This a summary of briefs filed in the return on equity cases at FERC involving the New England Transmission Owners. This now reflects all briefs.
Currently there are four pending complaints against the New England Transmission Owner’s (NETOs) ROE that go back to 2011. Each complaint has been fully litigated before an Administrative Law Judge (ALJ) with only the first complaint resulting in a FERC Commission decision (Opinion 531). The D.C. Circuit of Appeals vacated the Commission’s determinations in its order on the First Complaint (Opinion No. 531). In the meantime, the NETOs are continuing to collect their 10.57% base ROE from Opinion 531, although the Commission has indicated that it will exercise its “broad remedial authority” to correct its legal error to make whatever ROE it sets on remand effective as of the date of that Order.
On October 16, 2018, FERC issued an order in these complaint cases. In its Order, FERC set forth its methodology for addressing ROE complaints while considering the remand from the DC Court. In its proposal, FERC gives equal weight to the results of the four financial models in the record in the NETO cases, instead of primarily relying on the DCF model. In relying on a broader range of record evidence to estimate the NETOs’ cost of equity, FERC states that this will ensure that the selected ROE is based on substantial evidence and bring its methodology into closer alignment with how investors make investment decisions.
To determine whether an existing ROE remains just and reasonable (i.e., the first prong of the FPA section 206 analysis), FERC proposes (1) relying on the three financial models that produce zones of reasonableness—the DCF, CAPM, and Expected Earnings models—to establish a composite zone of reasonableness; and (2) relying on that composite zone of reasonableness as an evidentiary tool to identify a range of presumptively just and reasonable ROEs for utilities with a similar risk profile to the targeted utility. Under this approach, FERC intends to dismiss an ROE complaint if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile—unless that presumption is sufficiently rebutted.
Where the existing ROE has been shown to be unjust and unreasonable and therefore, requiring that FERC move to the second prong of the FPA section 206 analysis, FERC proposes to rely on all four financial models in the record—i.e., the three listed above, plus the Expected Earnings model—to produce four separate cost of equity estimates. FERC proposes to give them equal weight by averaging the four estimates to produce the just and reasonable ROE. For each of the DCF, CAPM, and Expected Earnings models, FERC proposes to use the central tendency of the respective zones of reasonableness as the cost of equity estimate for average risk utilities. FERC would then average those three midpoint/median figures with the sole numerical figure produced by the Risk Premium model to determine the ROE of average risk utilities. FERC would use the midpoint/medians of the resulting lower and upper halves of the zone of reasonableness to determine ROEs for below or above average risk utilities, respectively. Because its current policy is to cap a utility’s total ROE (the base ROE plus incentive ROE adders) at the top of the zone of reasonableness, FERC proposes to use the composite zone of reasonableness produced by the DCF, CAPM, and Expected Earnings to establish the cap on a utility’s total ROE.
The October 16 Order evaluated the justness and reasonableness of existing ROE of the NETOs by dividing a “composite zone of reasonableness” bounded by the average of the highest values obtained in the DCF, CAPM and Expected Earnings analysis, and the average of the three lowest values obtained in those analyses, into quartiles. The Order compares the pre-complaint NETO ROE of 11.14% to a “middle quartile” extending from 37.5% (three-eighths) to 62.5% (five-eighths) of a range from 7.51% to 13.08%, or from 9.6% to 10.99%. Since the NETOs’ Opinion No. 489 ROE of 11.14% exceeds 10.99%, FERC would find it unjust and unreasonable, and reduce it to 10.41%. FERC would also set the total ROE cap at 13.08%.
NETOs support the overall approach proposed by FERC in the October 2018 Order and recommend limited changes to ensure that it is statutorily and procedurally sound and consistent with the D.C. Circuit’s opinion in Emera Maine. The NETOs request that the Commission adopt the following results for these proceedings:
Case Prior ROE Presumptive Range ZOR New ROR
I 11.14% 9.60%-10.99% 7.51%-13.08% 10.41%
II 10.41% 9.85%-11.21% Dismiss - N/A N/A
III 10.41% 9.62%-11.10% Dismiss - N/A N/A
IV 10.41% 9.42%-10.88% Dismiss - N/A N/A
With some limited modifications, FERC’s approach satisfies the two steps of FPA Section 206 and the two holdings of the Court’s Emera Maine decision. First, it accords utilities the “statutory protection” that the Court mandated by ensuring that the Commission will not exercise its FPA Section 206 authority unless it satisfies the “condition precedent” of showing that the existing rate is outside “a broad range of potentially lawful ROEs.” Second, it provides the rational connection between the “record evidence” that undermined the reliability of the DCF analysis and the Commission’s “placement of the base ROE.” In developing a new framework that addresses the Court’s directives, FERC also achieves the “careful balance that attracts sufficient transmission investment but doesn’t impose undue burdens on consumers.”
