of the facilities components can produce more than 80 MW of DC power, would be inconsistent with PURPA’s goal of encouraging the development of small power production facilities and promoting the use of alternative energy sources. Id. Therefore, because the Commission’s interpretation of § 796(17)(A) was reasonable and well-supported, its decision to classify Broadview as a qualifying facility was not arbitrary or capricious. Id. at 12.

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]