Regulated Operations	9 Months Ended
Sep. 30, 2021
Regulated Operations [Abstract]
Rate Matters and Regulation	Rate Matters and Regulation Except as set forth below, the circumstances set forth in Note 16 to the financial statements included in the Registrants' 2020 Form 10-K appropriately represent, in all material respects, the current status of the Registrants' regulatory matters. Completed Regulatory Matters APSC Proceedings Arkansas 2020 Formula Rate Plan Filing In October 2020, OG&E filed its third evaluation report under its Formula Rate Plan, and on January 28, 2021, OG&E entered into a non-unanimous settlement agreement with the APSC General Staff and the Office of the Arkansas Attorney General. The only non-signatory to the settlement agreement agreed not to oppose the settlement. The settlement agreement included a revenue increase of $6.7 million, which is the maximum amount statutorily allowed in this filing. Additionally, the settling parties did not object to OG&E's request for a finding that the Arkansas Series II grid modernization projects included in this filing are prudent in cost. On March 9, 2021, the APSC issued a final order approving the non-unanimous settlement agreement, and new rates became effective April 1, 2021. Disconnection Procedures Related to COVID-19 In September 2020, the APSC invited comments from all jurisdictional utilities and any other interested stakeholders on specific questions related to whether a moratorium on service terminations should be lifted and if so, how the resumption of disconnections should occur. The APSC also ordered utilities to submit a detailed "Transitional Plan" outlining how utilities proposed to reinstate routine service disconnection activities and collection of past due amounts once the moratorium was lifted. OG&E submitted its proposed Transitional Plan in October 2020. On February 8, 2021, the APSC announced a target date of May 3, 2021 to lift the moratorium on disconnections and specified certain conditions and requirements that utilities must meet before disconnections may resume. Such requirements include, among other things, immediate communication to customers, notice periods for disconnections and deferred payment arrangements. On March 26, 2021, the APSC confirmed the lifting of the moratorium on disconnections on May 3, 2021 and directed utilities to take specific steps prior to resuming disconnections. OG&E resumed disconnections on May 3, 2021. Arkansas Approval to Construct Out of State Generation On March 3, 2021, OG&E filed an application with the APSC to request approval to construct a 5 MW solar facility in Oklahoma. The APSC issued an order on April 6, 2021, finding OG&E's application in the public interest, conditioned on Arkansas customers being held harmless and not subject to cost recovery associated with the project. OG&E expects the costs associated with constructing this solar facility to be fully recovered in Oklahoma. Integrated Resource Plan OG&E has conducted technical conferences for stakeholder engagement on its draft triennial system-wide IRP and, in October 2021, issued its final 2021 IRP to the APSC. This 2021 IRP identified system-wide capacity needs of 145, 183, 417 and 514 MWs in 2023, 2024, 2025 and 2026, respectively. OCC Proceedings Oklahoma Grid Enhancement Plan In November 2020, the OCC issued a final order approving a Joint Stipulation and Settlement Agreement that allows for interim recovery of OG&E's costs associated with its grid enhancement plan. The approved agreement included the following key terms: (i) cost recovery through a rider mechanism will be limited to projects placed in service in 2020 and 2021, capped at a revenue requirement of $7.0 million annually and only include communication, automation and technology systems projects; (ii) no operation and maintenance expense will be included in the rider mechanism; (iii) the rider mechanism will terminate by the issuance of a final order in OG&E's next general rate review or October 31, 2022, whichever occurs first; (iv) the rider mechanism rate of return will be capped at OG&E's current cost of capital; and (v) all cost recovery is subject to true-up and refund in OG&E's next general rate review. The rider mechanism became effective on February 1, 2021. OG&E reports to the OCC new projects completed each quarter, and the cost recovery factor is adjusted to include those projects after a stakeholder review. OG&E has submitted its report for projects that were placed in service through September 30, 2021. The cost recovery factors that include those projects will become effective on December 1, 2021. Any capital investment falling outside the criteria of the rider mechanism will be included in OG&E's next general rate review for recovery. Integrated Resource Plan OG&E has conducted technical conferences for stakeholder engagement on its draft triennial system-wide IRP and, in October 2021, issued its final 2021 IRP to the OCC. This 2021 IRP identified system-wide capacity needs of 145, 183, 417 and 514 MWs in 2023, 2024, 2025 and 2026, respectively. Pending Regulatory Matters Various proceedings pending before state or federal regulatory agencies are described below. Unless stated otherwise, the Registrants cannot predict when the regulatory agency will act or what action the regulatory agency will take. The Registrants' financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates. FERC Proceedings Order for Sponsored Transmission Upgrades within SPP Under the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff required the SPP to charge for these upgrades beginning in 2008, but the SPP had not been charging its customers for these upgrades due to information system limitations. However, the SPP had informed participants in the market that these charges would be forthcoming. In July 2016, the FERC granted the SPP's request to recover the charges not billed since 2008. The SPP subsequently billed OG&E for these charges and credited OG&E related to transmission upgrades that OG&E had sponsored, which resulted in OG&E being a net receiver of sponsored upgrade credits. The majority of these net credits were refunded to customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E. Several companies that were net payers of Z2 charges sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia Circuit. In July 2018, that court granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and November 2017 rehearing denial, ruled that the SPP violated its tariff to charge for the 2008 through 2015 period in 2016, held that the SPP tariff provision that prohibited those charges could not be waived and ordered the SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, in April 2019, OG&E filed a request for