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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 8-K

CURRENT REPORT PURSUANT
TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of report (Date of earliest event reported)
May 18, 2017
 
 
 
 
OGE ENERGY CORP.
(Exact Name of Registrant as Specified in Its Charter)
 
 
Oklahoma
(State or Other Jurisdiction of Incorporation)
 
 
1-12579
73-1481638
(Commission File Number)
(IRS Employer Identification No.)
 
 
321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma
73101-0321
(Address of Principal Executive Offices)
(Zip Code)
 
 
405-553-3000
(Registrant's Telephone Number, Including Area Code)
 
 
(Former Name or Former Address, if Changed Since Last Report)
 
 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
    
* Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
* Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
* Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
* Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR 240.12b-2).
Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o





Item 8.01. Other Events

OGE Energy Corp. (the "Company") is the parent company of Oklahoma Gas and Electric Company ("OG&E"), a regulated electric utility with approximately 836,000 customers in Oklahoma and western Arkansas. In addition, the Company holds a 25.7 percent limited partner interest and a 50 percent general partner interest in Enable Midstream Partners, LP.

As previously reported, on August 25, 2016, OG&E filed a general rate case with the Arkansas Public Service Commission ("APSC"). The rate filing requested a $16.5 million rate increase based on a 10.25 percent return on equity. The rate increase was based on a June 30, 2016 test year and included a recovery of over $3.0 billion of electric infrastructure additions since the last Arkansas general rate case in 2011. The increase also reflects increases in operation and maintenance expenses, including vegetation management, and increased recovery of depreciation and dismantlement costs.

In April 2017, OG&E entered into a settlement with the staff of the APSC and other intervenors. The settlement provides for a $7.1 million annual rate increase and a 9.50 percent return on equity on a 50.0 percent equity capital structure. The settlement also provides that OG&E will be regulated under a formula rate rider, which should result in a more efficient process as the return on equity, depreciation rates and capital structure should not change from what is approved by the APSC in the current rate case proceeding unless differences of plus or minus 50 basis points in return on equity were to occur. Adjustments are limited to plus or minus four percent of revenue for each rate class for the 12 months preceding the projected year. The initial term for the formula rate rider is not to exceed five years, unless additional approval is obtained from the APSC. OG&E expects to make its first filing under the Arkansas Formula Rate Rider in October 2018.

The APSC approved the settlement on May 18, 2017. The settlement agreement and approval from the APSC are attached as exhibits and incorporated herein by reference.

Item 9.01. Financial Statements and Exhibits

(d) Exhibit
 
 
 
 
 
        Exhibit Number
 
                    Description
 
 
 
99.01
 
Copy of the APSC Settlement Agreement approval dated May 18, 2017.
99.02
 
Copy of the Settlement Agreement filed with the APSC on April 20, 2017.




SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


 
OGE ENERGY CORP.
 
(Registrant)
 
 
By:
/s/ Scott Forbes
 
    Scott Forbes
 
 Controller and Chief Accounting Officer
 
 

May 24, 2017



Exhibit



ARKANSAS PUBLIC SERVICE COMMISSION

IN THE MATTER OF THE APPLICATION
)
 
OF OKLAHOMA GAS AND ELECTRIC
)
DOCKET NO. 16-052-U
COMPANY FOR APPROVAL OF A
)
ORDER NO. 8
GENERAL CHANGE IN RATES, CHARGES
)
 
AND TARIFFS
)
 

ORDER

This order approves the Settlement Agreement proposed by the parties to the Docket on April 20, 2017. Under the Settlement Agreement, Oklahoma Gas and Electric Company (OG&E) will be permitted to increase its rates to recover a revenue deficiency of $7.1 million, compared to $16.5 million requested in its Application. The return on equity is set at 9.5%, compared to OG&E's requested 10.25%. Several new optional rate schedules are authorized for residential and general service rate classes with a "best bill" provision. A formula rate plan is also approved for OG&E. For the average residential customer using 1000 kWh per month, the monthly bill will increase by $5.89 per month as opposed to $15.28 per month as proposed by OG&E.

