On August 31, 2023, FERC approved Missouri River Energy Services (Missouri River) request for three transmission incentives for its investment in two, high-voltage transmission line segments which are part of the Big Stone Project, a MISO Multi-Value Project that is part of the portfolio of 18 Long Range Transmission Tranche 1 Projects included in MTEP 2021.  Missouri River requested (1) a hypothetical capital structure of 50% equity and 50% debt (Hypothetical Capital Structure Incentive) for its investment in the Big Stone Project; (2) inclusion of 100% of prudently incurred Construction Work in Progress (CWIP) in rate base for the Big Stone Project (CWIP Incentive); and (3) recovery of 100% of prudently incurred costs in the Big Stone Project’s transmission facilities that are abandoned for reasons beyond Missouri River’s control (Abandoned Plant Incentive).     
   
The Big Stone Project involves the construction of two high-voltage transmission line segments.  The first segment is an approximately 95-105-mile, 345 kV line from the Big Stone South Substation in South Dakota owned by Otter Tail Power Company (Otter Tail) to the Alexandria Substation in Minnesota owned by Missouri River (Big Stone South-Alexandria segment).  Missouri River states that the line will be on a new right-of-way and is expected to be constructed to facilitate  a potential second 345 kV circuit on the same towers.  Missouri River further states that both the Big Stone South and Alexandria Substations will need to be expanded to terminate the new line.  The second segment of the Big Stone Project is a 345 kV line from the Alexandria Substation to the planned new Big Oaks Substation in Minnesota (Alexandria-Monticello segment).  This line will be strung largely on existing double-circuit capable towers and will also require the acquisition of some new rights-of-way as the line approaches the Big Oaks Substation near the Mississippi River.  Missouri River explains that the Alexandria Substation will also have to be expanded to terminate the Alexandria-Big Oaks line segment. 

The Big Stone Project has an expected in-service date of June 1, 2030 with an estimated total cost of $573.5 million (in 2022 dollars), with Missouri River’s investment comprising approximately 50% at an estimated amount of $285.6 million.   In addition to state and federal approvals, the Big Stone Project requires a certificate of need and route permit from the Minnesota Public Utility Commission and a facility permit from the South Dakota Public Utilities Commission. 

The remainder of this blog covers the hypothetical capital structure request.  Missouri River sought authorization to use a hypothetical capital structure of 50% equity and 50% debt for the life of the financing of the Big Stone Project.  In support, Missouri River explained that, as a municipal joint action agency, Missouri River cannot issue stock and thus cannot raise equity capital through a stock offering to finance the Big Stone Project.   Missouri River therefore contended that a hypothetical capital structure is needed to provide the returns necessary to achieve the financial metrics identified in the rate policy of Missouri River’s Board of Directors and to produce a debt service coverage ratio that is consistent with maintaining Missouri River’s existing Moody’s  Aa2 credit rating.  Missouri River explained that, without the Hypothetical Capital Structure Incentive, the debt service coverage ratio on the Big Stone Project would be below the range expected of a Moody’s Aa2-rated joint action agency and would put substantial downward pressure on Missouri River’s current credit rating.  Missouri River further explained that the Hypothetical Capital Structure Incentive provides a return to reflect the higher risk and complexities of the Big Stone Project as the projected $285.6 million investment in the Big Stone Project will be the largest transmission investment ever made by Missouri River, representing 221% of Missouri River’s projected 2023 net transmission plant of $129.5 million and 48% of its total long-term debt.   Missouri River also asserted that the Big Stone Project requires multiple permits and must be coordinated with multiple owners, which creates a more complex negotiating, decision-making, and implementation process; therefore, Missouri River maintained that, without the Hypothetical Capital Structure Incentive, “it would make more sense for Missouri River to invest in other more routine projects.”   Finally, Missouri River argued that granting the Hypothetical Capital Structure Incentive will further the Commission’s policy goal of promoting public and cooperative power investment in transmission  and is consistent with Commission precedent.
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FERC granted Missouri River’s request for the Hypothetical Capital Structure, finding that Missouri River had demonstrated that the requested incentives are tailored to the risks and challenges faced by the Big Stone Project and that approval of the Hypothetical Capital Structure Incentive and CWIP Incentive will bolster Missouri River’s financial metrics, help ensure maintenance of its current credit rating, and enable its participation in the Big Stone Project.  Further, FERC found that the requested hypothetical capital structure is within the range that the Commission has allowed for other entities reliant on non-equity financing.

​On February 28, 2023, in Docket No. ER18-99, FERC issued an order[1] addressing exceptions to an Initial Decision issued on December 6, 2021.[2]  The Initial Decision concerned disputes arising from Southwest Power Pool, Inc.’s (SPP) proposal to revise its Open Access Transmission Tariff (Tariff) to include the annual transmission revenue requirement (ATRR) of transmission facilities associated with the City of Nixa, Missouri (City of Nixa), owned by GridLiance High Plains LLC (GridLiance),[3] in one of SPP’s existing transmission pricing zones, SPP Pricing Zone 10 (Zone 10), for purposes of rate recovery (Nixa Assets).  In the Initial Decision, the Presiding Judge concluded that SPP’s proposal to incorporate the Nixa Assets in Zone 10 is consistent with cost causation principles and is otherwise just and reasonable.  In its Order on Initial Decision, FERC affirmed the Initial Decision.  On March 29, 2023, a joint request for rehearing was filed by two different intervener groups.  In its Order on Rehearing issued July 5, 2023, FERC modified the discussion in the Order on Initial Decision and continued to reach the same result.
 
Background:  SPP uses a zonal rate design, pursuant to which its footprint is separated into several transmission pricing zones for purposes of establishing transmission service rates.  The Tariff specifies a zonal ATRR for each pricing zone that is based on the sum of the ATRRs for each transmission owner in the zone.  The charges for Network Integration Transmission Service (network service) in a pricing zone are calculated by multiplying a customer’s percentage share of total load in the zone (i.e., its load ratio share) by the zonal ATRR.  When a new transmission owner is added to an existing pricing zone, the ATRR for its transmission facilities in the zone and any associated load not already included in the zonal load are added to the existing zone’s zonal ATRR and total load.  In 2017, SPP instituted a new Transmission Owner Zonal Placement Process (Zonal Placement Process) to review and determine zonal placement for existing transmission facilities that new SPP transmission-owning members propose to include under the SPP Tariff.  A group of SPP transmission owners challenged the SPP Zonal Placement Process, arguing that allocating the costs of a new SPP member’s transmission facilities to existing customers of a zone results in an unjust and unreasonable cost shift between new and existing transmission customers.[4]  Although FERC denied the complaint,[5] it also stated that parties may challenge the placement of a new transmission owner’s facilities in a transmission pricing zone.[6]  The Nixa Assets consist of approximately 10 miles of transmission lines and related facilities interconnected to Southwestern Power Administration (Southwestern) in Zone 10 and to City Utilities of Springfield, Missouri (City Utilities) in SPP Pricing Zone 3 (Zone 3).[7]  On October 18, 2017, SPP submitted proposed Tariff revisions to add an ATRR and a formula rate template and implementation protocols for the Nixa Assets.  SPP explained that it had used its Zonal Placement Process to place the facilities in Zone 10.  On March 15, 2018, FERC set the Tariff revisions for hearing and settlement judge procedures.[8]  After a settlement was unsuccessfully put forth to FERC, in late 2021, the Presiding Judge issued the Initial Decision, which addressed three general issues:  (1) whether, and to what extent, the placement of the Nixa Assets in Zone 10 involves a cost shift; (2) whether benefits accrue to Zone 10 customers as a result of placing the Nixa Assets in Zone 10; and (3) whether the benefits justify the cost shift.  The Presiding Judge determined that SPP’s proposal to incorporate the Nixa Assets in Zone 10 is consistent with cost causation principles and is otherwise just and reasonable.[9]  Specifically, the Presiding Judge found that:  (1) the placement of the Nixa Assets in Zone 10 will result in a $1.8 million cost shift to Zone 10 customers; (2) the Nixa Assets accrue substantial, specific, but unquantifiable benefits (i.e., integration benefits, reliability enhancements, and support for power transfers) to Zone 10 customers; and (3) those benefits justify the cost shift involved in the placement of the Nixa Assets in Zone 10.  In its Order on the Initial Decision, FERC affirmed the findings that SPP’s proposal to include the ATRR for the Nixa Assets in Zone 10 is just and reasonable and consistent with the cost causation principle and, accordingly, accepted SPP’s proposed Tariff revisions.  As to the amount of the cost shift, FERC determined that the Presiding Judge properly balanced competing evidence to reach the finding that the cost shift at issue in this proceeding should be calculated as GridLiance’s proposed ATRR for the Nixa Assets, which is $1.8 million.  In doing so, FERC rejected arguments that the proper amount of the cost shift should be measured by the amount or percentage of the Gridliance ATRR for the Nixa Assets  that will be paid by non-City of Nixa customers rather than the full amount of the GridLiance ATRR.  FERC explained that “the City of Nixa is already a Zone 10 customer and the Commission’s evaluation of the cost shift to Zone 10 customers can and should incorporate costs paid by the City of Nixa as well as other customers in that zone.”  FERC also affirmed the Presiding Judge’s finding that the Nixa Assets provide benefits that accrue to Zone 10 customers, concluding that the record supports the finding that the Nixa Assets provide integration, reliability, and power transfer benefits to Zone 10 customers.  Responding to “the main argument raised on exceptions” that the benefits that the Nixa Assets provide allegedly accrue mostly, if not entirely, to the City of Nixa rather than other Zone 10 customers, FERC found that the Presiding Judge properly evaluated the benefits of the Nixa Assets to all Zone 10 customers—including the City of Nixa—rather than restricting his findings to non-City of Nixa customers.  In doing so, FERC explained that “under SPP’s zonal rate design, all customers in a pricing zone pay a rate based on the ATRRs associated with all transmission facilities in that zone, regardless of which facilities may have previously been used to provide service to a specific customer prior to the customer or the Transmission Owner joining the [Regional Transmission Organization (RTO)].”  FERC  also affirmed the Presiding Judge’s finding that the benefits to Zone 10 customers from the Nixa Assets are roughly commensurate with their costs, and therefore SPP’s proposal to include the Nixa Assets in Zone 10 was just and reasonable.  FERC found that arguments that it should treat the “roughly commensurate” standard as requiring that any costs of a facility should be distributed “roughly proportionate” to the usage of that specific facility were “contrary to Commission precedent and inconsistent with how costs are allocated within SPP.”  Finally, FERC affirmed the Presiding Judge’s dismissal of the alternative rate proposals made by intervenors since, having affirmed the Presiding Judge’s finding that SPP’s proposal is just and reasonable, it “need not consider whether the proposal is more or less reasonable than other alternatives.”
 
Arguments on Rehearing:   Intervener arguments centered around their claim that a cost shift associated with a zonal placement decision under SPP’s Tariff cannot be just and reasonable unless each customer (or group of customers)  that will bear some portion of the costs of those assets (or group of assets) is deriving a benefit from those specific assets that is “roughly proportionate” to those costs.   The interveners sought to apply an asset-level, beneficiary-pays rough proportionality requirement.  FERC disagreed with this view as it  does not square with the existing zonal rate construct under the SPP Tariff.  Under that construction, a transmission customer taking network service shall pay a monthly demand charge for the SPP Pricing Zone where the load is located (Load Ratio Share).  As evident in this formula/calculation, SPP’s zonal rate construct does not attempt to measure each transmission customer’s benefit from each transmission asset included in the zonal ATRR.  Nor does it charge each customer transmission costs on an asset-by-asset basis.  Instead, under that zonal construct, the costs and benefits associated with network service in a zone are assessed on an aggregate level, with each customer paying for transmission service based on its load ratio share, which reflects its total use of the aggregate assets in the zone.   Even if a customer does not benefit from a particular transmission asset in a manner roughly commensurate with its load ratio share, this does not demonstrate that the customer is not overall receiving roughly commensurate benefits from the transmission assets within the zone as compared to the zonal rates it is paying under SPP’s Tariff.  The interveners also attempted to align their proposed proportionality requirement with SPP’s zonal rate construct by arguing that RTO zones will be ordinarily configured to allocate the costs of transmission facilities to the customers for whom they were constructed.   FERC agreed that, in a typical case, it expects that a transmission asset should be included in the same zone as the customers for whom they were constructed and continue to serve.   But this principle does not establish that zones generally, or SPP Pricing Zones in particular, have been or must be constructed to ensure that each customer benefits from each asset in the zone in rough proportion to the costs it pays for that specific asset, or that new assets that may be included in a zone must meet such a requirement.
 
FERC asserted that the facts of this case are as follows:  including the Nixa Assets in Zone 10 will result in a $1.8 million increase in the zonal ATRR, a portion of which will be borne by the City of Nixa based on its load ratio share under SPP’s existing Tariff.   Under these circumstances, considering the cost shift in terms of the $1.8 million ATRR of the Nixa Assets ensures that FERC does not take an incomplete view of the impacts of placing the Nixa Assets in Zone 10 by focusing only on how including the assets in Zone 10 impacts the non-City of Nixa customers.  Considering the full picture of the costs and benefits of the Nixa Assets to all Zone 10 customers is also consistent with SPP’s zonal rate construct, which does not evaluate the costs and benefits of transmission assets in a zone at the level of how individual customers use each of those assets, as explained above.      


[1] Sw. Power Pool, Inc., 182 FERC ¶ 61,141 (2023) (Order on Initial Decision).

[2] Sw. Power Pool, Inc., 177 FERC ¶ 63,021 (2021) (Initial Decision).

[3] GridLiance was formerly known as South Central MCN LLC.

[4] Indicated SPP Transmission Owners v. Sw. Power Pool, Inc.,                         162 FERC ¶ 61,213 (ITOs Complaint Order), reh’g denied, 165 FERC ¶ 61,005 (2018) (ITOs Complaint Rehearing Order). 

[5] Order on Initial Decision, 182 FERC ¶ 61,141 at P 4 (summarizing the basis for the Commission’s denial of the complaint in the ITOs Complaint Order and ITOs Complaint Rehearing Order).

[6] ITOs Complaint Order, 162 FERC ¶ 61,213 at P 74.

[7] GridLiance acquired the Nixa Assets from the City of Nixa on April 1, 2018.  Missouri Joint Municipal Electric Utility Commission then acquired the Nixa Assets from GridLiance on May 19, 2022.  See Sw. Power Pool, 179 FERC ¶ 61,134, at P 1, 4 (2022). 
 

[8] Sw. Power Pool, Inc., 162 FERC ¶ 61,215 (Hearing Order), order on reh’g and clarification, 164 FERC ¶ 61,120 (2018) (Rehearing Order).

[9] Initial Decision, 177 FERC ¶ 63,021 at PP 2, 188, 206.

​This summary concerns the Order Addressing Arguments Raised on Rehearing regarding reactive power compensation in MISO (Rehearing Order).
Background:  On November 30, 2022, in Docket No. ER23-523, MISO, on behalf of the MISO Transmission Owners (MISO TO),[1] submitted proposed revisions to Schedule 2, Reactive Supply and Voltage Control from Generation or Other Sources Service of OATT.  The MISO TOs proposed to eliminate all charges under Schedule 2 for the provision of reactive power within the standard power factor range for the MISO TOs’ own and affiliated generation resources.[2]  Based on the Commission’s “comparability standard,” MISO TOs stated that their proposal also terminates the obligation under Schedule 2 to pay unaffiliated generation resources in MISO for reactive power within the standard power factor range.  In its Reactive Power Order, FERC accepted the MISO TOs’ proposed Schedule 2 revisions, effective December 1, 2022.  This means that the $220 million being paid in MISO to generators for the provision of reactive power ended December 1, 2022.  

Several parties requested rehearing.  On July 12, 2023, FERC issued its Order on Rehearing (Rehearing Order - 184 FERC ¶ 61,022), modifying the discussion in the Reactive Power Order and continuing to reach the same conclusion.  Here are the items FERC discussed in its Rehearing Order: 

Comparability Standard:  FERC restated that electric power consists of two components:  real power, which is “the power that does real work—and thus the power that sellers are looking to sell and that buyers are looking to buy;” and reactive power, which is necessary to maintain adequate voltages so that real power can be transmitted.[3]  The provision of reactive power by generating facilities involves two different concepts.  Where reactive power is provided outside of the standard power factor range, it is “an ancillary service for transmitting power across the grid to serve load.”[4]  By contrast, where the generating facility is operating within the standard power factor range, “it is meeting its obligation as a generator to maintain the appropriate power factor in order to maintain voltage levels for energy entering the grid during normal operations.”[5]  Put differently, reactive support by generating facilities operating within the standard power factor range ensures that when these facilities inject real power—the product that their facilities exist to create and sell—onto the grid under normal conditions, they can do their part to maintain adequate voltages and not to threaten reliability.  FERC’s longstanding policy is  “that the provision of reactive power within the standard power factor range is, in the first instance, an obligation of the interconnecting generator and good utility practice,” such that “MISO TOs do not have an obligation to continue to compensate an independent generator for reactive power within the standard power factor range when its own or affiliated generators are no longer being compensated. 
Order No. 2003 reflects the distinction between these two different reactive power concepts.   When the transmission provider asks the interconnecting generator to operate its facility outside the established power factor range, the transmission provider is required to pay the interconnecting generator for the provision of such reactive power.   By contrast, compensation for reactive power when the generating facility is operating within the established power factor range is not required.   The sole exception FERC identified was that “if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range, it must also pay the Interconnection Customer.”   This is referred to as the comparability standard.  In the Reactive Power Order, the Commission accepted MISO TOs’ proposal to eliminate all charges under Schedule 2 for the provision of Reactive Service.  The effect of this order was not to “categorically prohibit new generation resources from seeking to recover the costs of their investment in reactive power capability.”   Rather, this order eliminated only Schedule 2’s mandated, separate stream of compensation for the capability of providing Reactive Service, which had been required in MISO consistent with the comparability standard.  This result is not unusual and is in fact already the case in other large RTOs or ISOs:  for example, Southwest Power Pool, Inc. has eliminated compensation within the power factor range,  and CAISO never provided such stand-alone compensation for Reactive Service. 
In its Rehearing Order, FERC stated that for synchronous resources, there is little or no incremental capital expenditure associated with the equipment necessary to produce reactive power because the same equipment is used to produce real power.   FERC went on to state that its conclusion that the same equipment used for Reactive Service is also necessary to produce real power is also supported by application of the AEP cost allocation methodology that apportions costs for synchronous generating plants.  As to non-synchronous resources,  the principal piece of equipment required for non-synchronous resources to produce reactive power is the inverter,  which is already necessary to convert the direct current produced by non-synchronous resources to alternating current—i.e., to supply real power that can be injected into alternating current power systems.  On rehearing and in earlier protests, no party points to any other equipment costs incurred by non-synchronous generating facilities that are attributable to providing Reactive Service.  

Reliance:  Numerous parties assert that independent power producers have come to rely on Schedule 2 compensation and argue that FERC erred in accepting MISO TOs’ proposal.  At the outset, FERC again noted that its acceptance of MISO TOs’ proposal considering the comparability standard was an application of the Commission’s long-standing policy in Order Nos. 2003 and 2003-A, consistent with its numerous subsequent decisions.  The parties on rehearing are, in effect, urging that generators’ unilateral business decisions to treat Schedule 2 compensation as irrevocable should amount to a new exception—in addition to the comparability standard—to Order No. 2003’s determination that compensation for Reactive Service should not be provided.  FERC rejected that argument in the Reactive Power Order and sustained that determination on rehearing.

Reliability:  FERC disagreed that it failed to adequately consider the effects of eliminating Schedule 2 compensation on grid reliability.   The Reactive Power Order considered the potential reliability impacts of MISO TOs’ proposal,  and FERC sustained its conclusions for the reasons articulated therein.  Moreover, arguments that accepting MISO TOs’ proposal erodes the incentive to invest in reactive power capability  are unpersuasive.  Under Order Nos. 2003 and 2003-A, reactive power capability within the standard power factor range (i.e., Reactive Service) is and remains mandatory for generator interconnection, without incentives.  The financial and other incentives for generators to invest in equipment to ensure reliability by providing reactive power outside of the standard power factor range are unaltered by and, in fact, not at issue in MISO TOs’ proposal.

Retail Rates:  Certain parties argue, primarily relying on Conway, that the possibility that generation owned or controlled by MISO TOs might recover the costs of reactive power capability from retail customers requires that independent power producers must also be compensated for such costs in their wholesale rates.   But this amounts to a generic argument that Schedule 2 compensation for Reactive Service is required not just when the transmission owner “pays its own or its affiliated generators for reactive power within the established range”  but also when the transmission owner can recover its costs through its bundled retail rates.  Neither Order Nos. 2003 and 2003-A, nor any of the Commission’s prior decisions, have ever suggested this requirement.  Arguments that Schedule 2 compensation is required unless transmission owners disclaimed the opportunity to recover Reactive Service costs in their retail rates were brought as challenges to Order No. 2003 and are not now properly before FERC.  FERC concluded that the possibility of compensation through retail rates did not give rise to a comparability issue or dictate that the Commission requires compensation under Schedule 2.   FERC further noted that Conway concerned allegations of actual anticompetitive behavior, namely that a public utility engaged in the sale of energy at both retail and wholesale sought to raise its wholesale rates in a way that would squeeze its customers, who competed with it in the retail market, out of that retail market.   The U.S. Supreme Court held that FERC has jurisdiction to consider the interplay between retail and wholesale rates in assessing a proposal to change a wholesale rate.   Here, by contrast, there are no allegations of anticompetitive behavior parallel to those in Conway, and—as noted in the Reactive Power Order—FERC  concluded that the comparability principle is satisfied by the fact that Schedule 2 compensation is being terminated for all generation, notwithstanding that the particular alternative avenues available to seek to recover Reactive Service costs may differ between transmission owners and independent power producers. 

Filing Rights and Procedures:  Some interveners argued that MISO TOs’ proposal failed to follow the appropriate procedures under Appendix K of the MISO TO Agreement in that the filing was not supported by the required majority vote nor was it the result of the required stakeholder process.  FERC found these arguments unpersuasive as there no requirement that the filing be supported by a public vote of eligible MISO TOs, under which the identity of those voting and how they voted must be disclosed, and FERC had no reason to doubt MISO TOs’ statement as to the outcome of the vote.  In the Reactive Power Order, FERC also rejected arguments that MISO TOs lacked authority to file their proposal under FPA section 205 because MISO TOs only have unilateral filing rights as to their own generators.  FERC explained it had previously found, and the D.C. Circuit in Dynegy affirmed, that pursuant to the settlement adopting section 9.6.3 of the MISO pro forma GIA, “transmission owners and the Midwest ISO share the same section 205 filing right, which is the right to submit filings under FPA section 205 to govern the rates, terms, and conditions applicable to the provision of ancillary services.”  FERC further concluded—consistent with the reasoning in the Reactive Power Order—that arguments asserting that accepting MISO TOs’ proposal undermines generators’ FPA section 205 filing rights reflect a misunderstanding of how compensation is provided for reactive service in MISO.  Specifically, whatever rights interconnection customers (including independent power producers) may have to compensation for Reactive Service must be consistent with the terms of their GIAs.   Section 9.6.3 of the MISO pro forma GIA provides that such payments shall be “pursuant to any tariff or rate schedule filed by Transmission Provider and approved by the FERC.”   Thus, generators who have GIAs with this or a similar provision have agreed to make their compensation for reactive power contingent on the contents of Schedule 2, which MISO (and MISO TOs through Appendix K) have the right to revise through an FPA section 205 filing.  Prior to FERC’s acceptance of MISO TOs’ proposal, Schedule 2 provided that the amount of such compensation for Reactive Service was determined by reference to generators’ annual reactive power revenue requirements.   MISO TOs’ proposal altered Schedule 2—and only Schedule 2—to provide that “there will be no separate charge to compensate any generation resource for reactive service within the standard power factor range.”   In other words, MISO TOs’ proposal did not adjust, overturn, or reduce to zero  any generator’s annual revenue requirement for reactive power, but rather revised the Tariff such that those revenue requirements are no longer cross-referenced as the basis for determining the amount of compensation for Reactive Service. 

Constitutional Arguments:  In the Reactive Power Order, the Commission rejected arguments that MISO TOs’ proposal violates the Takings Clause and Due Process Clause of the Fifth Amendment to the United States Constitution.   The obligation to provide Reactive Service exists independent of, and was not altered by, MISO TOs’ proposal:  it was stated in Order No. 2003 and applies to individual generators through their GIAs.   MISO TOs proposed only to change the compensation for Reactive Service, eliminating a stream of revenue under Schedule 2.  FERC thus concluded that arguments that the obligation to provide Reactive Service is unconstitutional are impermissible collateral attacks on our prior determinations. Generators do not have a property interest in continued Reactive Service compensation under the Tariff nor did MISO TOs’ proposal unconstitutionally deprive generators of that putative property interest under the Takings Clause or Due Process Clause of the Fifth Amendment.
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Dissent:  In the Rehearing Order, Commissioner Danly reiterated his dissention.  In his dissention to the Reactive Power Order, he stated that, notwithstanding the increased rates and the administrative burden of the present compensation approach, FERC cannot simply accept the MISO TOs’ proposal unless they meet their section 205 burden that the proposed rate—in this case, the elimination of reactive power compensation—is just and reasonable based on substantial evidence in the record.  He went on to state that the MISO TOs did not offer any evidence of the effects of eliminating the $220 million annual reactive power revenue requirement from the MISO tariff, and what is clear on the record is that separate reactive power compensation has been available in MISO for several years, and parties have taken this into account in their financings, bilateral contracting, power purchase agreements, and other arrangements.


[1] MISO TOs include:  Ameren Services Company, as agent for Union Electric Company, Ameren Illinois Company, and Ameren Transmission Company of Illinois; Arkansas Electric Cooperative Corporation; City Water, Light & Power (Springfield, IL); Cooperative Energy; Dairyland Power Cooperative; East Texas Electric Cooperative; Entergy Arkansas, LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy Texas, Inc.; Great River Energy; Indianapolis Power & Light Company; Lafayette Utilities System; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy Services; Montana-Dakota Utilities Co.; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Prairie Power, Inc.; Southern Indiana Gas & Electric Company; and Southern Minnesota Municipal Power Agency.

[2] The phrase “standard power factor range” refers to the power factor range required for interconnection and set forth in the interconnecting generator’s generator interconnection agreement (GIA).  MISO’s pro forma GIA prescribes a power factor range of 0.95 leading to 0.95 lagging.”   

[3] Sw. Power Pool, Inc., 119 FERC ¶ 61,199 at P 28 (SPP), order on reh’g,
121 FERC ¶ 61,196, at PP 16-22 (2007) (SPP Order on Rehearing); see also Bonneville, 120 FERC ¶ 61,211 at P 21 (“The purpose for which generation assets are built (including reactive power capability to maintain voltage levels for generation entering the grid) is to make sales of real power.”).

[4] Mich. Elec. Transmission Co., 97 FERC ¶ 61,187, at 61,852-53 (2001) (emphasis added).

[5] Id. at 61,853 (emphasis added); SPP, 119 FERC ¶ 61,199 at P 29; cf. Dynegy Midwest Generation, Inc., 125 FERC ¶ 61,280, at P 16 (2008) (“Reactive power is a localized service that is quickly used by transmission system components and cannot be transported over long distances.”).

​In Docket No. ER22-2968,  on September 30, 2022, as supplemented on February 14, 2023, SPP submitted proposed revisions to Attachment V (Generator Interconnection Procedures (GIP)) of its OATT to implement a new pro forma Facilities Service Agreement (FSA).  In SPP, an interconnection customer is responsible for 100% of the costs of network upgrades needed to accommodate its interconnection request.   Article 11.4 in SPP’s pro forma GIA provides two options for funding the costs of network upgrades for generator interconnection.   Under the first option, the interconnection customer pays for the network upgrade costs upfront during construction (Generator Upfront Funding).  Under the second option, the transmission owner can unilaterally elect to provide the upfront funding for the capital cost of the network upgrades (Transmission Owner Initial Funding).  SPP’s OATT did not contain provisions pertaining to how an interconnection customer would reimburse the transmission owner under the second option.
In the pro forma FSA, SPP proposed that the interconnection customer reimburse the transmission owner for a return on and of the capital costs of the network upgrades and system protection facilities needed for the interconnection customer’s interconnection service.  Specifically, SPP proposes a default 20-year term over which the interconnection customer reimburses the transmission owner through a monthly network upgrade charge.  The network upgrade charge is calculated using a formula rate that is based on the FSA’s term and the transmission owner’s Attachment H formula rate using data from the previous calendar year.  Additionally, the pro forma FSA requires that the interconnection customer post security in the amount of the initial capital cost, which may be reduced pro rata over the FSA’s term.  SPP stated that it also proposed revisions to its GIP and its pro forma GIA to effectuate certain provisions related to the pro forma FSA and the transmission owner’s election of Transmission Owner Initial Funding.
FERC found that the nonbinding notice by the transmission owner indicating it intends to fund network upgrades could lead to greater uncertainty for interconnection customers as the transmission owner could later change its election which could cause risk and uncertainty and delays for interconnection customers and could lead to late-stage withdrawals and attendant delays in administering the generator interconnection queue.  SPP contended that its filing and nonbinding transmission owner elections is substantially similar to generator interconnection procedures the Commission has accepted in MISO.  FERC disagreed, as MISO proposed, and FERC accepted, revisions to its tariff to add deadlines by which transmission owners must make both non-binding and binding elections of Transmission Owner Initial Funding prior to the start of the GIA negotiation phase.   The SPP proposal included only the non-binding indication provision during the first phase of SPP’s DISIS process.  FERC rejected the SPP OATT changes.  Therefore, though the SPP OATT provides for transmission owner funding of network upgrades, it still lacks provisions pertaining to how an interconnection customer would reimburse the transmission owner.    

​In an Order on Rehearing in Docket No. EL22-34, FERC continued to find that the Ohio Office of Consumer Council (OCC) demonstrated that the Ohio Power and AEP Ohio Transmission (AEP) rates were unjust and unreasonable since FERC specifically granted them an RTO Adder under section 219, and their continued participation in a Transmission Organization is not voluntary and the RTO Adder should be removed from their rates.  By contrast, OCC did not meet its burden to show that Duke and ATSI rates charged to Ohio customers were unjust and unreasonable as FERC had not specifically granted them an RTO Adder under section 219 and their rates, inclusive of any RTO Adder, were instead parts of comprehensive settlements.   While OCC is correct that an applicant may make a section 205 filing in order to recover an RTO Adder in its rates, it does not follow that the Commission, in approving comprehensive settlement packages, specifically authorized RTO Adders in the section 205 proceedings that resulted in ATSI and Duke’s rates.  Rather, in ATSI’s and Duke’s proceedings, even if the statements in the settlements indicated that the parties agreed to include an RTO Adder, FERC only approved comprehensive settlement packages without specifically approving the RTO Adder under section 219.  FERC does not know the precise trade-offs and concessions made by the parties to those proceedings.  Even if the settlements included an amount reflecting an RTO Adder, that does not explain how that RTO Adder came to be included in the settlement agreements and what trade-offs led to that outcome.  It is FERC’s position not to revisit individual elements in a settlement unless it is shown that they make the overall rate unjust and unreasonable.    
FERC found in the Rehearing Order that it had not err, as stated by AEP, by declining to address preemption arguments and whether the voluntariness requirement is consistent with the plain text of section 219.   FERC previously addressed those issues in the RTO Adder Order and in the Dayton Orders. 
 
In summary, FERC has eliminated the RTO Adder for Dayton Power and Light, Duke and ATSI for their Ohio transmission services. 
Commissioner Danly continues to dissent as the Federal Power Act does not limit incentives to those utilities that voluntarily join a transmission organization, though he did concur with the decision not to reduce the rates of ATSI and Duke.      

On November 30, 2022, in Docket No. ER23-523, the Midcontinent Independent System Operator, Inc. (MISO), on behalf of the MISO Transmission Owners (MISO TO),[1] submitted proposed revisions to Schedule 2, Reactive Supply and Voltage Control from Generation or Other Sources Service of its Open Access Transmission, Energy and Operating Reserve Markets Tariff (Tariff).  The MISO TOs proposed to eliminate all charges under Schedule 2 for the provision of reactive power within the standard power factor range (Reactive Service) from MISO TOs’ own and affiliated generation resources.[2]  Based on the Commission’s “comparability standard,” MISO TOs stated that their proposal also terminates the obligation under Schedule 2 to pay unaffiliated generation resources in MISO for reactive power within the standard power factor range.  FERC accepted MISO TOs’ proposed Schedule 2 revisions, effective December 1, 2022.  This means that the $220 million being paid in MISO to generators for the provision of reactive power ends December 1, 2022.  

Many comments were filed in this docket, particularly from generators opposing the elimination of reactive power compensation.  Notwithstanding, FERC found that the revisions are just and reasonable and not unduly discriminatory or preferential.  As FERC articulated in Order No. 2003, “the Interconnection Customer should not be compensated for reactive power when operating its Generating Facility within the established power factor range, since it is only meeting its obligation.”  In Order No. 2003-A, FERC clarified, however, that “if the Transmission Provider pays its own or its affiliated generators for reactive power within the established range, it must also pay the Interconnection Customer.”  Consistent with Order No. 2003 and 2003-A, where a transmission provider does not separately compensate its own or affiliated generators for reactive power service within the standard power factor range, it is not required to separately compensate non-affiliated generators for reactive power service within the standard power factor range.  Comparability entitles a generator to compensation for providing reactive power within the standard power factor range “if, and only if, the [t]ransmission [p]rovider pays its own or affiliated generators for reactive power within the [standard power factor range].”  FERC found that MISO TOs’ proposed Schedule 2 revisions to eliminate compensation for its own and affiliated generation resources and unaffiliated generation resources and the associated charges to transmission customers is permitted under, and consistent with, Order Nos. 2003 and 2003-A.  Additionally, FERC stated that Order Nos. 2003 and 2003-A do not mandate that once a transmission provider compensates its own or affiliated generators, it may never discontinue such compensation and must, as a result, always compensate unaffiliated generators.  Rather, FERC precedent allows transmission providers to eliminate compensation for reactive power within the standard power factor range for all generators, regardless of whether the generator is owned by or otherwise affiliated with a transmission owner or is independent.  FERC found protests that challenge these well-established policies to be collateral attacks on these earlier determinations.

Commissioner Danly dissented, stating that, notwithstanding the increased rates and the administrative burden of the present compensation approach, FERC cannot simply accept the MISO TOs’ proposal unless they meet their section 205 burden that the proposed rate—in this case, the elimination of reactive power compensation—is just and reasonable based on substantial evidence in the record.  He went on to state that the MISO TOs did not offer any evidence of the effects of eliminating the $220 million annual reactive power revenue requirement from the MISO tariff, and what is clear on the record is that separate reactive power compensation has been available in MISO for several years, and parties have taken this into account in their financings, bilateral contracting, power purchase agreements, and other arrangements.
​
Commissioner Clements stated in a concurring statement that she encourages stakeholders in MISO to consider more effective alternatives to cost-based reactive power compensation as services should be appropriately compensated for the benefits they provide, and reactive power plays an important reliability function.  She remains open to the possibilities of other reactive power compensation options, such as market solutions or compensation models that are based on the performance of the generators in providing reactive power when called upon, or that incentivize reactive power generation to be located where additional reactive supply is most needed from a reliability perspective.


[1] MISO TOs include:  Ameren Services Company, as agent for Union Electric Company, Ameren Illinois Company, and Ameren Transmission Company of Illinois; Arkansas Electric Cooperative Corporation; City Water, Light & Power (Springfield, IL); Cooperative Energy; Dairyland Power Cooperative; East Texas Electric Cooperative; Entergy Arkansas, LLC; Entergy Louisiana, LLC; Entergy Mississippi, LLC; Entergy Texas, Inc.; Great River Energy; Indianapolis Power & Light Company; Lafayette Utilities System; MidAmerican Energy Company; Minnesota Power (and its subsidiary Superior Water, L&P); Missouri River Energy Services; Montana-Dakota Utilities Co.; Northern States Power Company, a Minnesota corporation, and Northern States Power Company, a Wisconsin corporation, subsidiaries of Xcel Energy Inc.; Northwestern Wisconsin Electric Company; Otter Tail Power Company; Prairie Power, Inc.; Southern Indiana Gas & Electric Company; and Southern Minnesota Municipal Power Agency.

[2] The phrase “standard power factor range” refers to the power factor range required for interconnection and set forth in the interconnecting generator’s generator interconnection agreement (GIA).  MISO’s pro forma GIA prescribes a power factor range of 0.95 leading to 0.95 lagging.  This range is also sometimes referred to as the “deadband.” 

On February 24, 2022, the Office of the Ohio Consumers’ Counsel (OCC) filed a complaint (Complaint) against American Electric Power Service Corporation (AEPSC), American Transmission Systems, Inc. (ATSI), and Duke Energy Ohio (Duke) (together, Ohio TO) alleging that they are ineligible for a 50-basis point adder to the authorized return on equity (ROE) for participation in a Transmission Organization (RTO Adder).  This filing occurred many months after a FERC Order finding that The Dayton Power and Light Company did not qualify for an RTO Adder as under Ohio law participation in a transmission organization was not voluntary but required. 
  
FERC found that the Office of the Ohio Consumer Counsel (OCC) has shown that the rates for Ohio Power and AEP Ohio Transmission (AEP companies) are unjust and unreasonable because the Commission specifically granted them an RTO Adder under section 219 and that their continued participation in a Transmission Organization is mandatory in Ohio.  FERC also found that OCC has not met its burden of showing the rates for Duke and ATSI in Ohio are unjust and unreasonable as the Commission did not specifically grant them an RTO Adder under section 219, and their rates were instead the products of comprehensive settlements.  FERC ordered AEP to make a compliance filing, within 30 days of the date of this order and to remove the RTO Adder from their rates effective February 24, 2022.   Commissioner Danly dissented from the order, stating that the Federal Power Act does not limit incentives to only those utilities that “voluntarily” join a transmission organization and that FERC improperly added this non-statutory requirement in Order No. 679 and had no authority to do so then or now.  In his concurring statement, Commissioner Christie refers to the RTO Adder as “FERC candy” and states that in April 2021, he voted that the RTO Adder would be in effect for a transmission for three years then disappear.  The rulemaking considering transmission incentives, including the RTO Adder, is ongoing at FERC. 

​In Docket No. EL22-31, FERC denied on rehearing the Northern Maine Independent System Administrator’s request for reciprocal elimination of Through and Out Rates between it and ISO-NE.  Though FERC requires elimination of seams, including rate pancaking, within an RTO, such policy is to encourage, not require, reciprocal waivers of access charges between RTOs if such waivers can be accomplished in a manner that is reasonable in terms of cost recovery, cost shifting, efficiency, and discrimination.  Furthermore, where a particular RTO application proposes to rely on an “effective scope” in lieu of a larger geographical control area to satisfy Order No. 2000’s scope requirement, the Commission requires the applicant to show that the integration of the RTO’s markets with those of its neighbors would serve as the functional equivalent of a larger RTO.    ISO-NE’s RTO application was one that relied on an “effective scope” to satisfy the Commission’s scope and regional configuration requirement.  However, NMISA misinterpreted FERC’s inter-RTO rate pancaking policy as a mandate and misinterpreted the condition placed on ISO-NE’s RTO status due to its reliance on an “effective scope” to meet Order No. 2000’s scope requirement.  In granting ISO-NE RTO status, the Commission conditioned its approval upon ISO-NE reducing seams with NYISO specifically.  While the parties that proposed the formation of ISO-NE as an RTO also committed to attempt to reduce seams more broadly, mentioning other neighboring control areas, FERC did not condition ISO-NE’s RTO status on that further commitment.  Furthermore, the fact that the parties that formed ISO-NE made that further commitment does not equate to a condition on ISO-NE’s RTO status, nor does it transform the Commission’s policy to only require seams management agreements when an RTO proposal relies on an “effective scope” to satisfy Order No. 2000’s scope requirement into a universal requirement for seams management agreements.  FERC found that the relationship between NMISA and ISO-NE is not the same as that between the NYISO and ISO-NE.  NMISA has not sought or been granted RTO status as defined in Order No. 2000.  Thus, the rate pancaking policy, by its express terms, does not encompass NMISA because it only encourages reciprocal waiver of access charges between RTOs.  In reaching its decision to deny NMISA’s request, FERC considered whether NMISA was similarly situated with NYISO, and found that it was not.  This finding was based on the following factors:  1) NMISA has not negotiated a comprehensive seams management agreement with ISO-NE like NYISO did, 2) NMISA is not directly and substantially interconnected with ISO-NE like NYISO is, and 3) NMISA does not operate organized energy and ancillary service markets like ISO-NE’s like NYISO does.  The Commission pointed out that “[t]he principal purpose of the comprehensive seams management agreement between ISO-NE and NYISO is to address the high degree of interaction between their similar organized markets.”  A review of NMISA’s tariff document shows that NMISA’s function related to energy and ancillary services is primarily to purchase such energy and ancillary services from New Brunswick (under a specific New Brunswick tariff) or from third-party sellers (under bilaterally negotiated contracts) on behalf of the Competitive Electricity Providers (CEP) that serve retail load in the NMISA area of Maine.  Finally, the fact that NMISA and ISO-NE are electrically remote from each other (i.e., are not directly interconnected) means that the need for information sharing on such matters as real-time transmission congestion is markedly reduced between NMISA and ISO-NE compared to ISO-NE and NYISO.  