The NETOs request the following clarifications:
Trial Staff Brief:
Recommends the following:
Complaint Base ROE With Expected Earnings ROE Cap With Expected Earnings
I 9.29% 9.57% 10.82% 11.72%
II 9.26% 9.68% 10.13% 11.62%
III 9.14% 9.58% 11.06% 12.02%
IV 8.45% 9.28% 10.46% 11.63%
Eastern Massachusetts Consumer-Owned entities (EMCOs) state that the DCF remains a sound and reliable method to determine the market cost of equity. FERC has not used other ROE methodologies to same degree as DCF, so other methodologies lack maturity in application by FERC. FERC must exercise extreme caution when employing CAPM and Risk Premium. FERC should not use Expected Earnings as it is based upon accounting data and not reflective of the market cost of equity. FERC’s proposed Expected Earnings analysis is impervious to the market cost of equity capital and heavily anchors ROE results in past regulatory decisions. The proposed averaging of extreme ends of ranges of implied costs of equity exaggerates the skew that results from reliance on the midpoint, as opposed to the median. The results of the NETOs’ non-DCF analyses are substantially overstated in ways that the limited adjustments undertaken in developing the October 16 Order do not address. Failure to deploy a predictable and statistically effective screen for high-end outliers means that the resulting ranges continue to be skewed toward higher than reasonable results.
Recommend that FERC:
Consumer Aligned Parties (CAPS) state that FERC’s proposal to determine a zone of presumptively just and reasonable ROEs that would be used to determine if the existing ROE is just and reasonable is: 1) inconsistent with the Federal Power Act’s consumer protection purpose; 2) creates an asymmetry between Section 205 and 206 cases in that a TO can request a higher ROE if its calculations demonstrate one higher than the existing ROE – on the contrary, in a Section 206 case, the complainant would have to show that the calculated ROE is below the presumptive range; 3) the DC Court did not contemplate, let alone require, a presumption that an above-cost ROE remains just and reasonable unless it exceeds the cost-based level by more than one-eighth of the composite range; 4) the specifics of the proposed presumptive range are arbitrary - the composite range is arbitrary, and the non-DCF methods used in identifying the composite range are unreasonable, if applied as the Order does; and 5) the presumption range departs without justification from precedent specific to New England transmission ROEs in Opinion 489 where FERC required refunds for any NETO which had an ROE different than the new, determined ROE.
CAPS disagree with FERC that the outcome of the prior complaint being deemed the “existing” rate for purposes of the next complaint. CAPs state that the existing ROE for purposes of the second, third, and fourth complaints must be the ROE that is charged or collected by the NETOs—that is, the allowed ROE that was either (a) actually charged when a Section 206 complaint is filed, or (b) determined and fixed by a FERC order making it effective at such time. FERC’s approach here ignores the extended timeline associated with the complaints in these proceedings, where the period between filing of the complaint and Commission action has well exceeded the fifteen-month refund protection afforded by Section 206 and the existing rate will not always be identical to the outcome of the prior Complaint.
CAPs recommend the following changes:
Start End Recommendation Alternative
10/1/2011 12/26/2012 8.91% 9.64%
12/27/2012 12/31/2012 8.79% 9.64%
1/1/2013 3/27/2014 8.79% 9.79%
3/28/2014 7/30/2014 11.14% 11.14%
7/31/2014 10/15/2014 8.64% 9.64%
10/16/2014 10/30/2015 8.64% 9.64%
10/31/2015 4/28/2016 8.91% 9.64%
4/29/2016 9/29/2016 8.33% 9.19%
9/30/2016 7/28/2017 8.64% 9.64%
7/29/2017 9/29/2018 8.91% 9.64%
9/30/2018 continuing 8.33% 9.19%
AEP and EEI Comments:
Both entities request that FERC not decide how to determine the central tendency (midpoint versus median) for a single transmission owner in the NETO proceeding which involves several New England transmission owners.
Southern California Edison Comments:
Suggests that the issue of central tendency for a single-filing utility rate be left for a single utility ROE case where it can be briefed more thoroughly (same point as AEP and EEI) and that FERC consider modifying its proxy group selection criteria to ensure that a small proxy group does not negatively impact ROEs by allowing individual transmission owners who have small proxy groups to propose alternative methods for determining an appropriate proxy group. The practice of setting the low-end threshold 100 basis points above the utility bond yield does not contemplate that the spread between utility bond yields and the cost of utility equity can change over time, and thus the 100-basis point
spread may be too low.
