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Both the IRS excess benefit statute and the private inurement doctrine DO NOT apply to tax-exempt cooperatives. 26 U.S.C. § 4958(c) defines an excess benefit transaction as “any transaction in which an economic benefit is provided by an applicable tax-exempt organization directly or indirectly to or for the use of any disqualified person.” For the purposes of this statute, an applicable tax-exempt corporation includes “any organization which…would be described in 501(3),(4), or (29)…” See 26 U.S.C. § 4958(e). As far as private inurement goes, the general rule is that no one private individual may benefit (i.e. receive earnings) from a charitable organization. (See Treas. Reg. Section 1.501(c)(3)-1(c)(2)). Allowing such inurement would run contrary to notion that many charitable organizations are set up for the benefit of the public, not individuals. However, coops are the exception to this doctrine. Indeed, tax-exempt organizations under 501(c)(12) do not share the same purpose as 501(c)(3)-(4) corporations. Unlike charitable corporations est. via 501(c)(3), coops organized under 501(c)(12) are set up precisely to benefit their members, who are almost always private individuals. Thus, application of the private inurement doctrine to tax-exempt cooperatives does not seem consistent with their established purpose.

 

James A. L. Buddenbaum has practiced law for more than 25 years with Parr Richey representing municipalities and businesses in utility, healthcare and general business sectors in both regulatory and transactional matters. Jim also has extensive experience in representing businesses in making large property damage and similar insurance claims.

The statements contained here are matters of opinion for general information purposes only and should not be considered by anyone as forming an attorney client relationship or advice for any particular legal matter of the reader. All readers should obtain legal advice for any specific legal matters.

A group of four former cooperative members filed a breach of contract claim against Flathead Electric Cooperative. Wolfe v. Flathead Elec. Coop., Inc., 393 Mont. 312, 314 (Mont. 2018).Plaintiffs were members of the coop during various times, the latest of which was in 2007. Plaintiffs alleged that Flathead violated Montana law when it allocated patronage capital to their accounts, but did not actually refund any capital to the members on an annual basis. The Federal District Court of Montana mentioned that plaintiff’s claim would not likely prevail, as the statute governing capital refunds only requires that refunds be distributed “whenever the revenue exceeds the amount necessary to fund operations.” Id. However, the district court did not ultimately reach this question. Instead, it ruled that Plaintiffs did not file their claim within the applicable 8-year statute of limitations. Id. at 315.

On appeal, the Supreme Court of Montana affirmed. Id. at 313. When bringing a claim under a written contract, the statute of limitations runs from the moment a plaintiff’s claim accrues. Id. at 315. The Court held that Plaintiffs’ claim had accrued in February, 2008, as this was the date of the last board meeting that took place while Plaintiffs were still members of the cooperative. Id. at 315-16. Their complaint was filed in September, 2016 – 8-and-a-half years after their claim had accrued. Thus, the statute of limitations for Plaintiff’s breach of contract claim had expired. Id. at 316.

The court rejected plaintiff’s argument of fraudulent concealment, which would have tolled the statute of limitations until the time of discovery. Id. Flathead had a defined policy regarding patronage capital in their bylaws, and the Court did not find that it took any affirmative action to deceive Plaintiffs. Id. at 317. The Court also rejected the Plaintiff’s assertion that the breach is ongoing, holding that the latest any Plaintiff was a member was up to the board meeting of 2008, and that Plaintiffs had knowledge of the breach from that point onward. Id. at 316.

On September 13, 2018, the Seventh Circuit Court of Appeals upheld an Illinois law, 20 ILSC 3855/1-75(d-5), who provides subsidies to some of the state’s struggling nuclear generation facilities, against a challenge by the Electric Power Supply Association (EPSA), an advocacy group for the electric power industry.

Under the Federal Power Act, the Federal Energy Regulatory Commission (FERC) is authorized to regulate the sale of electricity in interstate commerce while states regulate local distribution of electricity, as well as the facilities used to generate it. In this case, EPSA argued that the Illinois law was preempted by the Federal Power Act because the subsidies indirectly regulated the price of power, which only FERC has the authority to regulate.

The Seventh Circuit explained that the states’ and FERC’s powers under the Federal Power Act often overlap; it would be impossible for states to regulate the local distribution of electricity without at least affecting the price of power within its borders. If a state were to offer subsidies that depended on selling power in interstate auction, then the legislation would be preempted. However, the Illinois law in this case only regulates local generation of power. Thus, the court found no preemption and the law was upheld.