History

On August 25, 2016, pursuant to Ark. Code Ann. §§ 23-4-401, et seq. and Arkansas Public Service Commission (Commission) Rules of Practice and Procedure Sections 3 and 8, OG&E filed its Application for Approval of a General Change in Rates, Charges, and Tariffs (Application) reflecting a $16.5 million revenue deficiency and a non-fuel revenue requirement of $108.8 million. See OG&E's Minimum Filing Requirements (MFR) Schedule A-1. OG&E further sought an overall rate of return of 6.01% and a return on equity (ROE) of 10.25%. OG&E provided notice that it elects to implement a Formula Rate Plan (FRP), proposed to change its cost allocation to use the Average and Excess Four Coincident Peak (A&E 4CP) cost allocation methodology for production costs, and proposed to revise its rate design, all pursuant to Act 725 of 2015, Ark. Code Ann. §§ 23-4-410, 23-4-422, and 23-4-1201 et seq. (Act 725). OG&E stated that its base rate increase is driven primarily by significant capital expenditures for plant and facilities in order to maintain a safe and reliable system and to comply with environmental and regulatory requirements, as well as increased operations and maintenance expenses. According to OG&E, the impact of the requested base rate increase would be a net increase of $15.28 or 18% for a typical residential customer using 1,000 kWh per month. In support of its Application, OG&E filed the Direct Testimony and Exhibits of its witnesses as follows: Donald Rowlett, David Smith, Robert Hevert, Malini Gandhi, Gwin Cash, Jason Thenmadathil, Scott Forbes, Jarod Cassada, Bryan Scott, William Wai, and John Spanos.

On September 16, 2016, Order No. 2 suspended the proposed rates and tariffs filed by OG&E; set a procedural schedule including a public evidentiary hearing for May 2, 2017, and a public comment hearing for May 9, 2017, in Fort Smith, Arkansas; and directed OG&E to publish notice of the filing of its Application.

In addition to OG&E, the official parties to this Docket are: Wal-Mart Stores Arkansas, LLC and Sam's West, Inc. (collectively Walmart), Arkansas River Valley Energy Consumers (ARVEC), Sierra Club (Sierra), the Office of Arkansas Attorney General Leslie Rutledge (AG), and the General Staff (Staff) of the Commission.


Docket No. 16-052-U
Order No. 8
Page 2


On January 31, 2017, Staff and the Intervenors filed Direct Testimonies and Exhibits of their witnesses. Walmart's witness was Steve Chriss. Walmart supported OG&E's used of A&E 4CP, opposed combining the PL-TOU-D and PL-TOU-E rate schedules, and opposed the Large Capital Additions Rider (LCA Rider).

ARVEC's witnesses were Larry Blank and Mark Garrett. ARVEC supported OG&E's used of A&E 4CP, opposed the LCA Rider, and opposed combining the PLTOU-D and PL-TOU-E rate schedules. ARVEC recommended adjustments to incentive compensation, supplemental employee retirement plans, payroll expense, ad valorem tax expense, vegetation management costs, corporate cost allocations, and storm damage costs. ARVEC also proposed that wind power production assets be allocated based on demand instead of energy.

Walmart and ARVEC also jointly filed the testimony of David Garrett who recommended an ROE of 9.0%, a debt to equity ratio of 52%/48%, and revised depreciation rates which would reduce Arkansas jurisdictional depreciation expense by $4.5 million.

The AG's witnesses were David E. Dismukes and William B. Marcus. The AG recommended a capital structure of 49% equity and 51% debt, with a rate of return on equity of 9.3%, or 9.05% if the FRP is adopted. The AG recommended revisions to incentive compensation amounts, advertising expenses, storm damage, and several other expense items, and recommended the inclusion of the Domestic Production Activities Deduction (DPAD) in the revenue conversion factor. The AG opposed the Storm Damage Recovery (SDR) Rider and the LCA Rider and recommended several revisions to OG&E's proposed FRP. The AG proposed that the Commission maintain current customer charges, reject demand rates for residential and General Service (GS) customers, and reject elimination of the volumetric block structure. For cost allocation of production costs, the AG recommended that the Commission adopt the same approach as recent rate cases and not make specific findings on the relationship between the proposed demand allocator and economic development for purposes of Act 725.