Louisiana Public Service Commission Comments:
Requests late-intervention as they are concerned that they will not have the ability to influence FERC’s direction on ROE in other proceedings involving transmission owners doing business in Louisiana and therefore request that ability here.
 Each of these three methodologies relies on a proxy group to determine a zone of reasonableness, and thus the top and bottom of the zone of reasonableness produced by each methodology can be averaged to determine a single composite zone of reasonableness. After determining the composite zone of reasonableness, FERC will then calculate the lower, middle and upper ranges of that composite zone. The presumptively just and reasonable ROEs for below-average, average, and above-average risk utilities will then be the quartile of the respective zone.
 FERC Trial Staff concludes in Complaint I that the existing 11.14% ROE is unjust and unreasonable and therefore FERC needs to determine the just and reasonable ROE, and they recommend 9.29%. They do not reach such conclusions in the other complaints. They simply provide the information needed for FERC to determine if the existing ROE is within the presumptive just and reasonable range and provide a new ROE if FERC determines that the existing ROE is unjust and unreasonable. Table B provided herein contains Staff’s recommendations if FERC were to reset the ROE and ROE Cap in each complaint case.
In late 2018, Next Era’s affiliate. NEET Midwest, won a competitive solicitation in MISO for the so-called Hartburg-Sabine Project, a $114.8 million Market Efficiency Project identified through MISO’s 2017 comprehensive transmission planning process to relieve congestion in East Texas. In its Selection Report, MISO determined that NEET Midwest’s proposal “offers an outstanding combination of low cost and high value, with best-in class cost and design, best-in-class project implementation plans, and top-tier plans for operations and maintenance,” and will “convey substantial benefits to ratepayers over time.” As highlighted in the Selection Report, NEET Midwest’s “multiple categories of cost caps and cost containment measures increase cost certainty and convey substantial benefits to ratepayers over time.” Here are the cost containment measures that NEET Midwest included in their proposal:
In addition, in Docket ER16- 2717, NEET requested from FERC and received authorization for 1) a Formula Rate for its transmission investments in MISO that is incorporated into the MISO Tariff, 2) a 50 basis point return on equity (“ROE”) adder for Independent System Operator participation (“ISO Participation Adder”); 3) a regulatory asset for NEET Midwest’s prudently incurred pre-commercial and formation costs for later recovery, with carrying charges (“Regulatory Asset Incentive”); and 4) a hypothetical capital structure of 60% equity and 40% debt, to remain in effect until the first transmission project is placed in service (“Hypothetical Capital Structure Incentive”). Any incentive that FERC granted would be subservient to the terms of NEET Midwest’s Proposal for the Hartburg/Sabine Project described above.
On January 4, 2019, NEET Midwest requested the abandonment incentive for this project. This request is pending before FERC in ER19-775.
Republic Transmission, which is owned by LSP Power and Hoosier Energy Rural Electric Cooperative, filed a formula rate at FERC in ER 19-605. Republic Transmission was selected in a MISO competitive process to build a new 345 kV transmission line providing market efficiency benefits, to be constructed between the existing Duff substation in Indiana and the existing Coleman substation in Kentucky (the “Project”). The Project has an expected in-service date of June 2020.
The formula rate has some innovative approaches in order to incorporate the results of the competitive process. The formula rate includes:
On December 19, 2018, SPP made a filing for recovery by Southwestern Electric Power Company (an AEP company) of costs related to the cancellation of two transmission projects after they were approved by the SPP Board of Directors and included in the SPP Transmission Expansion Plan. In 2014, SPP had designated AEP to construct these two projects. Then, as part of SPP’s 2018 Integrated Transmission Planning Near-Term Assessment, SPP determined that the projects were no longer required. On August 15, 2018, SPP formally notified AEP that it was withdrawing the Notification to Construct previously issued and directed AEP to stop any further work on the Projects, tabulate costs associated with the projects, and provide the information to SPP. Soon afterwards, AEP notified SPP that all activities associated with the development of the projects had ceased and that the costs incurred in the development of the projects, as of September 4, 2018, were $414,465.
In SPP, the cost of Network Upgrades that are not completed through no fault of the Transmission Owner (TO) selected with construction of the upgrades is handled as follows: If a proposed Network Upgrade was accepted and approved by the Transmission Provider (TP - SPP), the TP shall develop a mechanism to recover such costs and distribute such revenue on a case by case basis. Such recovery and distribution mechanism shall be filed with FERC. The TO that incurred the costs shall be reimbursed for those costs by the TP. These costs shall include but are not limited to: the costs associated with attempting to obtain all necessary approvals for the project, study costs, and any construction costs.
