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.  

PJM:
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. 

1. Regional Facilities are transmission enhancements that: (a) are AC facilities that operate at or above 500 kV; (b) are double-circuit AC facilities that operate at or above 345 kV; (c) are AC or DC shunt reactive resources connected to (a) or (b); or (d) are DC facilities that meet other predefined criteria. 
2. Necessary Lower Voltage Facilities are lower voltage facilities that must be constructed or reinforced to support new Regional Facilities.
3. Lower Voltage Facilities are transmission enhancements that (a) are not Regional Facilities; and (b) are not Necessary 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.
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MISO:
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.  

Dear Colleague,
 
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.
 
Sincerely,
 
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 10.32%; 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.  

​On October 16, 2018, FERC issued an Order in the New England Transmission Owners ROE complaints (NETO Order) 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.  There are several other ongoing proceedings involving base ROE disputes.  On November 15, FERC provided guidance regarding the effect of the NETO Order on these pending proceedings (five proceedings involving System Energy Resources, Inc., Entergy Services, Inc., Public Service Company of Oklahoma, Southwestern Electric Power Company, AEP, Oklahoma Transmission Company, AEP Southwestern Transmission Company, Oklahoma Gas & Electric Company, Southwestern Electric Power Company, Alabama Power Company, Georgia Power Company, Gulf Power Company, Mississippi Power Company and Southern Company Services, Inc. – MISO complaints addressed in separate order and blog) that have been set for hearing and settlement judge procedures.  FERC stated that it expects the participants in these five proceedings to address the NETO Order’s proposed new ROE methodology.  This includes presenting evidence concerning the merits of the proposed methodology and whether and how to apply the proposed new methodology to the facts of their respective proceedings.  FERC made it clear that its new base ROE methodology is a proposal and not yet final policy. 
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.  

On November 15, 2018, FERC issued a Notice of Proposed Rulemaking (NOPR), a policy statement, and several orders implementing individual rate revisions and reductions to reflect the impact of Tax Reform in transmission formula rates. The NOPR (RM19-5-000) proposes to require each transmission provider with transmission rates under an Open Access Transmission Tariff , a transmission owner tariff or a rate schedule to revise those rates to account for changes caused by the Tax Cuts and Jobs Act. These proposed reforms are designed to address the tax law’s effects on the Accumulated Deferred Income Taxes (ADIT) reflected in their transmission rates. Under these reforms, all public utilities with transmission formula rates would: 
·      include mechanisms to deduct any excess ADIT from or add any deficient ADIT to their rate bases;
·      include mechanisms in those rates that would raise or lower their income tax allowances by any amortized excess or deficient ADIT; and
·      incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT.
All public utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. Comments are due 30 days from when the NOPR is published in the Federal Register.  Here is the link to the NOPR: https://www.ferc.gov/whats-new/comm-meet/2018/111518/E-1.pdf?csrt=13550044115908092740.
FERC also issued a policy statement (PL19-2-000) which provides accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities, natural gas pipelines and oil pipelines. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017.  Here is the link to the Policy Statement: https://www.ferc.gov/whats-new/comm-meet/2018/111518/E-1.pdf?csrt=13550044115908092740.
FERC also approved an accounting request from the Edison Electric Institute (AC18-59-000) related to recording a reclassification of any stranded tax effects from Tax Reform. Lastly, FERC acted on 46 of the Federal Power Act section 206 show-cause investigations initiated in March, in which the Commission directed certain public utilities whose transmission tariffs specifically reference tax rates of 35 percent to reduce their tax rates to 21 percent or show why they did not need to do so.
Dumais Consulting welcomes the opportunity to help entities with comments to FERC on the NOPR and in complying with the eventual requirements both for accounting and electric transmission in formula rates. Please contact Dumais Consulting at www.DumaisConsulting.com.   