On June 20, 2018, the Indiana Supreme Court upheld a narrow interpretation of the Transmission, Distribution and Storage System Improvement Charge (“TDSIC”) statute in NIPSCO Industrial Group v. Northern Indiana Public Service Co., 100 N.E.3d 234 (Ind. 2018). A summary of that case can be found here: https://www.indianabusinesslawyerblog.com/nipsco-industrial-group-v-northern-indiana-public-service-co-100-n-e-3d-234-ind-2018/.

On September 25, 2018, the Indiana Supreme Court reissued their opinion in response to a rehearing on the issue. The modified opinion is largely identical to the opinion issued in June. The TDSIC statute allows for periodic rate increases to cover 80 percent of the approved cost estimates for an improvement project without going through the traditional ratemaking process. The remaining 20 percent of improvement costs are recovered through the next general rate case filed by the utility with the Indiana Utility Regulatory Commission (“Commission”). The Supreme Court modified the June opinion to add a clause clarifying that any cost overruns incurred during a TDSIC improvement project that are “specifically justified by the utility and specifically approved by the Commission” are also recoverable during the next general rate case filed with the Commission in addition to the remaining 20 percent of improvement costs. 100 N.E. 3d at 244.

Jeremy Fetty is a partner in the law firm of Parr Richey with offices in Indianapolis and Lebanon. Mr. Fetty is current Chair of the Firm Utility and Business Section and often advises businesses and utilities (for profit, non-profit and cooperative) on regulatory, compliance, and transactional matters.

On June 1, 2018, the U.S. Court of Appeals for the D.C. Circuit declined to review an order issued by the Federal Energy Regulatory Commission (“FERC”) holding that an operating company that withdrew from a “multi-state energy system” had to continue sharing benefits from a settlement with the other system members, even after it withdrew from the system.

In 1951, six companies from Arkansas, Louisiana, Texas, and Mississippi formed the Entergy Corporation, a publicly held utility company intended to share the costs and benefits of generating and transmitting power. The system agreement provided members the option to withdraw so long as the member gave an eight-year notice. Entergy Arkansas announced on December 19, 2005 that it intended to withdraw on December 18, 2013. In 2008, Entergy Arkansas settled state litigation against Union Pacific, which included a below-market rate for coal delivery as part of the settlement. Under the system agreement, all members realized some of the increased costs as a result of Union Pacific’s breach of contract, and they also realized the benefits of the reduced rate following the settlement.

In 2009, FERC approved both withdrawal notices, and held that neither Entergy Arkansas nor Entergy Mississippi should have to pay an exit fee to the other members. FERC held in subsequent proceedings that the settlement benefits should be allocated among the members and adopted a methodology for doing so.

On June 20, 2018, the Indiana Supreme Court upheld a narrow interpretation of the Transmission, Distribution and Storage System Improvement Charge (“TDSIC”) statute, which allows utility companies to seek approval from the Indiana Utilities Regulatory Commission (“IURC”) for specific transmission, distribution and storage system improvements and to raise rates periodically to recover the costs of the improvements as they are completed. The TDSIC statute was enacted in 2013 to encourage utilities to replace aging infrastructure without having to undergo the full ratemaking process and to recover the costs of the improvements as they were completed.

There are two types of proceedings under the TDSIC statute—Section 9 and Section 10. The Section 10 proceeding is the initial proceedings where a seven-year plan for eligible improvements, including cost estimates, is submitted and reviewed by the Indiana Utility Regulatory Commission (“IURC”). Once the plan is approved by the IURC, the utility may petition under Section 9 for periodic rate adjustments to recover 80 percent of capital expenditures for eligible, completed improvements. As a part of the Section 9 proceedings, the utility must also update the seven-year plan with the IURC. Furthermore, if the utility seeks to recover additional costs above the initially approved cost estimates, the utility must provide justification for the increase, and the IURC must approve the additional cost recovery.