Specifically, SPP and AEP requested, in accordance with Section VIII of Attachment J of the SPP OATT, commencing March 1, 2019, the AEP Annual Transmission Revenue Requirement (ATRR) would include $414,465, which consists of the costs associated with the canceled projects (Line – Chapel Hill REC – Welsh Reserve 138 kV Ckt 1 (Network Upgrade 50697) project and Line – Welsh Reserve - Wilkes 138 kV Ckt 1 (Network Upgrade 11423)). This amount shall be recovered over a twelve-month period in equal monthly installments. SPP and AEP shall make a joint informational filing notifying the Commission of the final total amount that AEP has recovered, including the costs incurred associated with the canceled projects, plus all interest recovered. If any property related to the lines is sold or otherwise disposed, the revenues associated with such sale or disposition shall be credited against the ATRR.
Transmission project cost allocation is set forth in Attachment J of the Tariff. According to Attachment J, the costs associated with Base Plan Upgrades are allocated on either a regional basis, a zonal basis, or both. Base Plan Upgrade cost allocation depends on the cost allocation methodology in effect at the time that the upgrade was approved for construction by the SPP Board of Directors. Since the Notice to Construct for the projects were issued in 2014, the costs incurred by AEP will be allocated pursuant to SPP’s “Highway/Byway” methodology – 67% allocated solely to the AEP Zone 18 and 33% allocated regionally.
FERC Addresses IRS Required treatment of accumulated deferred income taxes in electric transmission rates
In an order issued June 21, 2018, FERC instituted a section 206 proceedings to examine the methodology utilized by Ameren Illinois, Ameren Transmission of Illinois, and Northern States Power Company, for calculating Accumulated Deferred Income Tax (ADIT) balances in their projected test year or annual true-up calculations for their electric transmission formula rates. In a June 2018 Order, FERC explained that in light of the IRS April 2017 Private Letter Ruling, FERC undertook a review of Commission-jurisdictional transmission formula rates and identified Ameren, NSP Companies, and other transmission owners who currently use the two-step averaging methodology to calculate the ADIT component of rate base in their projected test year calculations or annual true-up calculations for their transmission formula rates. The two-step approach involves projecting ADIT balances using the prescribed IRS proration approach (Step 1) and then averaging the beginning and ending projected ADIT amounts from Step 1 (Step 2). FERC concluded that if the IRS’s proration methodology is applied to calculate ADIT balances in forward-looking formula rates, then the additional averaging step (Step 2) is not needed need to comply with the Consistency Rule (using same methodology to project tax expenses, depreciation expenses, ADIT and rate base). Thus, the two-step averaging methodology is not necessary to comply with the IRS Normalization Rules and results in understating ADIT balances and overstating rate base and revenue requirements. Several transmission owners, in addition to Ameren and Northern States (Public Service Company of Colorado, Southwestern Public Service Company, ALLETE, Montana-Dakota Utilities Co., Northern Indiana Public Service Company, Otter Tail Power Company, Southern Indiana Gas & Electric Company, International Transmission Company, ITC Midwest, Michigan Electric Transmission Company, American Transmission Company, TransCanyon DCR, Virginia Electric and Power Company, GridLiance and Southern California Edison) filed changes which FERC approved), or were ordered to file changes, to their transmission formula rates to eliminate the second step (averaging of the prorated balances).
For the orders, please click on the link below:
On November 27, 2018 in Docket No. ER18-2510, FERC approved an Abandonment Incentive requested by First Energy for an electric transmission project in PJM for which they are partially responsible to build and won. The Abandonment Incentive provides for 100% recovery of prudently-incurred abandonment costs if the project is abandoned or cancelled for reasons beyond the transmission developer’s control. FERC also confirmed that First Energy is eligible to seek recovery of 50 percent of prudently incurred project costs expended prior to a Commission order granting the Abandonment Incentive.
First Energy sought the same Abandonment Incentive previously approved for Transource, BGE, and PECO for the project – other entities responsible to build and own portions of the project. Specifically, First Energy requested the Abandonment Incentive to recover 100 percent of their prudently incurred costs, including plant costs, real estate procurement costs (including any losses incurred on the future sale of real estate), pre-commercial development costs, and all related costs, if the project is abandoned or cancelled for reasons beyond their control. First Energy stated that that it faces several risks in developing and constructing the project that are beyond its control, including permitting risks in two jurisdictions (Pennsylvania and Maryland), the risk that PJM may cancel the project due to changed system needs or economics, and completion risks arising from other transmission owners having development and construction responsibility for different parts of the project.