​Chairman Neil Chatterjee announced yesterday at the FERC Open Meeting that FERC will launch a review of electric transmission base ROE and incentives. He said that given the passage of time and the changing electric industry, that it is time for FERC to review existing policies to make sure that they are achieving the legislative mandate in the Energy Policy Act of 1995 which added Section 219 to the Federal Power Act). He did say that any changes made would have effect prospectively and not impact any existing cases. The timing and format of this review is under discussion. Commissioners LaFleur and Glick support this effort, as they have said recently that such a review is needed. Commissioner LaFleur suggested the review include how incentives work in the competitive transmission environment under Order 1000 as well as the RTO and transco incentives. Commissioner Glick stated FERC should focus on other actions that it should incent, such as new technologies that improve the existing transmission network. Given the recent FERC decision on a new approach to determining base ROEs, I expect the focus of this review to be on transmission incentives. 
Section 219 requires that FERC establish incentive-based (including performance-based) rate treatments for transmission investments that benefit consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion. The incentives are to (1) promote reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all transmission facilities; (2) provide a return on equity that attracts new investment in transmission facilities (including related transmission technologies); (3) encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities; and (4) allow recovery of all prudently incurred costs necessary to comply with mandatory reliability standards issued pursuant to section 215 and all prudently incurred costs related to transmission infrastructure development pursuant to section 216. Congress directed FERC to provide transmission owners an incentive joining an RTO. 

On February 13, 2018, in Docket ER18-463, FERC denied a request by Ameren to implement a 100-basis point ROE adder/transmission rate incentive for the Illinois Rivers and Mark Twain components of the Grand Rivers Project in MISO.  In March, Ameren requested rehearing of the FERC order.  Previously, Ameren had received risk reducing incentives for the two projects, including 100% construction work in progress, abandoned plant, a hypothetical capital structure, and the authority to assign those incentives to affiliated entities.  Ameren further requested the 100 basis point ROE adder, stating that the risk-reducing incentives already granted by the Commission did not fully address the risks and challenges of the two projects.  FERC denied the ROE adder, finding that, due to the late stage of development, including the substantial completion of the Illinois Rivers Project, Ameren had failed to demonstrate that the remaining risks and challenges associated with the projects warranted the requested ROE adder. 
In its request for rehearing, Ameren argues that the Commission erred by:  (1) denying the ROE adder for the Illinois Rivers Project on the basis of its construction progress; (2) failing to follow the 2012 Policy Statement on eligibility for the ROE adder; (3) denying the ROE adder for the Mark Twain Project on grounds that applied only to the Illinois Rivers Project; (4) failing to address the application in its entirety when the record supported granting the ROE adder for the Mark Twain Project standing alone; (5) giving weight to resolution of certain risks faced by the Mark Twain Project during the pendency of the application, and ignoring other remaining risks;  (6) concluding the Mark Twain Project’s risks were addressed by the abandonment incentive; and (7) not awarding, in the alternative, a 50 basis point ROE adder for either or both of the projects.  On rehearing, FERC denied the ROE adder for the Illinois River Project but granted a 50 basis point adder for the risks and challenges of the Mark Twain Project. 

Denying the ROE adder for the Illinois Rivers Project based on its construction progressIn the February 2018 Order, FERC explicitly stated that a project being nearly complete does not preclude it from receiving incentives.  However, FERC went on to explain that a project that is further along in construction and thus closer to completion faces fewer remaining risks and challenges, and FERC found that to be the case for the Illinois River Project.  FERC’s position is that an applicant may not seek incentives for a project that is already complete, while a project that is not yet complete is eligible for incentives.  In a case involving Pepco, FERC granted a ROE adder based on the risks and challenges for a project that was nearly complete.  FERC stated in the Ameren Order that they no longer will grant a ROE incentive based on the risks and challenges of a nearly complete project.  FERC plans to consider how close a project is to completion when evaluating the risks and challenges of the project – with less risk typically attendant to projects that are further along in the construction process.  With the Illinois River Project, FERC said that Ameren failed to meet the nexus test given the limited remaining risks and challenges it faced.  Specifically, even at the time of its December 2017 application, the Illinois Rivers Project was approximately 90 percent complete, with four of its nine line segments energized, including two of three river crossings, and with all 10 substations in service.  In addition, four of the five remaining line segments were in the advanced stages of construction at the time of application and are now complete.  While Ameren argued that the Illinois Rivers Project still faced legal uncertainty and landowner opposition, FERC did not view these risks as enough to warrant the ROE adder.    

Failing to follow the 2012 Policy Statement on eligibility for the ROE adder:In the 2012 Policy Statement, FERC stated that it expects an applicant seeking to obtain an ROE incentive based on a project’s risks and challenges to (1) identify the specific risks and challenges to the project that are not either already accounted for in the applicant’s base ROE or addressed through risk-reducing incentives; (2) demonstrate that the applicant is taking appropriate steps and using appropriate mechanisms to minimize its risk during project development; (3) demonstrate that alternatives to the project have been, or will be, considered in either a relevant transmission planning process or another appropriate forum; and (4) explain whether the applicant is committed to limiting the application of the ROE adder based on risks and challenges to a cost estimate.  As to the Illinois Rivers Project, FERC said Ameren failed to identify specific risks and challenges warranting the ROE adder, given that the Project is substantially complete.  While construction progress is not explicitly mentioned in the 2012 Policy Statement, FERC stated that it is not precluded from considering that factor as part of its analysis.  In Order No. 679-A, FERC clarified that the nexus test is met when an applicant demonstrates that the total package of incentives requested is “tailored to address the demonstrable risks or challenges faced by the applicant.”  FERC therefore

Denying the ROE adder for the Mark Twain Project on grounds that applied only to the Illinois Rivers Project; failing to address the application in its entirety when the record supported granting the ROE adder for the Mark Twain Project standing alone; giving weight to resolution of certain risks faced by the Mark Twain Project during the pendency of the application, and ignoring other remaining risks;  and concluding the Mark Twain Project’s risks were addressed by the abandonment incentive:  On rehearing, Ameren argued that substantial completion of the Illinois Rivers Project does not justify denying the ROE adder for the Mark Twain Project and that the record supports granting a ROE adder for the Mark Twain Project standing alone.  Specifically, Ameren states that the        Mark Twain Project’s permitting risks are significant, and that the identified risks are not addressed by the abandonment incentive.  FERC agreed with Ameren that the Mark Twain Project should be evaluated on its own merits and that it is not substantially complete – at the time of the application, construction had not begun.  FERC acknowledged that the Project 1) will relieve chronic and severe congestion that has had demonstrated cost impacts to customers, 2) is expected to produce production cost savings, net of the capital and operating costs of the projects, in the amount of $495.5 million in Missouri alone and approximately $2 billion MISO-wide, and 3) will unlock location constrained generation resources that previously had limited or no access to the markets.  FERC agreed that Ameren satisfied the first showing set forth in the 2012 Policy Statement.  FERC also found that Ameren satisfied the other three showings set forth in the 2012 Policy Statement -  1) Ameren is taking appropriate steps and using appropriate mechanisms to minimize risk during development of the Mark Twain Project (seeking and obtaining risk-reducing incentives and committing to use best practices in project management and procurement); 2) the Mark Twain Project was reviewed and approved as part of the MISO Transmission Expansion Plan 2011 portfolio of MVPs, such that alternatives to the project have been considered in a relevant transmission planning process; and 3) Ameren committed to limiting the application of the ROE Incentive to a cost estimate.

​Not awarding a 50 basis point ROE adder for either or both projects:FERC found that a 50 basis point adder, rather than a 100 basis point adder, is appropriate for the Mark Twain Project.  To support this finding, FERC relied upon two decisions related to Next Era NY:  1) a settlement that FERC approved which provided a 50 basis point ROE incentive for the AC Project (FERC approved a similar settlement for New York Transco for this project which also provided a 50 basis points risk and challenge ROE adder) and 2) the NY Empire Project in which FERC granted a 50 basis point ROE incentive.  FERC found that Mark Twain Project unlocks location constrained generation and provides congestion relief in a range comparable to that of these projects.  FERC ended its order by stating that the Ameren case is only the third instance in which the Commission has granted a ROE incentive based on a project’s risks and challenges since the 2012 Policy Statement and that it will continue to scrutinize each incentives application filed in the future.