Staff witnesses were Joy Brooks, Clark Cotten, Troy Eggleton, Elana Foley, Jeff Hilton, Matthew Klucher, Judy Lindholm, William Matthews, Regis Powell, Claude Robertson, Robert Swaim, Bill Taylor, Holly Tubbs, and Gerrilynn Wolfe. Staff recommended an Arkansas retail revenue requirement of $102,051,586 and a deficiency of $16,565,238 excluding rider revenues, or $9,834,957 including rider revenues.1 Staff supported an overall rate of return of 5.31%, a return on equity of 9.5%, and a capital structure of 52% debt and 48% equity. Staff recommended adjustment to OG&E's levels of incentive compensation and several other expenses and recommended the inclusion of the DPAD in the revenue conversion factor. Staff agrees with OG&E's use of the A&E 4CP but with mitigated results. Staff opposed the continuing use of the SDR Rider and also recommended revisions to OG&E's proposed Rider FRP including a fixed debt-to equity ratio. Staff recommended rejection of the LCA Rider. Staff proposed that the customer charge be increased by no more than the class average increase, that demand charges for residential and GS customers be offered as optional with a "best bill" provision and that tier changes in variable peak pricing include a "best bill" provision.

Sierra did not file Direct Testimony.


                                                                         
1 The latter is the amount comparable to OG&E's figures.


Docket No. 16-052-U
Order No. 8
Page 3

On February 28, 2017, OG&E filed the Rebuttal Testimonies and Exhibits of its witnesses Scott, Smith, Rowlett, Cash, Thenmadathil, Spanos, Forbes, Gandhi, Hevert, and Patricia Ruden. OG&E disagreed with proposals to revise OG&E's capital structure to use a hypothetical structure, and continued to support an ROE of 10.25%. OG&E also disagreed with the AG' s and Staff's proposals for customer charges and did not oppose Staff's proposal to make proposed residential and GS demand rates optional and to offer a "best bill" provision on those tariffs as well as tier changes in variable peak pricing. OG&E opposed changes to its levels of incentive compensation. OG&E agreed with most of Staff's revisions to the FRP.

On March 30, 2017, Staff and the Intervenors filed Surrebuttal Testimonies and Exhibits of their witnesses.

ARVEC witnesses Mark Garrett and Dr. Blank supported use of a demand allocator for production wind assets and opposed mitigation of the cost of service results. ARVEC opposed merging of the PL-TOU-D and PL-TOU-E rate schedules. David Garrett on behalf of Walmart and ARVEC updated his Discounted Cash Flow Model to arrive at an average ROE estimate of 7.2% and also urged the Commission to consider depreciation rates adopted for OG&E in Oklahoma.

Surrebuttal Testimony was filed by AG witnesses Dismukes and Marcus. The AG supported use of a demand allocator for production wind assets. The AG adopted Staff's recommendation of a hypothetical capital structure of 52% debt/48% equity and continued to oppose increased customer charges, residential and GS demand charges, and changes in the variable peak pricing (VPP) tiers.

Staff witnesses Brook, Cotten, Eggleton, Foley, Hilton, Klucher, Lindholm, Matthews, Powell, Swaim, Taylor, and Wolfe filed Surrebuttal Testimony. Staff's Surrebuttal Arkansas retail revenue requirement was $103,832,384, with a deficiency of $18,170,088 excluding rider revenues, or $8,429,045 including rider revenues.2 While Staff updated its recommended rate of return to 5.36%, Staff continued to recommend an ROE of 9.5%, a hypothetical capital structure of 52% debt/48% equity, use of the A&E 4CP cost allocation methodology as mitigated, and a rate design that increased the residential customer charge by no more than the class percentage increase. Staff noted that the issue of whether to fix the debt to equity ratio in the FRP remains contested. Staff continued to support OG&E's use of an energy allocator for production wind assets.

Sierra did not file Surrebuttal Testimony.

On April 6, 2017, OG&E filed the Sur-Surrebuttal Testimonies and Exhibits of its witnesses Wai, Thenmadathil, Spanos, Rowlett, Forbes, and Hevert. OG&E proposed an updated rate schedule revenue requirement of $109,808,593 with a retail revenue deficiency of $15,186,785. OG&E continued to support its proposed ROE of 10.25% and capital structure of 47% debt/53% equity. OG&E pointed out an error in Staff's advertising expense adjustment and offered support for the revision to its VPP tiers opposed by the AG.