FERC has found that transmission projects approved as baseline upgrades and included in PJM’s Regional Transmission Expansion Plan (RTEP) are entitled to the rebuttable presumption, as established under Order No. 679, if the facilities will either ensure reliability or reduce the cost of delivered power by reducing transmission congestion. The project under consideration here received approval as a baseline project through the RTEP process. In this case, FERC found that there was a nexus between the incentive sought and the investment made and that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant….” as First Energy demonstrated that the project faces substantial risks and challenges because it will cross several jurisdictions, require multiple layers of governmental approvals, is an interdependent part of a single integrated project, and that the larger project previously was found to face substantial risks and challenges. Prudence determinations would be made based upon a separate filing pursuant to FPA section 205 if First Energy seeks to recover any abandoned plant costs at which time First Energy would be required to demonstrate that the abandonment or cancellation of the project was beyond its control.
On November 27, 2018 in Docket ER18-2350, FERC accepted, subject to refund for revisions related to a remand, PJM’s proposed cost allocation for 60 new transmission projects (reliability projects). Reliability projects include Regional Facilities, Necessary Lower Voltage Facilities, and Lower Voltage Facilities.
PJM utilizes a hybrid cost allocation method for Regional Facilities and Necessary Lower Voltage Facilities - 50 percent of the costs are allocated on a load-ratio share basis and the other 50 percent are allocated based on the solution-based distribution factor (DFAX) method. PJM allocates the costs of Lower Voltage Facilities using the solution-based DFAX method. Notwithstanding, reliability projects that are included in the Regional Transmission Expansion Plan (RTEP) solely to address local planning criteria are allocated to the zone of the individual transmission owner. PJM proposed that 1) the costs of 27 transmission enhancements that operate as Lower Voltage Facilities be allocated pursuant to the solution-based DFAX method; 2) the costs of 15 transmission enhancements with investments of less than five million dollars be allocated to the Zone where the enhancement is located; 3) the costs of four transmission enhancements that address individual transmission owner needs be allocated to the Zone of the individual transmission owner; 4) the costs of nine transmission enhancements that operate at or below 200 kV be allocated to the Zone in which the enhancement is located; and 5) the costs of five transmission enhancements needed to address spare parts, replacement equipment and circuit breakers be allocated to the Zone in which the enhancement is located. Dominion and Old Dominion Electric Cooperative (ODEC) protested the proposed assignment to the Dominion Zone of 100 percent of the cost responsibility for three projects as the three projects are high-voltage projects which were included in the RTEP and it is arbitrary, unjust, and unreasonable for the Commission to allocate 100 percent of the costs of these projects to the Dominion Zone. Dominion and ODEC also state that the allocation of the costs of high-voltage transmission facilities to the zone of the transmission owner has been under review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court), and on August 3, 2018, the D.C. Circuit Court found that the Commission acted arbitrarily and capriciously by accepting the cost allocation methodology for Regional Facilities addressing local planning criteria and remanded the orders to the Commission for review. Dominion and ODEC do not allege that PJM incorrectly applied its Tariff, but instead challenge the cost assignment provisions of the Tariff itself. As a result, FERC accepted the proposed cost allocations but made its order subject to refund subject to revisions related to the remand.
On November 27, 2018 in Docket ER18-2514, FERC approved a request by MISO and the MISO Transmission Owners to change the cost allocation for Targeted Market Efficiency Projects (TMEP). TMEPs are interregional transmission projects that address historical congestion along the MISO-PJM seam and are low cost, high value transmission projects intended to reduce historical congestion on known Reciprocal Coordinated Flowgates. TMEPs benefit customers and improve coordination between MISO and PJM. For an upgrade to qualify as a TMEP, the upgrade must: (1) address historical congestion on a known Reciprocal Coordinated Flowgate; (2) have an estimated in-service date by the third summer peak season from the year in which the project is approved; (3) have an estimated installed cost of less than $20 million; and (4) have been recommended by the Joint RTO Planning Committee approved by the boards of MISO and PJM. Currently, MISO’s share of TMEP costs is allocated to MISO Transmission Pricing Zones in proportion to each zone’s share of the relative positive congestion contribution benefits from the TMEP. The formula used to calculate the benefits of a TMEP identifies the nodal congestion contribution for each load node as the product of: (1) the marginal value of relieving a particular constraint (i.e., the Shadow Price) at the Reciprocal Coordinated Flowgate, (2) a measure of the load’s contribution to congestion in the day-ahead and real-time markets at the load node to the Reciprocal Coordinated Flowgate (i.e., the shift factor), and (3) the amount of load served at that node. MISO and the MISO TOs propose three changes to the cost allocation for TMEPs: (1) incorporate generator nodes in the determination of the congestion contribution, rather than considering only load nodes; (2) aggregate the load node and generator node congestion contributions; and (3) discontinue applying the formula to all five-minute dispatches in the real-time market, so that the formula would apply only to the hours in the day-ahead market in which the Reciprocal Coordinated Flowgate experienced congestion. MISO and the MISO TOs state that the proposed changes 1) would improve the alignment of costs and benefits and improve transparency in calculating the cost allocation; 2) would create a more accurate match of benefits and costs; 3) would ensure that there is no involuntary allocation of costs to non-beneficiaries; and 4) would better define the beneficiaries of avoided congestion and allocate the TMEP upgrade costs more accurately than adding generator sensitivities alone. Additionally, removing the use of the real-time data has minimal effect on the cost allocation for TMEPs and simplifies the overall calculation effort. All filers supported the proposed changes to the TMEPs, and FERC accordingly approved these changes.