​In Docket No. ER22-1395, Public Service of New Mexico (PNM) filed two, late-filed, non-conforming, long-term firm point-to-point transmission service agreements (TSAs) with PacifiCorp and Tri-State Generation & Transmission Association, Inc. (Tri-State) under PNM’s Open Access Transmission Tariff (Tariff), with service commencing on December 1, 2005, and January 1, 2008, respectively.  PNM stated that it discovered the non-conforming TSAs in the process of performing a comprehensive review of its TSAs and internal processes for identifying and filing jurisdictional agreements with the Commission.  PNM noted that it was filing a report of the late-filed agreements to the Commission’s Office of Enforcement.  On the same date, in Docket No. ER22-1396-000, PNM filed 13 non-conforming, long-term, firm, point-to-point TSAs with several customers, entered into on various dates from July 1, 2005, to June 1, 2019.
 
FERC’s initial orders in these two cases (PNM I and PNM II) directed PNM to refund the time-value of monies actually collected for the time period during which the rates were charged without Commission authorization.  The orders directed PNM to make time-value refunds within 30 days for the TSAs, and to file a refund report within 30 days thereafter, and make a showing in the refund report, to the extent that time-value refunds would result in a loss.  On June 16, 2022, PNM requested rehearing, arguing that the time-value refunds, which it claimed would require it to pay its customers more than $7 million as a result of PNM I and in excess of $28 million as a result of PNM II, are unlawful, substantial and punitive.
 
On rehearing, FERC continued to find that refunds are required for PNM I.  FERC stated that its policy and precedent requiring refunds for late-filed agreements is well settled.  FERC stated that time-value refunds serve two purposes, in connection with the Commission’s statutory obligations:  (1) to protect customers, including against unduly preferential treatment, and (2) to incentivize public utilities to comply with the filing requirements of FPA section 205.
 
As for PNM II, FERC continued to find that PNM was under an obligation to file the 13 TSAs.  However, they clarified in the order on rehearing that, even though PNM was required to file the TSAs, based upon the circumstances in the case, FERC relieved PNM of its obligation to provide time-value refunds with respect to the 13 TSAs.   Section 35.1(g) of the Commission’s regulations requires that …”[a]ny individually executed service agreement for transmission, cost-based power sales, or other generally applicable services that deviates in any material respect from the applicable form of service agreement contained in the public utility’s tariff and all unexecuted agreements under which service will commence at the request of the customer, are subject to the filing requirements of this part.”  Here, as PNM’s 13 TSAs deviate from the standard language of its pro forma TSA, the TSAs are necessarily non-conforming.  In Order No. 2001, the Commission stated that “if an agreement does not precisely match the applicable standard form of service agreement . . . it is necessarily nonconforming and must be filed individually for Commission approval.”  Notwithstanding, FERC relieved PNM of its financial obligations as PNM had been maintaining a log detailing when it waived the deposit requirement of contracts (the issue with the 13 TSAs).  FERC stated that while the requirement to maintain a log arguably provides an alternative means for Commission oversight of PNM’s exercise of discretion under that Tariff provision, FERC concludes that the requirement, in and of itself, did not relieve PNM of its filing obligations under section 205 of the FPA given that the agreements are, as discussed above, nonconforming.  Nonetheless, as PNM maintained a log to record waiver of the applicant deposit and that log was available for the Commission to review, there may have been confusion as to whether the agreements also needed to be filed to ensure Commission oversight.  

​This case involves the base ROE for transmission owners in MISO.  A group of customers thought the base ROE provided by FERC was too generous and they asked FERC in 2013 and in 2015 in Section 206 proceedings to reduce that aspect of MISO’s rates. FERC did. In the process, FERC completely overhauled its approach to setting an appropriate ROE. Both the customers and transmission owners challenged several aspects of the FERC proceedings as unlawful or arbitrary and capricious. The Court agrees with the customers that FERC’s development of the base ROE methodology was arbitrary and capricious, so the Court vacated FERC’s base ROE orders and remanded for further proceedings.
 
The customers challenge FERC’s new base ROE methodology on five grounds. First, they argue that FERC should not have altered its previous approach to balancing long-term and short-term growth rates in the discounted-cash-flow model (Model 1). Second, they challenge three aspects of FERC’s approach to the capital-asset model (Model 2). Third, they argue that FERC’s creation of presumptively just and reasonable ranges at step one of the Section 206 analysis was arbitrary and capricious. Fourth, they argue that FERC should have set the new Return based on the median of the zone of reasonableness rather than the midpoint. And fifth, they challenge FERC’s decision to resuscitate the risk-premium model (Model 4) in its second rehearing order shortly after interring the model in its first rehearing order.  The Court found the first four of those arguments unpersuasive, but it agreed with the customers’ final argument. FERC failed to offer a reasoned explanation for its decision to reintroduce the risk-premium model (Model 4) after initially, and forcefully, rejecting it.  Because FERC adopted that significant portion of its model in an arbitrary and capricious fashion, the new base ROE produced by that model cannot stand. The Court therefore vacated FERC’s MISO base ROE orders to reopen the proceedings.