On October 14 and 17, 2016, OG&E submitted proof of notice of publication pursuant to Order No. 2.

Prior to the May 2, 2017, evidentiary hearing, the parties engaged in negotiations in an effort to achieve resolution of the litigated issues. Those negotiations led to the filing of a Settlement Agreement (Agreement) on April 20, 2017 (discussed infra). The unanimous3 Agreement settled all litigated issues based
                                              
2 The latter is the amount comparable to OG&E's figures.
3 The Agreement was supported by OG&E, Walmart, ARVEC, the AG, and Staff; Sierra took no position on the Agreement.


Docket No. 16-052-U
Order No. 8
Page 4

on Staff's Surrebuttal case with certain specific modifications. The Agreement was supported by Settlement Testimony of OG&E witness Rowlett; Walmart witness Chriss; ARVEC witness Blank; AG witness Shawn McMurray; and Staff witnesses Klucher, Hilton, and Powell. Pursuant to the request of the parties, the Commission in Order No. 7 excused from the hearing all witnesses except the settlement witnesses.

Proposed Settlement Compliance Tariffs were filed by OG&E on May 8, 2017. Compliance Testimony was filed by Staff witness Swaim on May 8, 2017.

On May 2, 2017, the Commission held a public evidentiary hearing at its offices in Little Rock, Arkansas, to consider the Agreement.4 On May 9, 2017, a public comment hearing was held in Fort Smith, Arkansas. No persons made public comments at the May 2 or May 9 hearing. In addition, 96 public comments5 have been received online to date which oppose the proposed rate increase, mention the need to use clean energy, or ask the Commission to not allow Arkansans to pay for the Oklahoma Sooner coal plant.

Settlement Agreement

As discussed above, the parties filed an Agreement on April 20, 2017, which settled all litigated issues based on Staff's Surrebuttal case with certain modifications. The terms of the Agreement are summarized as follows:

REVENUE REQUIREMENT:

A.
OG&E's Arkansas jurisdictional base rate revenue requirement is $102,193,196 with a resulting revenue deficiency of $7,116,038.
B.
The revenue deficiency and revenue requirement were developed based on Staff's Surrebuttal revenue requirement and related recommendations adjusted only as listed below:
1.
OG&E's Advertising adjustment IS-13 is changed from a decrease of $3,296,900 to a decrease of $957,693. This results in an increase to the revenue requirement of $162,772;
2.
The Revenue Conversion Factor (RCF) is increased by 0.0247. This change is the result of removing the DPAD from the RCF, thereby increasing the revenue requirement by $274,009;
3.
The Wind Jurisdictional Allocator is changed from an Energy Allocator of 10.29% to a Demand Allocator of 8.49%, resulting in a decrease to the revenue requirement of $2,102,493;
4.
The Company's adjustment IS-32 reflects a reduction in Storm Damage expense from $636,625 to $420,401, which decreases the revenue requirement by $429,693; and
5.
Capital Structure is revised from a debt to equity ratio of 52/48 to a debt to equity ratio of 50/50, including Staff's Surrebuttal recommendation of 2.9% of short-term debt. This increases the revenue requirement by $782,400. The return on common equity is 9.50%, unchanged from Staff's position.
C.
Depreciation rates per Staff witness Wolfe Surrebuttal Exhibit GW-1 as derived from the parameters in Surrebuttal Exhibit GW-2.
                                                 
4 Sierra did not appear at or participate in the May 2 hearing.
5 Including one submission by AARP Arkansas with approximately 1,480 signatures on February 17, 2017, which urged the Commission to reject the "settlement." A settlement in this Docket was not filed until April 20, 2017.