I will be participating on a panel for the upcoming ABACLE webinar Electric Transmission FERC Ratemaking: Formula Rates, Protocols, Return on Equity and Incentives on 7-Dec-2018 and thought you and your colleagues might be interested in attending. The program will focus on the standards applied by the Federal Energy Regulatory Commission (FERC) in determining whether proposed or existing electric transmission rates are just and reasonable and current considerations FERC applies in transmission ratemaking proposals. A Q&A session will follow.
For more information, or if you’d like to attend, please visit https://www.americanbar.org/events-cle/mtg/web/347648599.html?&sc_cid=CE1812FRC-FMP to register. As a colleague, you can save 15% using discount code FACMARK at checkout.
Please feel free to spread the word about this program to anyone you think may benefit from it, including sharing the discount code.
Dr. Paul Dumais
Follow me on LinkedIn at: https://www.linkedin.com/in/dr-paul-dumais-b868089/
Below is a summary of a recent FERC Notice of Proposed Rulemaking and Policy Statement. In these documents, FERC puts forth how it proposes entities under its jurisdiction to account for and reflect in rates the impacts on accumulated deferred income taxes from the reduction in federal income taxes from the Tax Reform Act. Dumais Consulting (www.DumaisConsulting.com) welcomes the opportunity to help your company navigate through for ratemaking and accounting these income tax items. Comments to FERC are due on the Rulemaking in mid-January 2019.
On November 15, 2018. FERC issued 1) a Notice of Proposed Rulemaking (NOPR) regarding Transmission Rate Changes to Address Accumulated Deferred Income Taxes and 2) and a Policy Statement on Accounting and Ratemaking Treatment of Accumulated Deferred Income Taxes and Treatment Following the Sale or Retirement of an Asset. FERC is proposing to require that public utilities deduct excess accumulated deferred income taxes (ADIT) from or add deficient ADIT to their rate base and adjust their income tax allowances by amortized excess or deficient ADIT. FERC is also proposing to require all public utilities with transmission formula rates to incorporate a new permanent worksheet that will annually track ADIT information. Lastly, FERC is proposing to require all public utilities with transmission stated rates to determine the amount of excess and deferred income tax caused by the Tax Cuts and Jobs Act’s (Act) reduction to the federal corporate income tax rate and return or recover this amount to or from customers.
In the NOPR, FERC identifies two components that are necessary to maintain accurate cost of service following a change in income tax rates, such as that caused by the Act: (1) preservation of rate base neutrality through the removal of excess ADIT from or addition of deficient ADIT to rate base; and (2) the return of excess ADIT to or recovery of deficient ADIT from customers. FERC is not proposing to prescribe a specific adjustment mechanism which applies to all transmission owners (TOs) with transmission formula rates as prescribing a one-size-fits-all approach is not appropriate. FERC instead proposes to allow TOs to propose any necessary changes to their formula rates on an individual basis. Regarding the period over which the amortization of excess or deficient ADIT must occur, FERC proposes that TOs follow the guidance provided in the Act, which requires returning excess protected ADIT no more rapidly than over the life of the underlying asset using the Average Rate Assumption Method, or, where a TO’s books and underlying records do not contain the vintage account data necessary, it must use an alternative method. The Act does not specify what method TOs must use for excess or deficient unprotected ADIT, which will be determined on the specific facts and circumstances.
Regarding transmission stated rates, FERC proposes maintaining Order No. 144’s requirement that TOs reflect any adjustments made to their ADIT balances as a result of the Act (and any future tax changes) in their next rate case. However, to increase the likelihood that those customers who contributed to the related ADIT accounts receive the benefit of the Act, FERC proposes to require TOs with stated rates to (1) determine any excess or deficient ADIT caused by the Act and (2) return or recover this amount to or from customers. FERC proposes that TOs calculate this excess or deficient ADIT using the ADIT approved in their last rate cases, which allows preservation of the costs of service as accepted in their last rate case. FERC plans to evaluate each proposal on an individual basis. Since FERC’s existing regulations already require all the information necessary to support the changes from the Act, FERC is not requiring any additional worksheets.