rehearing with the FERC, and in May 2019, OG&E filed a FERC 206 complaint against the SPP, alleging that the SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. OG&E's filing requested that the FERC rule that the SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement. The SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that the SPP should not be held responsible for those payments if refunds are ordered. Further, the SPP has requested the FERC to negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound. In February 2020, the FERC denied OG&E's request for rehearing of its February 2019 order, denying the waiver and ruling that the SPP must seek refunds from project sponsors for Z2 payments for the 2008 through 2015 period and pay them back to transmission owners. The FERC also denied the SPP's request for a stay and for institution of settlement procedures. The FERC stated it would not institute settlement procedures unless parties on both sides of the matter requested them. The FERC did not rule on OG&E's complaint or the complaints of other project sponsors, or consider the SPP's refund plan. The FERC thus has not set any date for payment of refunds. In March 2020, OG&E petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the FERC's order denying the waiver and requiring refunds. The court issued a decision on August 27, 2021, denying review and holding that the SPP was prohibited by the filed rate doctrine from imposing Z2 charges during the 2008 through 2015 historical period. The court further held that the FERC reasonably exercised its remedial authority to order the SPP to refund the retroactive upgrade charge. The court did not direct a time frame or procedures for the SPP to implement refunds. OG&E and the SPP filed a petition for rehearing of the court's decision, which was denied on October 29, 2021. The court will return the matter to the FERC for action in accordance with its opinion on November 5, 2021. If the FERC proceeds to order refunds in full, OG&E estimates it would be required to refund $13.0 million, which is net of amounts paid to other utilities for upgrades and would be subject to interest at the FERC-approved rate. The SPP has stated in filings it made with the FERC while the appeal was pending that there are considerable complexities in implementing the refunds that will have to be resolved before they can be paid. Payment of refunds would shift recovery of these upgrade credits to future periods. Of the $13.0 million, the Registrants would be impacted by $5.0 million in expense that initially benefited the Registrants in 2016, and OG&E customers would incur a net impact of $8.0 million in expense through rider mechanisms or the FERC formula rate. As of September 30, 2021, the Registrants have reserved $13.0 million plus estimated interest for a potential refund. In January 2020, the FERC acted on an SPP proposal to eliminate Attachment Z2 revenue crediting and replace it with a different rate mechanism that would provide project sponsors, such as OG&E, the same level of recovery, and rejected the proposal to the extent it would limit recovery to the amount of the upgrade sponsor's directly assigned upgrade costs with interest. The SPP resubmitted a proposal in April 2020 without this limited recovery, and with the alternative rate mechanism, and the FERC approved it in June 2020, effective July 1, 2020. No party sought rehearing of the order, and it is now final. This order would only prospectively impact OG&E and its recovery of any future upgrade costs that it may incur as a project sponsor subsequent to July 2020. All of the existing projects that are eligible to receive revenue credits under Attachment Z2, which includes the $13.0 million at issue in OG&E's appeal as discussed above, will continue to do so. Incentive Adders for Transmission Rates The FERC issued a NOPR on March 20, 2020, and issued a supplemental NOPR on April 15, 2021, proposing to update its transmission incentives policy. Among other things, the NOPR proposes (i) the current 50-basis point return on equity adder for RTO/ISO participation would be applicable only to transmitting utilities that join an RTO/ISO, and this incentive would only apply for the first three years in which the utility is an RTO/ISO member and (ii) transmitting utilities that have been members of an RTO/ISO for three years or more, such as OG&E, would be required to make a compliance filing to remove the existing return on equity adder from their rates. OG&E is currently evaluating the potential impacts of this proposed rule. Currently, there is no specific deadline for the FERC to take further action, and it is unknown whether the FERC will address the RTO participation adder individually or as part of a larger order on transmission incentives. APSC Proceedings Winter Storm Uri In February 2021, Winter Storm Uri resulted in record winter peak demand for electricity and extremely high natural gas and purchased power prices in OG&E's service territory. On April 1, 2021, OG&E filed with the APSC a Motion for Authority to Establish Special Regulatory Treatment within the Energy Cost Recovery Rider to Defer Extraordinary Fuel Costs Incurred Due to Winter Storm Uri. More specifically, OG&E's motion sought approval to defer, amortize and recover the extraordinary fuel costs over a ten-year period with a carrying charge of OG&E's pre-tax rate of return of 6.60 percent, through a special factor within OG&E's Energy Cost Recovery Rider beginning with the first billing cycle of May 2021. On April 13, 2021, the APSC issued an order allowing OG&E interim recovery at an interest rate equal to the customer deposit interest rate, which is currently 0.8 percent, over a period of ten years beginning with the first billing cycle of May 2021. Recovery is subject to a true-up after the APSC determines the appropriate allocation, length of recovery and carrying charge. On May 4, 2021, OG&E filed testimony further supporting its 10-year amortization period and a carrying charge of OG&E's pre-tax rate of return of 6.60 percent. In April 2021, Arkansas enacted legislation to amend its storm recovery securitization statute to allow for both electric and gas utilities to recover through securitization extraordinary natural gas, fuel and purchased power costs caused by storms. The amended statute authorizes the APSC to issue a financing order for the issuance of securitization bonds upon a finding it is reasonably expected to lower overall costs or mitigate rate impacts as compared with traditional utility financing. Upon the initiation of a securitization application, the APSC has 135 days to issue an order. The requesting utility has two years from the date of the financing order to issue the