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Rate Matters and Regulation | 6 Months Ended
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Jun. 30, 2015
Regulated Operations [Abstract] |
Rate Matters and Regulation | Rate Matters and Regulation Except as set forth below, the circumstances set forth in Note 15 to the Company's Consolidated Financial Statements included in the Company's 2014 Form 10-K appropriately represent, in all material respects, the current status of the Company's regulatory matters. Arkansas Regulatory Developments The State of Arkansas earlier in 2015 enacted two laws related to rate filings. Act 725, among other things, provides a public utility the option, to be exercised concurrently with the filing of a general rate application, to file notice of its intent to exercise its right for an annual formula rate review so as to provide a streamlined review of the utility’s rates to determine if adjustments in rates are justified. If the utility exercises such rights, rates may be adjusted if the earned return rate is 0.5 percent above or below the target return rate. This procedure is expected to reduce regulatory lag in Arkansas. Act 725 additionally allows for evidence to be presented, relative to the calculation of the return on common equity, comparing the requested return on common equity to approved returns on common equity for public utilities delivering similar services with corresponding risks within Arkansas and also in similar regulatory jurisdictions in the same general part of the country. Act 1000 amends and clarifies existing interim rate requirements to expand the types of expenses that may be recorded and specifically authorize the recovery of allowance for funds used during construction. Act 1000 allows a public utility to file for an interim rate schedule through which it may recover investments and expenses, including allowance for funds used during construction, expended complying with legislative or administrative rules, regulations, or requirements related to the protection of the public, health, safety, or the environment. Rates are implemented at the time of filing of the interim rate schedule, subject to refund. As permitted by Act 1000, on May 8, 2015, OG&E filed an interim rate schedule to recover expenditures for the Arkansas portion of the low NOx burners made in order to comply with the Regional Haze rule for NOx. Pending Regulatory Matters Environmental Compliance Plan On August 6, 2014, OG&E filed an application with the OCC for approval of its plan to comply with the EPA’s MATS and Regional Haze FIP while serving the best long-term interests of customers in light of future environmental uncertainties. The application seeks approval of the environmental compliance plan and for a recovery mechanism for the associated costs. The environmental compliance plan includes installing dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas. The application also asks the OCC to predetermine the prudence of replacing OG&E's soon-to-be retired Mustang steam turbines in late 2017 (approximately 460 MW) with 400 MW of new, efficient combustion turbines at the Mustang site in 2018 and 2019 and approval for a recovery mechanism for the associated costs. OG&E estimates the total capital cost associated with its environmental compliance and Mustang Modernization Plan included in this application to be approximately $1.1 billion. The OCC hearing on OG&E's application before an ALJ began on March 3, 2015 and concluded on April 8, 2015. Multiple parties advocating a variety of positions intervened in the proceeding. As previously reported, on June 8, 2015 the ALJ issued his report on OG&E's application. While the ALJ in his report agrees that the installation of dry scrubbers at Sooner Units 1 and 2 and the conversion of Muskogee Units 4 and 5 to natural gas pursuant to OG&E’s environmental compliance plan is the best approach, the ALJ makes various recommendations including, among others, that: (i) the OCC should not raise rates at this time; (ii) with respect to OG&E’s environmental compliance plan, the OCC should grant pre-approval of the estimated costs for new equipment as set by contract, including installation costs covered by a contract, but pre-approval of other equipment and installation costs that were still being negotiated at the end of the evidentiary hearing on April 8, 2015 should be deferred and may be considered in the next general rate case; (iii) the foregoing pre-approval is subject to the condition that the OCC should direct OG&E to issue requests for information for at least 200 MWs of wind power within thirty days of a final order; (iv) the OCC should postpone consideration of all other cost recovery issues until the next general rate case; (v) the OCC should direct the PUD Director to commence a general rate case; and (vi) the OCC should deny the Mustang Modernization Plan. OG&E filed exceptions to the ALJ's report in which OG&E set forth the various findings and recommendations that OG&E believes to be erroneous, including the ALJ’s refusal to recommend a recovery rider for OG&E environmental compliance plan and