In the Policy Statement (PS), FERC clarifies that for both accounting and ratemaking purposes, public utilities and natural gas companies should record the amortization of the excess or deficient ADIT in Account 254 (Other Regulatory Liabilities) or Account 182.3 (Other Regulatory Assets) and record the offsetting entries to Account 410.1 (Provision for Deferred Income Taxes, Utility Operating Income) or Account 411.1 (Provision for Deferred Income Taxes – Credit, Utility Operating Income), as required by the Uniform System of Accounts (USofA). FERC further clarifies that for accounting purposes, oil pipelines should adjust their ADIT balances to reflect the change in federal income tax rates with offsetting entries to the appropriate income statement account, as required by the USofA. Accordingly, oil pipeline companies will not record excess or deficient ADIT for accounting purposes but should provide additional disclosures in the Notes that accompany their FERC Form No. 6, Annual Report of Oil Pipeline Companies (Form No. 6). FERC reiterates that public utilities and natural gas pipelines must continue to follow the accounting guidance issued by the Chief Accountant in Docket No. AI93-5-000 with respect to changes in tax law or rates. To ensure transparency in the accounting adjustments to the deferred tax accounts, entities should provide additional disclosures in their 2018 FERC annual financial filing within the Notes to the Financial Statements.
With respect to ratemaking, for a public utility or natural gas pipeline that continues to have an income tax allowance, any excess or deficient ADIT associated with an asset must continue to be amortized in rates even after the sale or retirement of that asset. This excess or deficient ADIT will continue to be refunded to or recovered from customers based on the schedule that was initially established as the balances of excess and deficient ADIT recorded in Account 254 and Account 182.3, respectively, continue to exist as regulatory liabilities and assets after an asset sale, in cases for which the excess and
deficient ADIT do not transfer to the purchaser of the plant asset. Thus, in order to provide transparency regarding the accounting and rate treatment of amounts removed from the ADIT accounts, public utilities and natural gas pipelines should disclose in their FERC annual financial filings within the Notes to the Financial Statements: (1) the FERC accounts affected; (2) how any ADIT accounts were remeasured in the determination of the excess or deficient ADIT amounts in Accounts 182.3 and 254; (3) the related amounts associated with the reversal and elimination of ADIT balances in those accounts; (4) the amount of excess and deficient ADIT that is protected and unprotected; (5) the accounts to which the excess or deficient ADIT will be amortized; and (6) the amortization period of the excess and deficient ADIT to be returned or recovered through rates for both protected and unprotected ADIT. Disclosures should also summarize how excess and deficient will be included in rates by rate jurisdiction. As for oil pipelines, as discussed above, ADIT balances will be reduced immediately by the full amount of the excess or deficient tax reserve in line with the USofA for oil pipelines outlined in General Instruction 1-12.76 b, Ratemaking Guidance.
The Commission has previously found that the sale or retirement of an asset with an ADIT balance is usually deemed a taxable event under IRS rules, and, as such, the ADIT balance is extinguished as the deferred taxes then become payable to the appropriate government authorities, and there is no longer an ADIT balance to “return” to customers. However, we believe that excess or deficient ADIT associated with post-December 31, 2017, asset dispositions and retirements should be treated differently for ratemaking purposes. For these assets, there are two associated balances: (1) the ADIT balance based on the 21 percent tax rate that will be owed to the IRS and (2) deficient ADIT or excess ADIT balances resulting from the reduced tax liability that will not be payable to the IRS upon the sale or retirement of the asset. While the ADIT balance that needs to be settled with the IRS would be extinguished following a sale, the deficient ADIT or excess ADIT balances is more reflective of a regulatory liability or asset, and no longer reflects deferred taxes that are still to be settled with the IRS and need not be extinguished. Additionally, FERC noted that the rationale for continuing to amortize deficient ADIT or excess ADIT balances in rates upon sales or retirements of assets is substantively like the rationale for amortizing excess ADIT in rates for assets that have not been sold or retired. The difference is that for a sale or retirement, ADIT based on a 21 percent tax rate will be settled with the IRS immediately, while for an asset that is not sold or retired, the ADIT will be settled with the IRS over the remaining life of the asset as it depreciates. In other words, the difference between the ADIT for assets that are sold or retired and ADIT for assets that are not sold or retired is the timing of when companies will settle the 21 percent of ADIT with the IRS. In both scenarios, there is excess ADIT based on the 14 percent previously collected from the customers that will no longer be payable to the IRS. Current IRS regulations speak specifically to the normalization requirements for sales and retirements as a result of the Tax Reform Act of 1986. These regulations permit the amortization of protected excess and/or deficient ADIT even if the underlying asset associated with the ADIT has been sold or retired. That is, the selling jurisdictional entity can continue to amortize excess ADIT in rates after the sale without violating the IRS’ normalization requirements. The only limitation imposed by the IRS is that the timing of the amortization must be like protected excess or deficient ADIT for which the underlying asset has not been sold or retired. Consistent with the above discussion, oil pipelines should continue maintaining excess or deficient ADIT within the appropriate ADIT accounts for ratemaking purposes. When jurisdictional assets are retired or sold the oil pipeline should continue to amortize any excess or deficient amounts associated with those assets as part of the process of determining an income tax allowance within the rate making process or seek prior Commission approval to do otherwise.