securitization bonds. The amended statute allows carrying costs at a utility's weighted average cost of capital from the date of when the costs were incurred until the date when bonds are ultimately issued. On May 20, 2021, OG&E filed a motion for suspension of procedural schedule, which the APSC approved, to investigate and evaluate the potential securitization recovery of the Arkansas jurisdictional portion of the Winter Storm Uri costs. OG&E intends to apply for securitization in early 2022 if it is deemed to strike the right balance between protecting the credit strength of OG&E and providing customer savings. As of September 30, 2021, OG&E has deferred $91.0 million to a regulatory asset, as indicated in Note 1. Arkansas 2021 Formula Rate Plan Filing On October 1, 2021, OG&E filed its fourth evaluation report under its Formula Rate Plan, including a request to increase its Arkansas retail revenues by $6.4 million. OG&E also requested extending its Formula Rate Plan Rider by five years. If approved, new rates will be effective April 1, 2022. OCC Proceedings Oklahoma Retail Electric Supplier Certified Territory Act Causes Several rural electric cooperative electricity suppliers have filed complaints with the OCC alleging that OG&E has violated the Oklahoma Retail Electric Supplier Certified Territory Act. OG&E believes it is lawfully serving customers specifically exempted from this act and has presented evidence and testimony to the OCC supporting its position. There have been five complaint cases initiated at the OCC, and the OCC has issued decisions on each of them. The OCC ruled in favor of the electric cooperatives in three of those cases and ruled in favor of OG&E in two of those cases. All five of those cases have been appealed to the Oklahoma Supreme Court, where they have been made companion cases but will be individually briefed and have individual final decisions. If the Oklahoma Supreme Court ultimately were to find that some or all of the customers being served are not exempted from the Oklahoma Retail Electric Supplier Certified Territory Act, OG&E would have to evaluate the recoverability of some plant investments made to serve these customers. The total amount of OG&E's plant investments made to serve the customers in all five cases is approximately $28.0 million, of which $11.7 million applies to the three cases where the OCC ruled in favor of the electric cooperatives. In addition to the evaluation of the recoverability of the investments, OG&E may also be required to reimburse certified territory suppliers for an amount of lost revenue. The amount of such lost revenue would depend on how the OCC calculates the revenue requirement but could range from approximately $26.0 million to $35.4 million for all five cases, of which $2.5 million to $3.9 million would apply to the three cases where the OCC ruled in favor of the electric cooperatives. Winter Storm Uri In February 2021, Winter Storm Uri resulted in record winter peak demand for electricity and extremely high natural gas and purchased power prices in OG&E's service territory. On February 24, 2021, OG&E submitted an application to the OCC outlining a two-step approach for regulatory treatment for the fuel and purchased power costs associated with Winter Storm Uri. The steps included: (i) an intra-year fuel clause increase to be effective April 1, 2021; and (ii) a request for regulatory asset treatment at OG&E's weighted average cost of capital for the remaining fuel and purchased power costs. On March 18, 2021, the OCC approved OG&E's filing to establish a regulatory asset. The approval allowed OG&E to create a regulatory asset for all deferred costs with an initial carrying charge based on the effective cost of the debt financing, until such time where the prudency of this event is evaluated, the amortization period is decided on and a long-term carry cost is established. In April 2021, Oklahoma enacted legislation to allow for the securitization of costs incurred during Winter Storm Uri. The new statute authorizes the OCC to issue a financing order for the issuance of securitization bonds after consideration of certain factors, including but not limited to, mitigated impacts and savings for customers through the use of ratepayer-backed securitization bonds as compared to traditional utility financing. The OCC must issue a financing order within 180 days after receiving all necessary information required by the statute. Under the statute, the Oklahoma Development Finance Authority is responsible for issuing the securitization bonds within two years from the date of the financing order. Carrying costs will be included at a rate and time determined by the OCC and continue until the bonds are issued. On April 26, 2021, OG&E filed an application pursuant to the Act seeking OCC approval to securitize its costs related to Winter Storm Uri and to receive an interim carrying charge on OG&E's regulatory asset balance at its weighted-average cost of capital for the period between April 2022 and the date when the securitized bonds are issued. On June 18, 2021, OG&E filed its direct testimony which supports the prudence of the costs incurred during Winter Storm Uri and demonstrates the customer savings associated with securitization as opposed to traditional utility financing. On October 8, 2021, OG&E filed a settlement agreement between OG&E, the Public Utility Division Staff of the OCC, the Oklahoma Industrial Energy Consumers, the OG&E Shareholders Association and Walmart Inc. The settlement agreement is subject to approval by the OCC. The settling parties agreed the OCC should issue a financing order authorizing the securitization of $760.0 million, which includes estimated finance costs and is subject to change for carrying costs, any updates from the SPP settlement process and actual securitization issuance costs. The settling parties agree that OG&E's total extreme purchase costs (for natural gas and wholesale energy purchases) are currently estimated to be $748.9 million, of which it is agreed that $739.1 million should be deemed prudent. Any adjustments for this settlement will be recorded in the fourth quarter of 2021. The OCC conducted a hearing on the settlement agreement on October 13-14, 2021. The Administrative Law Judge is expected to draft a recommendation for deliberation on a final order by the OCC, and the final order is expected by December 15, 2021. 2020 Oklahoma Fuel Prudency On June 28, 2021, the Public Utility Division Staff filed their application initiating the review of the 2020 fuel adjustment clause and prudence review. OG&E filed its minimum filing requirements and supporting testimony on August 27, 2021. A hearing on the merits is expected to be held in December 2021.

In October 2020, OG&E filed its third evaluation report under its Formula Rate Plan, and on January 28, 2021, OG&E entered into a non-unanimous settlement agreement with the APSC General Staff and the Office of the Arkansas Attorney General. The only non-signatory to the settlement agreement agreed not to oppose the settlement. The settlement agreement included a revenue increase of $6.7 million, which is the maximum amount statutorily allowed in this filing. Additionally, the settling parties did not object to OG&E's request for a finding that the Arkansas Series II grid modernization projects included in this filing are prudent in cost. On March 9, 2021, the APSC issued a final order approving the non-unanimous settlement agreement, and new rates became effective April 1, 2021.

In September 2020, the APSC invited comments from all jurisdictional utilities and any other interested stakeholders on specific questions related to whether a moratorium on service terminations should be lifted and if so, how the resumption of disconnections should occur. The APSC also ordered utilities to submit a detailed "Transitional Plan" outlining how utilities proposed to reinstate routine service disconnection activities and collection of past due amounts once the moratorium was lifted. OG&E submitted its proposed Transitional Plan in October 2020.

On February 8, 2021, the APSC announced a target date of May 3, 2021 to lift the moratorium on disconnections and specified certain conditions and requirements that utilities must meet before disconnections may resume. Such requirements include, among other things, immediate communication to customers, notice periods for disconnections and deferred payment arrangements. On March 26, 2021, the APSC confirmed the lifting of the moratorium on disconnections on May 3, 2021 and directed utilities to take specific steps prior to resuming disconnections. OG&E resumed disconnections on May 3, 2021.

On March 3, 2021, OG&E filed an application with the APSC to request approval to construct a 5 MW solar facility in Oklahoma. The APSC issued an order on April 6, 2021, finding OG&E's application in the public interest, conditioned on Arkansas customers being held harmless and not subject to cost recovery associated with the project. OG&E expects the costs associated with constructing this solar facility to be fully recovered in Oklahoma.

In November 2020, the OCC issued a final order approving a Joint Stipulation and Settlement Agreement that allows for interim recovery of OG&E's costs associated with its grid enhancement plan. The approved agreement included the following key terms: (i) cost recovery through a rider mechanism will be limited to projects placed in service in 2020 and 2021, capped at a revenue requirement of $7.0 million annually and only include communication, automation and technology systems projects; (ii) no operation and maintenance expense will be included in the rider mechanism; (iii) the rider mechanism will terminate by the issuance of a final order in OG&E's next general rate review or October 31, 2022, whichever occurs first; (iv) the rider mechanism rate of return will be capped at OG&E's current cost of capital; and (v) all cost recovery is subject to true-up and refund in OG&E's next general rate review. The rider mechanism became effective on February 1, 2021.

OG&E reports to the OCC new projects completed each quarter, and the cost recovery factor is adjusted to include those projects after a stakeholder review. OG&E has submitted its report for projects that were placed in service through September 30, 2021. The cost recovery factors that include those projects will become effective on December 1, 2021.

Various proceedings pending before state or federal regulatory agencies are described below. Unless stated otherwise, the Registrants cannot predict when the regulatory agency will act or what action the regulatory agency will take. The Registrants' financial results are dependent in part on timely and adequate decisions by the regulatory agencies that set OG&E's rates.

Under the SPP Open Access Transmission Tariff, costs of participant-funded, or "sponsored," transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP Open Access Transmission Tariff required the SPP to charge for these upgrades beginning in 2008, but the SPP had not been charging its customers for these upgrades due to information system limitations. However, the SPP had informed participants in the market that these charges would be forthcoming. In July 2016, the FERC granted the SPP's request to recover the charges not billed since 2008. The SPP subsequently billed OG&E for these charges and credited OG&E related to transmission upgrades that OG&E had sponsored, which resulted in OG&E being a net receiver of sponsored upgrade credits. The majority of these net credits were refunded to customers through OG&E's various rate riders that include SPP activity with the remaining amounts retained by OG&E.

Several companies that were net payers of Z2 charges sought rehearing of the FERC's July 2016 order; however, in November 2017, the FERC denied the rehearing requests. In January 2018, one of the impacted companies appealed the FERC's decision to the U.S. Court of Appeals for the District of Columbia Circuit. In July 2018, that court granted a motion requested by the FERC that the case be remanded back to the FERC for further examination and proceedings. In February 2019, the FERC reversed its July 2016 order and November 2017 rehearing denial, ruled that the SPP violated its tariff to charge for the 2008 through 2015 period in 2016, held that the SPP tariff provision that prohibited those charges could not be waived and

ordered the SPP to develop a plan to refund the payments but not to implement the refunds until further ordered to do so. In response, in April 2019, OG&E filed a request for rehearing with the FERC, and in May 2019, OG&E filed a FERC 206 complaint against the SPP, alleging that the SPP's forced unwinding of the revenue credit payments to OG&E would violate the provisions of the Sponsored Upgrade Agreement and of the applicable tariff. OG&E's filing requested that the FERC rule that the SPP is not entitled to seek refunds or in any other way seek to unwind the revenue credit payments it had paid to OG&E pursuant to the Sponsored Upgrade Agreement. The SPP's response to OG&E's filing agreed that OG&E should be entitled to keep its Z2 payments and argued that the SPP should not be held responsible for those payments if refunds are ordered. Further, the SPP has requested the FERC to negotiate a global settlement with all impacted parties, including other project sponsors who, like OG&E, have also filed complaints at FERC contending that the payments they have received cannot properly be unwound.

In February 2020, the FERC denied OG&E's request for rehearing of its February 2019 order, denying the waiver and ruling that the SPP must seek refunds from project sponsors for Z2 payments for the 2008 through 2015 period and pay them back to transmission owners. The FERC also denied the SPP's request for a stay and for institution of settlement procedures. The FERC stated it would not institute settlement procedures unless parties on both sides of the matter requested them. The FERC did not rule on OG&E's complaint or the complaints of other project sponsors, or consider the SPP's refund plan. The FERC thus has not set any date for payment of refunds. In March 2020, OG&E petitioned the U.S. Court of Appeals for the District of Columbia Circuit for review of the FERC's order denying the waiver and requiring refunds. The court issued a decision on August 27, 2021, denying review and holding that the SPP was prohibited by the filed rate doctrine from imposing Z2 charges during the 2008 through 2015 historical period. The court further held that the FERC reasonably exercised its remedial authority to order the SPP to refund the retroactive upgrade charge. The court did not direct a time frame or procedures for the SPP to implement refunds. OG&E and the SPP filed a petition for rehearing of the court's decision, which was denied on October 29, 2021. The court will return the matter to the FERC for action in accordance with its opinion on November 5, 2021.

If the FERC proceeds to order refunds in full, OG&E estimates it would be required to refund $13.0 million, which is net of amounts paid to other utilities for upgrades and would be subject to interest at the FERC-approved rate. The SPP has stated in filings it made with the FERC while the appeal was pending that there are considerable complexities in implementing the refunds that will have to be resolved before they can be paid. Payment of refunds would shift recovery of these upgrade credits to future periods. Of the $13.0 million, the Registrants would be impacted by $5.0 million in expense that initially benefited the Registrants in 2016, and OG&E customers would incur a net impact of $8.0 million in expense through rider mechanisms or the FERC formula rate. As of September 30, 2021, the Registrants have reserved $13.0 million plus estimated interest for a potential refund.

In January 2020, the FERC acted on an SPP proposal to eliminate Attachment Z2 revenue crediting and replace it with a different rate mechanism that would provide project sponsors, such as OG&E, the same level of recovery, and rejected the proposal to the extent it would limit recovery to the amount of the upgrade sponsor's directly assigned upgrade costs with interest. The SPP resubmitted a proposal in April 2020 without this limited recovery, and with the alternative rate mechanism, and the FERC approved it in June 2020, effective July 1, 2020. No party sought rehearing of the order, and it is now final. This order would only prospectively impact OG&E and its recovery of any future upgrade costs that it may incur as a project sponsor subsequent to July 2020. All of the existing projects that are eligible to receive revenue credits under Attachment Z2, which includes the $13.0 million at issue in OG&E's appeal as discussed above, will continue to do so.

The FERC issued a NOPR on March 20, 2020, and issued a supplemental NOPR on April 15, 2021, proposing to update its transmission incentives policy. Among other things, the NOPR proposes (i) the current 50-basis point return on equity adder for RTO/ISO participation would be applicable only to transmitting utilities that join an RTO/ISO, and this incentive would only apply for the first three years in which the utility is an RTO/ISO member and (ii) transmitting utilities that have been members of an RTO/ISO for three years or more, such as OG&E, would be required to make a compliance filing to remove the existing return on equity adder from their rates. OG&E is currently evaluating the potential impacts of this proposed rule. Currently, there is no specific deadline for the FERC to take further action, and it is unknown whether the FERC will address the RTO participation adder individually or as part of a larger order on transmission incentives.

In February 2021, Winter Storm Uri resulted in record winter peak demand for electricity and extremely high natural gas and purchased power prices in OG&E's service territory. On April 1, 2021, OG&E filed with the APSC a Motion for Authority to Establish Special Regulatory Treatment within the Energy Cost Recovery Rider to Defer Extraordinary Fuel Costs Incurred Due to Winter Storm Uri. More specifically, OG&E's motion sought approval to defer, amortize and recover the extraordinary fuel costs over a ten-year period with a carrying charge of OG&E's pre-tax rate of return of 6.60 percent, through a special factor within OG&E's Energy Cost Recovery Rider beginning with the first billing cycle of May 2021. On April 13, 2021, the APSC issued an order allowing OG&E interim recovery at an interest rate equal to the customer deposit interest rate, which is currently 0.8 percent, over a period of ten years beginning with the first billing cycle of May 2021. Recovery is subject to a true-up after the APSC determines the appropriate allocation, length of recovery and carrying charge. On May 4, 2021, OG&E filed testimony further supporting its 10-year amortization period and a carrying charge of OG&E's pre-tax rate of return of 6.60 percent.

In April 2021, Arkansas enacted legislation to amend its storm recovery securitization statute to allow for both electric and gas utilities to recover through securitization extraordinary natural gas, fuel and purchased power costs caused by storms. The amended statute authorizes the APSC to issue a financing order for the issuance of securitization bonds upon a finding it is reasonably expected to lower overall costs or mitigate rate impacts as compared with traditional utility financing. Upon the initiation of a securitization application, the APSC has 135 days to issue an order. The requesting utility has two years from the date of the financing order to issue the securitization bonds. The amended statute allows carrying costs at a utility's weighted average cost of capital from the date of when the costs were incurred until the date when bonds are ultimately issued.

On May 20, 2021, OG&E filed a motion for suspension of procedural schedule, which the APSC approved, to investigate and evaluate the potential securitization recovery of the Arkansas jurisdictional portion of the Winter Storm Uri costs. OG&E intends to apply for securitization in early 2022 if it is deemed to strike the right balance between protecting the credit strength of OG&E and providing customer savings. As of September 30, 2021, OG&E has deferred $91.0 million to a regulatory asset, as indicated in Note 1.

Several rural electric cooperative electricity suppliers have filed complaints with the OCC alleging that OG&E has violated the Oklahoma Retail Electric Supplier Certified Territory Act. OG&E believes it is lawfully serving customers specifically exempted from this act and has presented evidence and testimony to the OCC supporting its position. There have been five complaint cases initiated at the OCC, and the OCC has issued decisions on each of them. The OCC ruled in favor of the electric cooperatives in three of those cases and ruled in favor of OG&E in two of those cases. All five of those cases have been appealed to the Oklahoma Supreme Court, where they have been made companion cases but will be individually briefed and have individual final decisions.

If the Oklahoma Supreme Court ultimately were to find that some or all of the customers being served are not exempted from the Oklahoma Retail Electric Supplier Certified Territory Act, OG&E would have to evaluate the recoverability of some plant investments made to serve these customers. The total amount of OG&E's plant investments made to serve the customers in all five cases is approximately $28.0 million, of which $11.7 million applies to the three cases where the OCC ruled in favor of the electric cooperatives. In addition to the evaluation of the recoverability of the investments, OG&E may also be required to reimburse certified territory suppliers for an amount of lost revenue. The amount of such lost revenue would depend on how the OCC calculates the revenue requirement but could range from approximately $26.0 million to $35.4 million for all five cases, of which $2.5 million to $3.9 million would apply to the three cases where the OCC ruled in favor of the electric cooperatives.

In February 2021, Winter Storm Uri resulted in record winter peak demand for electricity and extremely high natural gas and purchased power prices in OG&E's service territory. On February 24, 2021, OG&E submitted an application to the OCC outlining a two-step approach for regulatory treatment for the fuel and purchased power costs associated with Winter Storm Uri. The steps included: (i) an intra-year fuel clause increase to be effective April 1, 2021; and (ii) a request for regulatory asset treatment at OG&E's weighted average cost of capital for the remaining fuel and purchased power costs. On March 18, 2021, the OCC approved OG&E's filing to establish a regulatory asset. The approval allowed OG&E to create a regulatory asset for all deferred costs with an initial carrying charge based on the effective cost of the debt financing, until such time where the prudency of this event is evaluated, the amortization period is decided on and a long-term carry cost is established.

In April 2021, Oklahoma enacted legislation to allow for the securitization of costs incurred during Winter Storm Uri. The new statute authorizes the OCC to issue a financing order for the issuance of securitization bonds after consideration of certain factors, including but not limited to, mitigated impacts and savings for customers through the use of ratepayer-backed securitization bonds as compared to traditional utility financing. The OCC must issue a financing order within 180 days after receiving all necessary information required by the statute. Under the statute, the Oklahoma Development Finance Authority is responsible for issuing the securitization bonds within two years from the date of the financing order. Carrying costs will be included at a rate and time determined by the OCC and continue until the bonds are issued.

On April 26, 2021, OG&E filed an application pursuant to the Act seeking OCC approval to securitize its costs related to Winter Storm Uri and to receive an interim carrying charge on OG&E's regulatory asset balance at its weighted-average cost of capital for the period between April 2022 and the date when the securitized bonds are issued. On June 18, 2021, OG&E filed its direct testimony which supports the prudence of the costs incurred during Winter Storm Uri and demonstrates the customer savings associated with securitization as opposed to traditional utility financing. On October 8, 2021, OG&E filed a settlement agreement between OG&E, the Public Utility Division Staff of the OCC, the Oklahoma Industrial Energy Consumers, the OG&E Shareholders Association and Walmart Inc. The settlement agreement is subject to approval by the OCC. The settling parties agreed the OCC should issue a financing order authorizing the securitization of $760.0 million, which includes estimated finance costs and is subject to change for carrying costs, any updates from the SPP settlement process and actual securitization issuance costs. The settling parties agree that OG&E's total extreme purchase costs (for natural gas and wholesale energy purchases) are currently estimated to be $748.9 million, of which it is agreed that $739.1 million should be deemed prudent. Any adjustments for this settlement will be recorded in the fourth quarter of 2021. The OCC conducted a hearing on the settlement agreement on October 13-14, 2021. The Administrative Law Judge is expected to draft a recommendation for deliberation on a final order by the OCC, and the final order is expected by December 15, 2021.