At issue in this case was a seven-year plan filed by the Northern Indiana Public Service Company (“NIPSCO”) seeking approval for an improvement to its gas system under the TDSIC statute from the IURC. The Section 10 petition identified specific improvement projects for the first year, but for the remaining six years, the plan described “project categories” rather than identifying specific projects, because NIPSCO knows from historical data that a certain percentage of its systems will fail annually and need replacing (referred to as “ascertainable criteria”), but it cannot identify exactly which parts of its system will fail.  The IURC approved the Section 10 petition and subsequent Section 9 petitions. The NIPSCO Industrial Group (“Industrial Group”) intervened to oppose NIPCOS’s fourth Section 9 petition because it updated the gas plan with an increased cost of $20 million, but the IURC approved it because the petition further identified specific projects and asset replacements within the project categories approved in the Section 10 petition.

On June 27, 2018, the Indiana Supreme Court issued an opinion establishing that the Indiana Utility Regulatory Commission (“Commission”) is a proper party to an appeal of a Commission order. Hamilton Se. Utils., Inc. v. Indiana Util. Reg. Comm’n, No. 93A02-1612-EX-2742, 2018 Ind. LEXIS 496, at *1-12 (Ind. June 27, 2018).  Interestingly, the Commission had participated as a party in appeals of its orders without controversy until relatively recently, when parties began to challenge its standing to be a party in several appellate proceedings

This matter began in September 2015 when Hamilton Southeastern Utilities, Inc. (“HSE”) requested a rate increase from the Commission. HSE sought an 8.42% increase in rates, but the Commission only authorized a rate increase of 1.17%, partially because the Commission said that HSE should eliminate outsourcing expenses. Id. at *3-4. HSE appealed the order, initially naming the Commission as a party. HSE then moved to dismiss the Commission, claiming “it had mistakenly identified the Commission as a party” and that the Commission should not be a party because it had “acted as a fact-finding administrative tribunal.” Hamilton Se. Utils., Inc. v. Indiana Util. Reg. Comm’n., 85 N.E.3d 612, 617 (Ind. Ct. App. 2017).  The Court of Appeals granted the motion, reasoning that the Commission had adjudicated a rate case where the parties appearing before the Commission advocated for competing interests, and the Commission’s order “should speak for itself, without the need to further rationalize its decision.” Id. at 619. The Court of Appeals went on to affirm a number of the Commission’s decisions in calculating the 1.17% increase, but it held that the Commission arbitrarily excluded outsourcing expenses from that rate calculation. Id. at 626.

The Supreme Court granted transfer to review the question of whether the Commission was a proper party to the appeal of its order. The Court held that it was a proper party because it is a “long-standing custom and practice” to treat the Commission as a proper party to appeals of its orders, and the legislature had acquiesced to that practice. Hamilton Se. Utils., Inc, 2018 Ind. LEXIS 496, at *6.The Court noted that other “similarly situated executive branch agencies enjoy the ability to defend their decisions on appeal, both through explicit legislative directive” and through “legislative acquiescence to custom and practice.” Id. at *8. Furthermore, the Court said that public policy supports allowing the Commission to defend its orders on appeal in the interests of not disturbing a long-standing custom, promoting efficiency in the appeals process, and allowing the Commission to adequately represent its interests since opposing parties in a ratemaking case do not necessarily represent all of the Commission’s interests in defending its order. Id. at *10. Finally, the Court noted that the Commission’s role in the ratemaking case is administrative, not adjudicative, and therefore HSE’s argument that the Commission could not be a party because it adjudicated the proceedings failed. Id. at *11.

In June 2017, Florida Power and Light (“FPL”), a rate-regulated electric utility, filed an application with FERC requesting authorization to transfer its ownership interests in substation equipment and other assets to JEA, the largest community-owned electric utility in Florida. FERC dismissed FPL’s application for lack of jurisdiction. The net book value of the retained assets to be given to JEA was $3 million, including a $1.1 million value for the substation equipment.

FERC determined that FPL’s application was unnecessary and that FERC lacked jurisdiction to review the application. Under section 203(a)(1) of the FPA, FERC only has jurisdiction to review applications where a public utility seeks to: (A) sell, lease, or dispose of the whole of its facilities which are valued above $10 million; (B) merge or consolidate facilities with another person; (C) purchase , acquire, or take a security of another public utility in excess of $10 million; or (D) purchase, lease, or otherwise acquire an existing generation facility valued over $10 million that is used for interstate wholesale sales over which FERC has jurisdiction for ratemaking. 16 U.S.C. § 824b(a)(1) (2017). Subsection (A) did not apply because the value of the assets to be transferred was under $10 million. Subsections (C) and (D) likewise did not apply.

FPL stated in its application that subsection (B) applied to transactions involving the acquisition of transmission facilities from non-jurisdictional municipal entities and that FERC had not yet addressed whether subsection (B) applied to the disposition of transmission facilities from a jurisdictional public utility to a non-jurisdictional municipal entity. FERC determined that subsection (B) did not apply to the sale or other disposition of jurisdictional facilities. Additionally, subsection (B) did not apply because the party acquiring the facilities is a municipal entity.

The First Circuit Court of Appeals recently issued an opinion finding that the Public Utility Regulatory Policies Act (“PURPA”) does not authorize lawsuits between cogeneration facilities and electric utilities because there is no express or implied private right of action in the statutory language. Allco Renewable Energy, Ltd. V. Mass. Elec. Co., 875 F.3d 64 (1st Cir. 2017). PURPA was enacted to encourage the development of energy-efficient cogeneration and small power production facilities, requiring electric utilities to purchase energy from “qualifying facilities” at a regulation-specified cost rate. Under FERC regulations, the cost rate is the rate equal to the utility’s full avoided cost. A qualifying facility under PURPA is a “nontraditional” facility which produces energy from sources such as biomass, waste, renewable resources, or geothermal resources.

In Allco, the plaintiff was a qualifying facility that wanted to negotiate a purchase agreement with defendant National Grid, an electric utility. Instead of negotiating a purchase agreement, National Grid offered to purchase Allco’s energy under its standard power purchase contract. Allco petitioned the Massachusetts Department of Public Utilities (“MDPU”) to investigate the reasonableness of National Grid’s offer, which the MDPU denied. FERC subsequently denied Allco’s petition asking FERC to bring an enforcement action against MDPU, and Allco sued National Grid and other state defendants.

The court analyzed section 210 of PURPA to determine whether it created an express or implied private right of action allowing a qualifying facility to sue an electric utility. PURPA expressly authorizes FERC to bring enforcement actions against a state in federal court and allows a qualifying facility to sue the state utility regulatory agency in state court for PURPA violations—it does not authorize suits between  qualifying facilities and electric utilities. The court also held that Congress did not implicitly authorize this kind of lawsuit because of the aforementioned express enforcement provisions. Additionally, the court invalidated MDPU regulations relating to calculating a utility’s avoided costs, but left the proper calculation to the MDPU since state utility regulatory agencies are responsible for implementing FERC’s regulations for rate determinations.

The Indiana General Assembly recently made changes to the Indiana Underground Plant Protection statute (Indiana Code § 8-1-26) which will take effect July 1, 2017. S.B. 472, 120th Gen. Assem., Reg. Sess. (Ind. 2017). The main change in this chapter is the creation of a new voluntary “design information notice” which applies to advance planning efforts relating to a demolition or excavation project. The amendments also establish procedures for Indiana 811 and operators once a design information notice is received.

A design engineer, consultant, or architect may voluntarily submit a design information notice to Indiana 811, which must include contact information for the person serving the notice, the person responsible for project planning activities, and the person planning to perform the excavation or demolition, if known. The notice must also include the scope and location of the proposed project and whether white lining will be performed. The person responsible for the project may not serve more than two design information notices for the same project within any 180-day period. Additionally, if the person serving the design information notice is unable to provide the physical location of the proposed excavation or demolition project with the location’s address or legal description, the person must perform white lining in the area affected by the proposed project. Indiana 811 must receive the notice at least ten working days, but not more than twenty calendar days before preliminary planning activities commence. Indiana 811 is required to adopt policies for processing design information notices, including alerting the operators of underground facilities that will be affected by the proposed project and providing this list of operators to the party serving the design information notice.

Once an operator or utility receives a design information notice, it must, within ten working days, contact the person serving the notice and inform them whether the operator has underground facilities located in the project area. If the operator does have underground facilities in the area, it must provide either a description of the location and type of facility affected by the proposed project, allow an inspection of the operator’s drawings or records for all of the operator’s underground facilities within the project area, or mark the location of the operator’s underground facilities within the project area with temporary markers. The operator must also, where applicable, provide the person serving the notice with the necessary maps or information to describe the location of all facility markers marking the underground utility. An operator may reject a design information notice where there are security considerations or the operator would be placed at a competitive disadvantage by producing the information. An operator who rejects a design information notice must provide notice to the person serving the design information notice and may request additional information.

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