the ALJ’s recommendation that the OCC should deny the Mustang Modernization Plan. The OCC heard oral arguments on June 25, 2015 and took the case under advisement. On July 21, 2015, Commissioner Bob Anthony (one of the three commissioners on the OCC) issued his deliberation statement that was consistent with many parts of the ALJ Report, including the ALJ’s support of OG&E’s environmental compliance plan, the ALJ’s recommendation, as described above, to pre-approve certain estimated costs of the environmental recovery plan, and the ALJ’s recommendation to defer all other costs recovery issues until the next general rate case. OG&E cannot predict the outcome of this proceeding. Oklahoma Demand Program Rider Review In July 2012, OG&E filed an application with the OCC to recover certain costs associated with Demand Programs through the Demand Program Rider, including the lost revenues associated with the SmartHours program. The SmartHours program is designed to incentivize participating customers to reduce on-peak usage or shift usage to off peak hours during the months of May through October, by offering lower rates to those customers in the off peak hours of those months. Lost revenues are created by the difference in the standard rates and the lower incentivized rates. Non-SmartHours program customers benefit from the reduction of on-peak usage by SmartHours customers, by the reduction of more costly on-peak generation and the delay in adding new on-peak generation. In December 2012, the OCC issued an order approving the recovery of costs associated with the Demand Programs, including the lost revenues associated with the SmartHours program, subject to the Oklahoma PUD staff review. In March 2014, the Oklahoma PUD staff began their review of the Demand Program cost, including the lost revenues associated with the SmartHours program. In November 2014, OG&E believed that it had reached an agreement with the Oklahoma PUD staff on the methodology to be used to calculate lost revenues associated with the SmartHours program and the amount of lost revenue for 2013, which totaled $10.1 million. The agreement also included utilizing the same methodology for calculating lost revenues for 2014, which would result in lost revenues for 2014 of $11.6 million. In January 2015, OG&E implemented rates that began recovering the 2013 lost revenues, in accordance with the agreement that it believed had been reached with the Oklahoma PUD staff. In April 2015, the Oklahoma PUD staff filed an application, seeking an order from the OCC determining the proper calculation methodology for lost revenues pursuant to OG&E’s Demand Program Rider, primarily affecting the SmartHours program lost revenues. In the application, the Oklahoma PUD staff recommends the OCC approve the Oklahoma Public Utility Division staff methodology for calculating lost revenues associated with the SmartHours program, which differs from the methodology that OG&E believes it had agreed upon and which would result in recovery of lost revenue for 2013 of only $4.9 million, a reduction of $5.2 million from the amount recorded by OG&E for 2013. OG&E believes that the methodology agreed to in November 2014, is consistent with the 2012 OCC order, and believes that it is probable that it will recover the $10.1 million of lost revenues associated with 2013, and the $11.6 million associated with 2014. A hearing was held on June 30, 2015 and July 1, 2015. OG&E expects a commission ruling in the third quarter of 2015. Fuel Adjustment Clause Review for Calendar Year 2013 The OCC routinely reviews the costs recovered from customers through OG&E's fuel adjustment clause. On July 31, 2014, the OCC Staff filed an application to review OG&E's fuel adjustment clause for calendar year 2013, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. OG&E filed the necessary information and documents needed to satisfy the OCC's minimum filing requirement rules on September 29, 2014. On May 21, 2015, the ALJ recommended that the OCC find that OG&E's 2013 electric generation, purchased power and fuel procurement processes and costs were prudent, accurate and properly applied to customer billing statements. OG&E received an order to that effect from the OCC on June 17, 2015. Fuel Adjustment Clause Review for Calendar Year 2014 On July 28, 2015, the OCC staff filed an application to review OG&E's fuel adjustment clause for calendar year 2014, including the prudence of OG&E's electric generation, purchased power and fuel procurement costs. Oklahoma Rate Case Filing On July 28, 2015 OG&E filed a notice of intent with the OCC to file a general rate case on or before November 30, 2015 based on a June 30, 2015 test year and to modify rates no later than 180 days from the date of filing the rate case. Among the matters OG&E expects the rate case to address are certain cost recovery riders, the retail portion of transmission expenditures made by OG&E since the last rate case, ad valorem taxes, depreciation rates, impact of the expiration of OG&E’s wholesale contracts and the costs associated with the SPP Integrated Market.

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