Docket No. 16-052-U
Order No. 8
Page 5

COST ALLOCATION AND RATE DESIGN

A.
Use Staff's Cost of Service Study (COSS) as presented in Surrebuttal Exhibit MSK-1 of Staff witness Klucher for overall revenue distribution, updated to reflect the change to the wind jurisdictional allocator.
B.
Use OG&E's filed jurisdictional allocation factors derived using OG&E's billing determinants for calculating the jurisdictional cost allocations and use Staff's billing determinants for Arkansas rate class allocation and rate design per Staff witness Swaim's Surrebuttal. OG&E's proposal for "rebanding" the VPP prices is adopted and Staff's billing determinants for VPP will be adjusted accordingly, as proposed by OG&E witness Wai in Direct and Sur-surrebuttal. OG&E will restart the one-year "best bill" provision for all current VPP subscribers upon any changes to the Tier definitions consistent with the recommendation of Staff witness Swaim.
C.
Use the revenue mitigation plan per Staff witness Klucher in his Surrebuttal Testimony. No class shall receive a reduction in rates. Any reduction a class would have received will be applied so as to mitigate the impact to those classes receiving a rate increase.
D.
File Compliance tariffs as soon as practical.
E.
Set the customer charge for the Residential class at $9.75 per month; and the customer charge for the General Service class at $25.00 per month.
F.
Use Staff's recommendations for rate design.
G.
Adopt OG&E's proposal to merge PL-TOU-D and PL-TOU-E into a single PL-TOU tariff. Rate design for each class will not change during the annual FRP review.
H.
Adopt a demand and non-demand version of the Residential standard tariff and the General Service standard tariff, in accordance with the Rebuttal of OG&E witness Scott. The demand tariffs will be available as a voluntary option for Residential customers and General Service customers, respectively. In addition, OG&E will offer an initial one-year "best bill" provision for all Residential and General Service demand tariff subscribers.

OTHER ISSUES

A.
Make new rates effective for bills rendered on the first billing cycle after a Commission order approving the Agreement but not later than for bills rendered on June 1, 2017.
B.
Adopt the Formula Rate Plan Rider, which will reflect the fixed capital structure of 50% debt and 50% equity. The 50% debt portion will be made up of 47.1% long-term debt and 2.9% of short-term debt.
C.
Withdraw the Large Capital Additions Rider in this docket.
D.
Withdraw the Storm Damage Rider in this docket.

The Agreement was supported by Settlement Testimony of OG&E witness Rowlett; Walmart witness Chriss; ARVEC witness Blank; AG witness Shawn McMurray; and Staff witnesses Klucher, Hilton, and Powell.

For OG&E, witness Rowlett testifies that fundamentally, OG&E's rate design, detailed in the direct, rebuttal and sur-surrebuttal testimonies of Scott and Wai and agreed to by Staff witnesses Klucher and Swaim, has been adopted by the Settling Parties. He states that in addition, the Settling Parties have agreed that OG&E may offer optional Residential and General Service tariffs incorporating a demand charge. T. 621.

Mr. Rowlett observes that for the average customer, after consideration of all riders, the total bill impact by class is 9.1 % for Residential, 8.4% for General Service, and 1 % for Power & Light and Power


Docket No. 16-052-U
Order No. 8
Page 6

& Light Time of Use. He says this results in the average Residential customer increase of approximately $5.89 for a customer utilizing 1,000 kWh per month and an increase of approximately $9.65 for the average Commercial customer utilizing 1,800 kWh per month. T. 621-22.

Mr. Rowlett testifies that the optional Residential tariff with a demand charge (R-kW) is $1.00 per kW per month and that a typical Residential customer has a maximum monthly demand of 8.4 kW. He notes that the inclusion of a demand charge eliminates the need for block energy pricing in the Residential tariff. He verifies that customers who subscribe to the R-kW tariff will receive "best bill" protection for their initial year of service under the R-kW tariff, and the same applies to the General Service, which now includes a GS-kW optional rate. T. 622.

During the hearing Mr. Rowlett opined that changes to the bands or tiers in the VPP for residential and GS would be adjusted similar to the energy cost recovery (ECR) factors. T. 1229.

ARVEC witness Blank supports use of the demand allocator for jurisdictional allocation of the wind asset costs. He notes the Power & Light customers will not see a net bill increase but current revenues for these customers are over 6% higher than the settlement COSS results, which are used to mitigate the residential class' rate increase. He states the bill impacts to P&L TOU customers are minimal and the rate design to combine the PL-TOU-D and PL-TOU-E are acceptable. T. 1288-89.

Walmart witness Chriss testifies that the Agreement should be approved as a reasonable resolution of the issues as it is the result of arms-length negotiations and addresses Walmart's issues. T. 1895.

AG witness McMurray testifies that the Agreement addresses the AG's major concerns on revenue requirement in the following ways:
1.
It reduces the overall rate increase to OG&E customers to approximately $7.1 million - $9.4 million less than originally requested (less than half of the initial request), and $1.3 million less than recommended by Staff in Surrebuttal Testimony;
2.
It lowers the authorized ROE to 9.5%, far less than OG&E's initially requested 10.25%. While this is higher than the ROE recommended by the Attorney General and ARVEC, it is within the range of reasonableness of more than one expert's testimony;
3.
It reduces the percentage of equity in the accepted capital structure to 50% from the requested 53%. While this is more equity than recommended by all other parties, it falls within the range of reasonableness established in testimony; and
4.
The lower revenue deficiency also reflects several concessions on issues raised by the Attorney General and/ or ARVEC, including:
a.
It reflects a disallowance of a portion of incentive compensation based on financial goals in keeping with Commission precedent;
b.
It reflects disallowance of certain advertising and dues and donations costs that were either not necessary for utility service or did not benefit Arkansas ratepayers;
c.
It changes the jurisdictional allocation of wind generation so as not to allow OG&E to recover more than 100% of its wind costs because of differing jurisdictional allocation methods between Arkansas and Oklahoma; and
d.
It reduces the amount charged to ratepayers for OG&E's amortization of the cost of storm damage restoration. T. 2425-26.

He states that the allocation of the increase to the various classes contained in the Agreement represents substantial mitigation from both OG&E's and Staff's COSS, and all major rate classes see rate increases that


Docket No. 16-052-U
Order No. 8
Page 7

are lower than in Staff's Surrebuttal case. When one compares the respective class increases reflected in OG&E's initial application, the Staff's Surrebuttal cost of service study, and the Staff's recommended mitigation in its Surrebuttal, Mr. McMurray observes that the respective class allocations are well within the range of reasonable outcomes from litigation. He also notes that, when one considers the proposed reductions or elimination of some riders, the overall increase in residential bills will be 9.1%, compared to the 18.8% increase initially requested by OG&E and the 10.6% increase in Staff's Surrebuttal case, while GS bills will increase 8.4%, compared to the 15.9% increase initially requested by the Company and the 8.9% increase in Staff's Surrebuttal case. T. 2426-27.

Mr. McMurray points out that the Agreement specifically addresses the AG's other major concerns in the following ways:
1.
It declines to endorse the originally proposed FRP, but makes changes in methodology and procedures, including accepting a fixed capital structure;
2.
It does not include either of the two new riders that were opposed by the AG, LCA Rider and SDR Rider;
3.
Instead of the requested $11.80 residential customer's monthly service charge (and Staff's recommended $10.23 in surrebuttal), the Agreement limits the customer charge to $9.75; and instead of the requested $28.00 GS customer's monthly service charge (and Staff's recommended $26.36 in surrebuttal), the Agreement limits that customer charge to $25.00;
4.
The Agreement does not include a mandatory residential and GS demand charge, but instead includes only a voluntary demand charge, with a "best bill" provision, and keeps in place the current block structure for those two classes. T. 2427-28.

On behalf of Staff, Mr. Hilton testifies that the Arkansas Jurisdictional Retail Rate Schedule Revenue Requirement is $102,193,196, which is $5,968,293 less than the $108,161,489 requested by OG&E in its Revised Application, and $1,313,005 less than the $103,506,201 recommended by Staff in its Surrebuttal Testimony. He explains that the Revenue Deficiency resulting from the Agreement is $16,857,081, which excludes the revenue from the expiring riders being included in base rates of $9,741,043, and that including the expiring rider revenue results in a Revenue Deficiency of $7,116,038. T. 2668.

Mr. Hilton points out that the adjustment to Advertising Expense in Section 2 of the Agreement corrects an error of a duplicative reduction. He represents that the DPAD (Manufacturing Tax Deduction) is eliminated as OG&E is not eligible for the DPAD because it will continue to have a net operating loss carry-forward for tax purposes through 2019. He observes that the parties agreed to use a Demand Allocator (instead of energy) to allocate wind-related production plant and expense to the Arkansas jurisdiction. He notes that for the purpose of settlement, the parties agreed to revise the Debt to Equity Ratio to 50/50 and to use a three-year average of 2014-2016 storm costs (instead of 2012-2016). He concludes by indicating that the FRP is modified to include the terms of the Agreement. T. 2669-72.

Staff witness Klucher presents a summary of the Settlement COSS in his Table 1. He testifies that the Agreement allocates wind production assets between jurisdictions using the production demand allocation factor (consistent with the recommendation of ARVEC and the AG, and as used in Oklahoma), and the Arkansas jurisdictional amount is allocated to the classes based on the production energy allocation factor. He states that the mitigation of the revenue distribution to the classes follows the recommendation and principles set forth in his Surrebuttal. He summarizes the revenue distribution by customer group resulting from the Agreement in his Table 2. T. 2732-35.



Docket No. 16-052-U
Order No. 8
Page 8

Mr. Klucher testifies that the agreed-upon revenue requirement provides a reasonable approach towards aligning prices with the full COSS results while reflecting the gradualism principle. He notes that OG&E has not had a change in rates since its last rate case in Docket No. 10-067-U, approximately 6 years ago. Based on the time since OG&E's last increase, he calculates that the recommended overall increase of 4.2% equals a compound annual growth rate (CAGR) of 0.7% per year, with the agreed upon increase for the Residential class of 9.1% equaling a CAGR of 1.5% per year. He adds that the largest increase for any class based on the agreed upon approach is the Residential VPP class at 16.5%, or a CAGR of 2.6% per year. T. 2736.

Mr. Klucher explains that the agreed-upon Residential customer charge is $9.75, an increase of $1.81 (22.8%), and the General Service customer charge is $25.00, an increase of $3.25 (14.9%), both consistent with the recommendation made by Staff witness Swaim that the customer charge increase should be no more than the proposed class system average increase. He confirms that the Agreement adopts OG&E's proposal to merge the PL-TOU Demand and Energy tariffs into a single PL-TOU tariff and that OG&E will offer demand and non-demand rates for Residential and General Service customers which will be a voluntary option and include a one-year "best bill" provision. T. 2737-38.

At the hearing, Mr. Klucher confirmed that the optional tariffs for time of use, VPP, and demand will all have a "best bill" provision for the initial enrollment period of one year. The comparison for the "best bill" provision will be the tariff the customer is coming from. For new customers, he states that the comparison would be to the R-1 tariff. T. 3282-83. At the end of the year, the customer will receive a credit if the customer would have been better off on the otherwise applicable tariff but it is the customer's choice to stay or move to a different tariff. He explains that for the VPP tariff, the comparison will be between the new tiers and tariff the customer came from, but not the old VPP tiers, as a customer cannot go back to the old tiers. T. 3284-85. Mr. Klucher affirms that the procedure for changing the VPP tiers will be similar to the ECR procedure; he explains that the tariff is attempting to put a certain number of days in the different tiers, which will be spelled out in the tariff. T. 3286-87.

Also on behalf of Staff, Mr. Powell testifies that the Agreement accepts his recommended ROE of 9.50% for use in calculating the overall rate of return (ROR) and uses a hypothetical capital structure in determination of the ROR with a debt-to-equity (DTE) ratio of 50/50, which modified Staff's recommendation of 52/48. In evaluating his sample companies, he observes that the agreed-to DTE ratio falls within a reasonable band of central tendency for his sample companies' capital structures and thus he supports the 50/50 DTE ratio as reasonable. Therefore, he concludes that it is reasonable to use his recommended ROE of 9.50% in combination with a hypothetical capital structure with a 50/50 DTE ratio. T. 2974-75.

Mr. Powell notes that the adjusted external capital structure combined with the revised revenue conversion factor (RCF) from Staff's Settlement cost of service as supported by Staff witness Matthew S. Klucher produces an ROR of 5.42% after-tax and 7.68% pre-tax. He concludes that, consistent with Staff's position, the Agreement fixes the external capital structure in future FRP Rider filings to the DTE ratio, including the short-term debt percentage. T. 2975-76.