There are two outstanding complaint proceedings involving the return on equity (ROE) of Midcontinent Independent System Operator, Inc.’s (MISO) transmission-owning members (MISO TOs) (Docket Nos. EL14-12-003 and EL15-45-000). FERC set these proceedings for hearing after it issued Opinion No. 531 in October 2014, concerning the ROE of the New England Transmission Owners (NETOS). In the order setting the first MISO proceeding for hearing, FERC stated that it expected to be guided by Opinion 531. On October 16, 2018, FERC issued an Order in the NETO cases in which it proposed a new methodology for analyzing the base return on equity (ROE) component of rates under section 206 of the Federal Power Act (FPA) and directed the participants to the applicable proceedings to submit briefs regarding the proposed new methodology. In their November 15th Order in the MISO cases, FERC similarly establish a paper hearing on whether and how this new methodology should apply to the proceedings pending before the Commission involving MISO TOs’ ROE.
In the first complaint filed in 2013 against the MISO TO’s, FERC calculated the just and reasonable ROE using the two-step DCF methodology from Opinion No. 531 and found that the base ROE to be 10.32%. Following the issuance of that Order (Opinion No. 551), numerous parties submitted requests for rehearing, which are currently pending. In the second complaint filed in 2015, the Administrative Law Judge issued the Initial Decision in 2016 in which he adopted a zone of reasonableness of 6.76% to 10.68% and determined that the just and reasonable ROE was 9.70% percent–halfway between the midpoint and the upper bound of the zone of reasonableness. The participants filed briefs on and opposing exception, which are currently pending before the Commission.
In its November 15th Order, FERC performed an illustrative calculation using record evidence from the First MISO Complaint. That calculation indicates that 1) the range of presumptively just and reasonable ROEs for MISO TOs is 9.55% to 10.95% percent; (2) MISO TOs’ preexisting ROE of 12.38% is therefore unjust and unreasonable; (3) the just and reasonable ROE is 10.28%; and (4) the cap on MISO TOs’ total ROE is 13.06%. FERC stated that these findings are merely preliminary and established a paper hearing on whether and how this new methodology should apply to the two MISO TO complaints. FERC concluded by stating that participants are free to present evidence supporting the proposed new methodology or supporting a different or revised new methodology and that the participants should submit separate briefs regarding each of the two complaints. Initial briefs are due in 60 days (mid-January 2019) and responses are due 30 days later (mid-February).
As a reminder, in the NETO Order, FERC directed the parties to submit briefs regarding: (1) a proposed framework for determining whether an existing ROE is unjust and unreasonable under the first prong of FPA section 206 and (2) a revised methodology for determining just and reasonable ROEs. FERC proposed to establish a composite zone of reasonableness, giving equal weight to the discounted cash flow (DCF) model, capital asset pricing model (CAPM), and expected earnings model. FERC proposed that, in order to find an existing ROE unjust and unreasonable under the first prong of section 206, the ROE must be outside a range of presumptively just and reasonable ROEs for a utility of its risk profile. For average risk single utilities, that range would be the quartile of the zone of reasonableness centered on the midpoint/median of the zone of reasonableness. For below or above average risk utilities, that range would be the quartile of the zone of reasonableness centered on the central tendency of the lower or upper half of the zone of reasonableness, respectively. FERC proposed to determine a replacement ROE under the second prong of FPA section 206 using the above three models, plus the risk premium model. For average risk utilities, the Commission proposed to determine the midpoint/medians of each zone of reasonableness produced by the DCF, CAPM, and expected earnings models and average those ROEs with the risk premium model ROE, giving equal weight to each of the four figures. The Commission proposed to use the midpoint/medians of the lower and upper halves of the zones of reasonableness to determine ROEs for below and above average risk utilities, respectively, and average those ROEs with the risk premium model ROE.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates.