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Note 3 - Rate and Regulatory Matters | 12 Months Ended
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Dec. 31, 2019
Notes to Financial Statements |
Public Utilities Disclosure [Text Block] | 3. Rate and Regulatory Matters Below are descriptions of OTP’s major capital expenditure projects that have had, or are expected to have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific general rate proceedings and descriptions of rate riders and a summary of rate rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the FERC, impacting OTP’s revenues in 2019, 2018 and 2017. Major Capital Expenditure Projects Merricourt Wind Energy Center (Merricourt)—On November 16, 2016 OTP entered into an Asset Purchase Agreement (the Purchase Agreement) with EDF Renewable Development, Inc. and certain of its affiliated companies (collectively, EDF) to purchase and assume the development assets and certain specified liabilities associated with Merricourt, a 150-megawatt (MW) wind farm in southeastern North Dakota, for a purchase price of approximately $34.7 million, subject to adjustments for interconnection costs. Also on November 16, 2016, OTP entered into a Turnkey Engineering, Procurement and Construction Services Agreement (the TEPC Agreement) with EDF-RE US Development, LLC (EDF-USD) pursuant to which EDF-USD will develop, design, procure, construct, interconnect, test and commission the wind farm with a targeted completion date in 2020 for consideration of approximately $200.5 million, subject to certain adjustments, payable following the closing of the Purchase Agreement in installments in connection with certain project construction milestones. The agreements contain customary representations, warranties, covenants and indemnities for this type of transaction. On October 26, 2017 the MPUC approved the facility under the Renewable Energy Standard making Merricourt eligible for cost recovery under the Minnesota Renewable Resource Recovery rider, subject to qualifications and reporting obligations. The MPUC’s final written order was issued on January 10, 2018. A final order for an Advance Determination of Prudence (ADP) for Merricourt, subject to qualifications and compliance obligations, and a Certificate of Public Convenience and Necessity were issued by the NDPSC on November 3, 2017. The phase-in rider approved by order of the SDPUC on March 6, 2019 includes recovery of Merricourt costs. The Merricourt generator interconnection agreement with MISO was approved by the FERC in April 2019. In connection with action by the FERC, OTP and EDF-US agreed, in the First Amendment to the Purchase Agreement and the TEPC Agreement dated June 11, 2019, to change the purchase price to $37.7 million and to make a related reallocation of responsibility for interconnection costs and liabilities. On July 16, 2019 OTP closed on the purchase of substantially all of the development assets and assumed certain specified liabilities from EDF related to Merricourt pursuant to the Purchase Agreement, as amended, for a purchase price of approximately $37.7 million, subject to certain adjustments, and issued the notice to EDF-USD to begin construction in August 2019. As of December 31, 2019, OTP had capitalized approximately $81.7 million in project costs and allowance for funds used during construction (AFUDC) associated with Merricourt. OTP expects this project will be completed in October of 2020. Astoria Station—OTP is constructing this 245 MW simple-cycle natural gas-fired combustion turbine generation facility near Astoria, South Dakota as part of its plan to reliably meet customers’ electric needs, replace expiring capacity purchase agreements and prepare for the planned retirement of its Hoot Lake Plant in 2021. A final order granting an ADP for Astoria Station was issued by the NDPSC on November 3, 2017, subject to certain qualifications and compliance obligations. On August 3, 2018 the SDPUC issued an order granting a site permit for Astoria Station. In a September 26, 2018 hearing the NDPSC established a GCR rider for future recovery of costs incurred for Astoria Station. On March 6, 2019 the SDPUC issued an order approving a settlement that allows a phase-in rider which includes recovery of Astoria Station costs. The interconnection agreement for Astoria Station was executed by MISO in December 2018 and accepted by the FERC in January 2019. Site preparation and excavation began in May 2019. As of December 31, 2019, OTP had capitalized approximately $58.7 million in project costs and AFUDC associated with Astoria Station. OTP expects this project will be completed in late 2020 or early 2021. Big Stone South–Ellendale Multi-Value Transmission Project (MVP)—This 345-kiloVolt transmission line, energized on February 6, 2019, extends 162 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., and the parties have equal ownership interest in the transmission line portion of the project. The MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011. MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit from the MVP. OTP capitalized costs of approximately $106 million on this project, including assets that are 100% owned by OTP. General Rates Minnesota—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base is 7.5056% and its allowed rate of return on equity (ROE) is 9.41%. The MPUC’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South–Brookings and Big Stone South–Ellendale MVPs will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers (see discussion under Minnesota Transmission Cost Recovery Rider below), and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from ECR and TCR riders to base rate recovery, which occurred when final rates were implemented on November 1, 2017. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs. OTP accrued interim and rider rate refunds until final rates became effective. The final interim rate refund, including interest, of $9.0 million was applied as a credit to Minnesota customers’ electric bills beginning November 17, 2017. In addition to the interim rate refund, OTP refunded the difference between (1) amounts collected under its Minnesota ECR and TCR riders based on the ROE approved in its most recent rider update and (2) amounts that would have been collected based on the lower 9.41% ROE approved in its 2016 general rate case going back to April 16, 2016, the date interim rates were implemented. The revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were $0.9 million and $1.4 million, respectively. These amounts were refunded to Minnesota customers over a 12-month period beginning in November 2017 through reductions in the Minnesota ECR and TCR rider rates. North Dakota—On November 2, 2017 OTP filed a request with the NDPSC for a rate review and an effective increase in annual revenues from non-fuel base rates of $13.1 million or 8.72%. The requested $13.1 million increase was net of reductions in North Dakota RRA, TCR and ECR rider revenues that would have resulted from a lower allowed ROE and changes in allocation factors in the general rate case. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed ROE of 10.3%. On December 20, 2017 the NDPSC approved OTP’s request for interim rates to increase annual revenue collections by $12.8 million, effective January 1, 2018. In response to the reduction in the federal corporate tax rate under the TCJA, the NDPSC issued an order on February 27, 2018 reducing OTP’s annual revenue requirement for interim rates by $4.5 million to $8.3 million, effective March 1, 2018. On March 23, 2018 OTP made a supplemental filing to its initial request for a rate review, reducing its request for an annual revenue increase from $13.1 million to $7.1 million, a 4.8% annual increase. The $6.0 million decrease included $4.8 million related to tax reform and $1.2 million related to other updates. In a September 26, 2018 hearing the NDPSC approved an overall annual revenue increase of $4.6 million (3.1%) and a ROE of 9.77% on a 52.5% equity capital structure. This compares with OTP’s March 2018 adjusted annual revenue increase request of $7.1 million (4.8%) and a requested ROE of 10.3%. The NDPSC’s approval did not require any rate base adjustments from OTP’s original request and established a GCR rider for future recovery of costs incurred for Astoria Station. The net revenue increase reflects a reduction in income tax recovery requirements related to the TCJA and decreases in rider revenue recovery requirements. Final rates were effective February 1, 2019, with refunds of excess revenues collected under interim rates applied to customers’ April 2019 bills, including $0.8 million for amounts collected reflecting the higher tax rates under interim rates in effect in January and February 2018. South Dakota—On April 20, 2018 OTP filed a request with the SDPUC to increase non-fuel rates in South Dakota by approximately $3.3 million annually, or 10.1%, as the first step in a two-step request. Interim rates were effective October 18, 2018. The second step in the request was an additional 1.7% revenue increase to recover costs for Merricourt when the wind generation facility goes into service. The SDPUC approved a partial settlement on March 1, 2019 on all issues of the rate case except ROE. The partial settlement included approval of a phase-in plan to provide for a return on amounts invested in Astoria Station and Merricourt, which addressed the second step of the request for increased rates in South Dakota. The partial settlement also included a moratorium on filing another general rate case in South Dakota until the new generation projects have been in service for a year. The partial settlement also allowed OTP to retain the impact of lower tax rates related to the TCJA from January 1, 2018 through October 17, 2018 resulting in the reversal of an accrued refund liability and recognition of $1.0 million in revenue in the first quarter of 2019. The SDPUC approved the ROE portion of the rate case on May 14, 2019. Pursuant to the May 30, 2019 order, OTP’s allowed ROE was set at 8.75%, resulting in an annual revenue increase of approximately $2.2 million prior to the approval of a June 28, 2019 stipulation agreement discussed below. Final rates went into effect August 1, 2019. An interim rate refund for the lower ROE going back to October 18, 2018 was applied to South Dakota customers’ October 2019 bills. On July 9, 2019 the SDPUC approved a stipulation agreement entered into by OTP with SDPUC staff for the purpose of correcting a mistake in OTP’s rate base in its 2018 general rate case docket. The revenue requirement stated in the SDPUC’s final order dated May 30, 2019 understated the correct amount of OTP's South Dakota share of electric transmission plant in service by approximately $4.1 million. For South Dakota ratemaking purposes, the understatement resulted in an annual revenue requirement shortfall of approximately $341,000. To address the shortfall, the parties agreed that OTP would file an update to its South Dakota TCR rider. OTP was authorized full recovery of the transmission rate base correction reflected in the TCR rider tracker beginning as of the first date of interim rates, October 18, 2018, with the TCR rider rate update going into effect on October 1, 2019. The stipulation agreement had the effect of increasing the non-fuel annual revenue increase in the general rate case to approximately $2.6 million or 7.7%, which is 69% of the adjusted requested annual revenue increase of approximately $3.7 million or 11.1%. To ensure rates are appropriately set under the stipulation, the parties agreed to establish an earnings sharing mechanism to share with customers any weather-normalized earnings above the authorized ROE of 8.75%. OTP's annual weather-normalized earnings are reported each year by June 1 in its jurisdictional annual report, which will be used to determine the earnings level for purposes of calculating any refund. The earnings sharing mechanism requires that OTP will refund to customers 50% of any weather-normalized revenue that corresponds to the earnings in excess of its authorized ROE, up to a maximum of 9.50% ROE for a particular year. OTP will refund 100% of any earnings above 9.50% each year. In the event a refund is due under this provision, OTP will notify the SDPUC of the refund amount and plan for crediting customers within 30 days of filing its South Dakota jurisdictional annual report. Rate Riders OTP has several rate riders in place in each of its state jurisdictional service areas. These rate riders are designed to recover expenses, costs and returns on rate base investments not currently being recovered in base, or general, rates. Following is a brief description and summary of recent proceedings of riders in place in each state served by OTP followed by tables showing revenues recorded under rate riders in 2019, 2018 and 2017 and a listing of rate rider updates impacting revenues in 2019, 2018 and 2017. Minnesota Minnesota Conservation Improvement Programs (MNCIP)— OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On May 25, 2016 the MPUC adopted changes to the MNCIP financial incentive. The model provides utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. The financial incentive is also limited to 40% of 2017 MNCIP spending, 35% of 2018 spending and 30% of 2019 spending. The new model reduces the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. The Minnesota Department of Commerce (MNDOC) issued a decision on May 20, 2019 to extend all utilities’ 2017-2019 MNCIP plans one year, through 2020, with an incentive based on 30% of spending and 10% of net benefits. Based on results from MNCIP 2019, 2018 and 2017 program years, OTP recognized financial incentives of $2.7 million for 2019, $3.0 million for 2018 and $2.9 million for 2017, of which $2.6 million was recognized in 2017 with $0.3 million that had been reserved for potential future refund recognized in 2019. Transmission Cost Recovery Rider— The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule. In OTP’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the MPUC’s order diverted interstate wholesale revenues that have been approved by the FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment resulted in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because the FERC’s revenue requirements and authorized returns vary from the MPUC revenue requirements and authorized returns for the project investments over the lives of the projects, the impact of this decision can vary over time and be dependent on the differences between the revenue requirements and returns in the two jurisdictions at any given time. On August 18, 2017 OTP filed an appeal of the MPUC general rate case order with the Minnesota Court of Appeals to contest the portion of the order requiring OTP to jurisdictionally allocate costs of the FERC MVP transmission projects in the TCR rider. On June 11, 2018 the Minnesota Court of Appeals reversed the MPUC’s order related to the inclusion of Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVPs and all revenues received from other utilities under MISO’s tariffed rates as a credit in OTP Minnesota TCR revenue requirement calculations. On July 11, 2018 the MPUC filed a petition for review of the MVP decision to the Minnesota Supreme Court, which granted review of the Minnesota Court of Appeals decision. A decision by the Minnesota Supreme Court is expected in the second quarter of 2020. On November 30, 2018 OTP filed its annual update and supplemental filing to the Minnesota TCR rider. In this filing two scenarios were submitted based on whether the Minnesota Supreme Court affirms the original decision by the Minnesota Court of Appeals to exclude the MVP projects from the TCR rider or overturns the Minnesota Court of Appeals decision and includes the two MVP projects in the TCR rider. In addition, on April 1, 2019, the MNDOC filed comments in OTP’s TCR rider docket, opposing OTP’s proposal for TCR rider recovery of these costs. The MPUC is not expected to act on the TCR rider until after the Minnesota Supreme Court has acted and additional briefing has occurred in the docket. The estimated amount credited to Minnesota customers through the TCR rider through December 31, 2019, and subject to recovery if the Minnesota Court of Appeals decision is upheld is approximately $2.6 million. If the Minnesota Court of Appeals decision is upheld, there will be additional briefing in the pending TCR rider docket regarding the recovery of these costs. Environmental Cost Recovery Rider—OTP had an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provided for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In its 2016 general rate case order, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery effective with implementation of final rates in November 2017. Accordingly, in its 2018 annual update filing OTP requested, and the MPUC approved, setting the Minnesota ECR rider rate to zero effective December 1, 2018. Renewable Resource Adjustment—Effective November 1, 2017, with the implementation of final rates in Minnesota, new rates were put into effect for the Minnesota RRA rider to address recovery of federal production tax credits (PTCs) expiring on OTP’s wind farms in 2017 and 2018. On June 21, 2019 OTP filed its annual update to the Minnesota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as recovery of Merricourt. On December 19, 2019 the MPUC approved a revised request which included changes related to Merricourt capitalized costs. Fuel and Purchased Power Costs Recovery—In a December 2017 order, the MPUC adopted a program to implement certain procedural reforms to Minnesota utilities’ automatic fuel adjustment clause (FAC) for fuel and purchased power cost recovery. With this order, the method of accounting for all Minnesota electric utilities changed to a monthly budgeted, forward-looking FAC with annual prudence review and true-up to actual allowed costs. On October 31, 2019 the MPUC approved the forecasted monthly fuel cost rates submitted by OTP for 2020 and the rates became effective on January 1, 2020. This mechanism could result in reductions in Electric segment operating income margins, increase variability in consolidated net income in future periods if costs per kwh vary from forecasted costs per kwh and cause an increase in working capital and short-term borrowings in the event recovery of all or a portion of excess costs is delayed or denied by the MPUC. North Dakota Renewable Resource Adjustment—OTP has a North Dakota RRA which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment. Effective in February 2019 with the implementation of general rates based on the results of OTP’s 2017 general rate case, recovery of renewable resource costs previously being recovered through the North Dakota RRA rider transitioned to recovery in base rates. On December 31, 2019 OTP filed its annual update to the North Dakota RRA requesting approval for recovery of the difference in PTCs in base rates and the actual PTCs generated, as well as a return on Merricourt costs incurred while under construction. This update also included a credit for the remaining unrefunded credit balance in the North Dakota ECR rider tracker on November 30, 2019. Transmission Cost Recovery Rider—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case. Based on the order in the 2017 general rate case, only certain costs remained subject to refund or recovery through this rider: Southwest Power Pool (SPP) costs and MISO Schedule 26 and 26A revenues and expenses and costs related to rider projects still under construction in the test year used in the 2017 general rate case. On December 18, 2019 the NDPSC approved OTP’s annual update to its North Dakota TCR rider. The filing included seven new projects, updated costs associated with existing projects, details about the pending MISO ROE complaint, and details about SPP related expenses. Environmental Cost Recovery Rider—OTP has an ECR rider in North Dakota. The ECR rider provides for a return on investment at the level approved in OTP’s preceding general rate case and recovery of OTP’s North Dakota share of environmental investments and costs approved for recovery under the rider. Prior to its 2017 general rate case reaching a final settlement and final rates going into effect on February 1, 2019, OTP’s North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant Mercury and Air Toxic Standards (MATS) projects were being recovered through the ECR rider. Effective February 1, 2019 these rate base investments are being recovered under general rates and the rider was zeroed out except for an overcollection balance that will be refunded to ratepayers through the North Dakota RRA annual update filed on December 31, 2019. Generation Cost Recovery Rider—On May 15, 2019 the NDPSC approved OTP’s request to establish an initial GCR rider rate for recovery of OTP’s North Dakota jurisdictional share of the revenue requirements on its investment in Astoria Station, effective on bills rendered after July 1, 2019. South Dakota Transmission Cost Recovery Rider—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. OTP has a TCR rider in South Dakota. A supplemental filing to update the rider was made on January 29, 2018 to reflect updated costs and collections and incorporate the impact of the reduction in the federal corporate income tax rate under the TCJA. Effective October 18, 2018, with the implementation of interim rates under South Dakota general rate case proceedings, the TCR rate was decreased as a result of recovery of certain costs being shifted to recovery in interim rates and included for ongoing recoveries in final base rates at the end of the 2018 general rate case. OTP made a supplemental filing for the South Dakota TCR rider on February 1, 2019. On February 15, 2019 the SDPUC approved the supplemental filing and rates effective March 1, 2019. Two new projects were approved for recovery under the rider: The Lake Norden area transmission upgrade project with a recovery date effective January 1, 2019 and the Big Stone South–Ellendale project with a recovery date effective January 1, 2020. On September 17, 2019 the SDPUC approved OTP’s supplemental TCR rider filing update request to address the transmission rate base correction disclosed in the 2018 general rate case docket with updated rates effective October 1, 2019. Environmental Cost Recovery Rider—OTP has an ECR rider in South Dakota. The ECR rider provides for a return on investment at the level approved in OTP’s most recent general rate case and for recovery of OTP’s South Dakota share of environmental investments and costs approved for recovery under the rider. Prior to interim rates going into effect on October 18, 2018 pending a final decision on OTP’s South Dakota general rate increase request, OTP’s South Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects were being recovered through the ECR rider. With the initiation of interim rates, recovery of the costs previously being recovered under the ECR rider was transitioned to recovery under interim rates and the South Dakota ECR rider rate was reset to provide a refund to customers while interim rates were in effect. The ending balance of the South Dakota ECR rider at the conclusion of interim rates was refunded to South Dakota customers along with their October 2019 interim rate refunds. Phase-In Rate Plan Rider—On May 31, 2019 OTP petitioned the SDPUC for approval of its initial rate for the Phase-In Rate Plan Rider as described in OTP’s most recent South Dakota general rate case settlement stipulation and was approved by the SDPUC’s order in that rate case. The petition is OTP’s initial filing for the rider to recover OTP’s South Dakota share of actual and forecasted costs for Astoria Station and Merricourt, and to refund forecasted net benefits associated with additional load growth in the Lake Norden area. On August 21, 2019 the SDPUC approved OTP’s supplemental filing for its South Dakota Phase-In Rate Plan Rider effective September 1, 2019. Rate Rider Updates The following table provides summary information on the status of updates since January 1, 2016 for the rate riders described above:
Rate Rider |  |  | R - Request Date A - Approval Date |  |  |  | Effective Date Requested or Approved |  |  | Annual Revenue ($000s) |  | Rate
Minnesota |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Conservation Improvement Program |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2018 Incentive and Cost Recovery |  |  | A – | December 27, 2019 |  |  |  | January 1, 2020 |  |  | $ | 11,926 |  | $0.00710 | /kwh
2017 Incentive and Cost Recovery |  |  | A – | October 4, 2018 |  |  |  | November 1, 2018 |  |  | $ | 10,283 |  | $0.00600 | /kwh
2016 Incentive and Cost Recovery |  |  | A – | September 15, 2017 |  |  |  | October 1, 2017 |  |  | $ | 9,868 |  | $0.00536 | /kwh
2015 Incentive and Cost Recovery |  |  | A – | July 19, 2016 |  |  |  | October 1, 2016 |  |  | $ | 8,590 |  | $0.00275 | /kwh
Transmission Cost Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2018 Annual Update–Scenario A |  |  | R – | November 30, 2018 |  |  |  | June 1, 2019 |  |  | $ | 6,475 |  | Various
–Scenario B |  |  |  |  |  |  |  |  |  |  | $ | 2,708 |  | Various
2017 Rate Reset |  |  | A – | October 30, 2017 |  |  |  | November 1, 2017 |  |  | $ | (3,311 | ) | Various
2016 Annual Update |  |  | A – | July 5, 2016 |  |  |  | September 1, 2016 |  |  | $ | 4,736 |  | Various
Environmental Cost Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2018 Annual Update |  |  | A – | November 29, 2018 |  |  |  | December 1, 2018 |  |  | $ | - |  | 0% | of base
2017 Rate Reset |  |  | A – | October 30, 2017 |  |  |  | November 1, 2017 |  |  | $ | (1,943 | ) | -0.935% | of base
2016 Annual Update |  |  | A – | July 5, 2016 |  |  |  | September 1, 2016 |  |  | $ | 11,884 |  | 6.927% | of base
Renewable Resource Adjustment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2019 Annual Update – Revised |  |  | A – | December 19, 2019 |  |  |  | January 1, 2020 |  |  | $ | 12,506 |  | $0.00467 | /kwh
2018 Annual Update |  |  | A – | August 29, 2018 |  |  |  | November 1, 2018 |  |  | $ | 5,886 |  | $0.00219 | /kwh
2017 Rate Reset |  |  | A – | October 30, 2017 |  |  |  | November 1, 2017 |  |  | $ | 1,279 |  | $0.00049 | /kwh
North Dakota |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Renewable Resource Adjustment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2020 Annual Update |  |  | R – | December 31, 2019 |  |  |  | April 1, 2020 |  |  | $ | 3,828 |  | 3.744% | of base
2019 Annual Update |  |  | A – | May 1, 2019 |  |  |  | June 1, 2019 |  |  | $ | (235 | ) | -0.224% | of base
2018 Rate Reset for effect of TCJA |  |  | A – | February 27, 2018 |  |  |  | March 1, 2018 |  |  | $ | 9,650 |  | 7.493% | of base
2017 Rate Reset |  |  | A – | December 20, 2017 |  |  |  | January 1, 2018 |  |  | $ | 9,989 |  | 7.756% | of base
2016 Annual Update |  |  | A – | March 15, 2017 |  |  |  | April 1, 2017 |  |  | $ | 9,156 |  | 7.005% | of base
2015 Annual Update |  |  | A – | June 22, 2016 |  |  |  | July 1, 2016 |  |  | $ | 9,262 |  | 7.573% | of base
Transmission Cost Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2019 Annual Update |  |  | A – | December 18, 2019 |  |  |  | January 1, 2020 |  |  | $ | 5,739 |  | Various
2018 Supplemental Update |  |  | A – | December 6, 2018 |  |  |  | February 1, 2019 |  |  | $ | 4,801 |  | Various
2018 Rate Reset for effect of TCJA |  |  | A – | February 27, 2018 |  |  |  | March 1, 2018 |  |  | $ | 7,469 |  | Various
2017 Annual Update |  |  | A – | November 29, 2017 |  |  |  | January 1, 2018 |  |  | $ | 7,959 |  | Various
2016 Annual Update |  |  | A – | December 14, 2016 |  |  |  | January 1, 2017 |  |  | $ | 6,916 |  | Various
Environmental Cost Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2019 Update |  |  | A – | October 22, 2019 |  |  |  | November 1, 2019 |  |  | $ | - |  | 0% | of base
2018 Update |  |  | A – | December 19, 2018 |  |  |  | February 1, 2019 |  |  | $ | (378 | ) | -0.310% | of base
2018 Rate Reset for effect of TCJA |  |  | A – | February 27, 2018 |  |  |  | March 1, 2018 |  |  | $ | 7,718 |  | 5.593% | of base
2017 Rate Reset |  |  | A – | December 20, 2017 |  |  |  | January 1, 2018 |  |  | $ | 8,537 |  | 6.629% | of base
2017 Annual Update |  |  | A – | July 12, 2017 |  |  |  | August 1, 2017 |  |  | $ | 9,917 |  | 7.633% | of base
2016 Annual Update |  |  | A – | June 22, 2016 |  |  |  | July 1, 2016 |  |  | $ | 10,359 |  | 7.904% | of base
Generation Cost Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2019 Initial Request |  |  | A – | May 15, 2019 |  |  |  | July 1, 2019 |  |  | $ | 2,720 |  | 2.547% | of base
South Dakota |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Transmission Cost Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2020 Annual Update |  |  | R – | October 31, 2019 |  |  |  | March 1, 2020 |  |  | $ | 2,407 |  | Various
2019 Rate Reset |  |  | A – | September 17, 2019 |  |  |  | October 1, 2019 |  |  | $ | 2,046 |  | Various
2019 Annual Update |  |  | A – | February 20, 2019 |  |  |  | March 1, 2019 |  |  | $ | 1,638 |  | Various
2018 Interim Rate Reset |  |  | A – | October 18, 2018 |  |  |  | October 18, 2018 |  |  | $ | 1,171 |  | Various
2017 Annual Update |  |  | A – | February 28, 2018 |  |  |  | March 1, 2018 |  |  | $ | 1,779 |  | Various
2016 Annual Update |  |  | A – | February 17, 2017 |  |  |  | March 1, 2017 |  |  | $ | 2,053 |  | Various
2015 Annual Update |  |  | A – | February 12, 2016 |  |  |  | March 1, 2016 |  |  | $ | 1,895 |  | Various
Environmental Cost Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2018 Interim Rate Reset |  |  | A – | October 18, 2018 |  |  |  | October 18, 2018 |  |  | $ | (189 | ) | -$0.00075 | /kwh
2017 Annual Update |  |  | A – | October 13, 2017 |  |  |  | November 1, 2017 |  |  | $ | 2,082 |  | $0.00483 | /kwh
2016 Annual Update |  |  | A – | October 26, 2016 |  |  |  | November 1, 2016 |  |  | $ | 2,238 |  | $0.00536 | /kwh
Phase-In Rate Plan Recovery |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
2019 Initial Request |  |  | A – | August 21, 2019 |  |  |  | September 1, 2019 |  |  | $ | 864 |  | 3.345% | of base
Revenues Recorded under Rate Riders The following table presents revenue recorded by OTP under rate riders in place in Minnesota, North Dakota and South Dakota for the years ended December 31:
Rate Rider (in thousands) |  | 2019 |  |  | 2018 |  |  | 2017 |
Minnesota |  |  |  |  |  |  |  |  |  |  |  |
Conservation Improvement Program Costs and Incentives |  | $ | 8,271 |  |  | $ | 8,127 |  |  | $ | 6,008 |
Renewable Resource Adjustment |  |  | 5,513 |  |  |  | 3,067 |  |  |  | (196 | )
Transmission Cost Recovery |  |  | 2,497 |  |  |  | (2,039 | ) |  |  | 2,973 |
Environmental Cost Recovery |  |  | (1 | ) |  |  | (24 | ) |  |  | 8,148 |
North Dakota |  |  |  |  |  |  |  |  |  |  |  |
Transmission Cost Recovery |  |  | 5,292 |  |  |  | 7,016 |  |  |  | 8,729 |
Generation Cost Recovery |  |  | 878 |  |  |  | - |  |  |  | - |
Environmental Cost Recovery |  |  | 550 |  |  |  | 7,318 |  |  |  | 9,782 |
Renewable Resource Adjustment |  |  | 230 |  |  |  | 8,529 |  |  |  | 7,620 |
South Dakota |  |  |  |  |  |  |  |  |  |  |  |
Transmission Cost Recovery |  |  | 2,165 |  |  |  | 1,664 |  |  |  | 1,843 |
Conservation Improvement Program Costs and Incentives |  |  | 851 |  |  |  | 628 |  |  |  | 598 |
Environmental Cost Recovery |  |  | (29 | ) |  |  | 1,676 |  |  |  | 2,345 |
Phase-In Rate Plan |  |  | (125 | ) |  |  | - |  |  |  | - |
Total |  | $ | 26,092 |  |  | $ | 35,962 |  |  | $ | 47,850 |
TCJA The TCJA, passed in December 2017, reduced the federal corporate income tax rate from 35% to 21%, effective January 1, 2018. At the time of passage, all OTP’s rates had been developed using a 35% tax rate. The MPUC, the NDPSC, the SDPUC and the FERC each initiated dockets or proceedings to begin working with utilities to assess the impact of the lower rates on electric rates, and to develop regulatory strategies to incorporate the tax change into future rates, if warranted. The MPUC required regulated utilities providing service in Minnesota to make filings by February 15, 2018. On August 9, 2018 the MPUC determined the impacts of the TCJA as calculated, including amortization of excess accumulated deferred income taxes, should be refunded and rates should be adjusted going forward to account for the impacts of the TCJA. On December 5, 2018 the MPUC released its final order related to the TCJA docket directing OTP to return to ratepayers, in a one-time refund, the TCJA-related savings accrued prior to the refund effective date. The order also directs OTP to use these savings to reduce customers’ base rates prospectively, allocating the savings to customers in proportion to the size of each customer’s bill, or to each customer class in proportion to the class’s size. New rates reflecting the reduction in revenue requirements related to the TCJA tax rate reduction went into effect June 1, 2019. A one-time refund to Minnesota customers of $11.5 million in excess of amounts billed from January 2018 through May 2019 occurred in August and September 2019. As described above, OTP’s recent general rate cases in North Dakota and South Dakota reflected the impact of the TCJA in interim rates. OTP accrued refund liabilities for the time periods during which revenues were collected under rates set to recover higher levels of federal income taxes than OTP incurred under the lower federal tax rates in the TCJA. FERC Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act of 1935 (Federal Power Act). The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a suspension period, subject to ultimate approval by the FERC. MVPs—MVPs are designed to enable the MISO region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit from the MVP. ROE—On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. Several parties requested rehearing of the September 2016 order. On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50 basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP’s incentive rate filing, OTP’s ROE went to 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016. On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners’ ROE should be 9.7%. Based on the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC-ordered reduction in the MISO Tariff allowed ROE for the first 15-month refund period in its February and June 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO Tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.6 million as of September 30, 2019. On March 1, 2019 the FERC issued a Notice of Inquiry (NOI) seeking comment on whether, and if so how, it should modify its policies concerning the determination of the ROE used in designing jurisdictional rates charged by public utilities. For years, the FERC has utilized a particular two-step, analysis to establish ROEs for utilities and natural gas interstate pipelines. The NOI sought comments on whether it should develop ROEs using a different financial model. The NOI also sought comments, among other things, on the continued use of RTO Adders. On November 21, 2019 the FERC adopted a different two-step ROE model and capital asset pricing model to determine whether a jurisdictional public utility’s rate of ROE is just and reasonable under section 206 of the Federal Power Act. Applying the new methodology in complaints against the MISO transmission owners, the FERC determined that the MISO transmission owners’ current base ROE should be 9.88%. The FERC also stated it will use ranges of presumptively just and reasonable ROEs in its analysis of whether existing ROEs have become unjust and unreasonable. This order also implemented the FERC’s revised methodology in the two complaints against the MISO transmission owners’ base ROE. The order granted rehearing on the first complaint, found the existing 12.38% ROE unjust and unreasonable, and directed the MISO transmission owners to adopt a 9.88% ROE effective September 28, 2016, and to provide refunds. The order also dismissed the second complaint and found that the record in that proceeding did not support a finding that the 9.88% ROE established in the first complaint proceeding had become unjust and unreasonable. As a result of the FERC granting rehearing on the first complaint and finding the existing 12.38% ROE unjust and unreasonable and directing the MISO transmission owners to adopt a 9.88% ROE, OTP increased its refund provision related to the ROE complaints from $1.6 million to $3.0 million as of December 31, 2019. The $3.0 million includes provisions for:
| ● | an additional $0.2 million refund related to the first complaint as a result of reducing the reasonable ROE from 10.32%, established in the FERC’s September 28, 2016 refund order, to the newly established 9.88% ROE,
| ● | a $1.3 million refund for the period from September 28, 2016 through December 31, 2019 related to a reduction in the current ROE from 10.82% to 10.38% based on the newly established 9.88% reasonable ROE for the first complaint period plus the 50-point RTO adder granted by the FERC on January 5, 2015, and
| ● | a $1.5 million refund related to the second complaint period in response to requests for rehearing on the FERC’s decision to dismiss the second complaint based on a potential reduction in the reasonable ROE for that period from 12.38% to 9.88% plus the 50-point RTO adder.
In response to the FERC’s November 21, 2019 order, the MISO Transmission Owners (including OTP) and others filed requests seeking rehearing of the FERC’s November 21, 2019 order, and a group of parties filed with the United States Court of Appeals for the District of Columbia a protective appeal.

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