Concerning the Compliance Tariffs filed by OG&E, Staff witness Swaim explains the "best bill" provision for the voluntary Residential Service Demand, Residential Service Time-of-Use, Residential Service Variable Peak Pricing (R-VPP), General Service Time-of-Use Rate, General Service Variable Peak Pricing (GS-VPP), General Service Demand, and Flex Pricing rates found in Compliance Tariff Sheets No. 4.1, 7.2, 8.3, 11.1, 13.3, 14.1, and 46.5. He verifies that the Compliance Tariffs filed by OG&E on May 8, 2017, properly incorporate the requirements of the Agreement and that the Compliance Tariffs replace all of


Docket No. 16-052-U
Order No. 8
Page 9

the pages of the current tariffs. He recommends approval effective for bills rendered on and after the first billing cycle following Commission approval of revised rates in this Docket. Swaim Compliance Testimony at 3-5.

Findings and Conclusions

After considering all of the pre-filed testimony and exhibits and the testimony of the witnesses who appeared at the hearing on May 2, 2017, along with the public comments made in the Docket, the Commission approves the Agreement.

The Commission finds that the evidence presented supports the proposed revenue requirement as this falls within the range supported by the testimonies filed in this Docket.

The Commission finds that the ROE of 9.5% stipulated in the Agreement is within the range of reasonable ROEs proposed by several parties but lower than the rate requested by OG&E. The settlement ROE of 9.5% considers the varying analyses presented by the parties. Likewise, the agreed-to capital structure of a 50% debt to 50% equity ratio is reasonable and falls within the range for sample companies and as suggested by the parties. It is reasonable to use the settlement ROE in combination with the settlement debt-to-equity ratio.

The Commission finds that the depreciation rates adopted by the Agreement are reasonable.

The Commission accepts the use of a demand allocator (instead of energy, and consistent with its use in Oklahoma) to allocate wind-related production plant and expense to the Arkansas jurisdiction. The Commission accepts the class revenue requirement allocation embodied in the Agreement; makes no finding regarding cost allocation methodologies; and makes no finding regarding the applicability and meaning of Act 725 as it pertains to cost allocation for production demand costs for electric utilities. The evidence confirms that the resulting allocation is consistent with previous Commission decisions that no individual customer class should receive a rate decrease when there is an overall rate increase. The resulting allocation additionally mitigates the impact on Municipal Pumping, Athletic Field Lighting, and Residential customers by applying any revenue surplus attributable to classes that have no change in current revenues. The overall 7.5% increase in rate schedule revenues (including expiring rider revenues) and a system average increase of 4.2% (9.1% for residential) provides a reasonable approach towards aligning prices with the full cost of service study results while reflecting the gradualism approach. Accordingly, the Commission finds that the Agreement results in a class revenue requirement allocation that is just, reasonable, and in the public interest.

The average increase in base rates for all classes is reasonable considering the offsetting effect of the riders. The overall increase of 4.2%, which equates to a compound annual growth rate of 0.7% per year since OG&E's last rate case, is reasonable. In its Application, OG&E requested a rate increase which would have resulted in a net increase of $15.28 to a typical monthly residential bill for a customer using 1,000 kWh; the Agreement as proposed instead results in an increase of $5.89. Increases to customer charges for the residential and GS rate classes are consistent with Staff's recommendation that the customer charge increase should be no more that the proposed class system average increase and represent a more gradual change to minimize customer impact. For the residential class, the agreed-to customer charge of $9.75 is an increase of $1.81, but less than the $11.80 requested by OG&E. Likewise, for the GS class, the agreed-to customer charge of $25.00 is an increase of $3.25, but less than the $28.00 requested by OG&E.



Docket No. 16-052-U
Order No. 8
Page 10

The Agreement's proposal for OG&E to offer optional demand rates for residential and GS customers, along with a "best bill" provision, increases options for those customers with minimal risk and is therefore in the public interest. Likewise, the "best bill" provision available upon changes to the tier definitions in the VPP rates also increases options for those customers while minimizing risk and is therefore in the public interest.

Therefore, the rate design is reasonable as it balances cost-based rates with customer impact.

The Commission finds that Rider FRP as proposed in the Agreement is reasonable. Rider FRP was revised to address concerns of the parties and its design and protocols appear to provide a reasonable framework to implement and administer OG&E's FRP under Act 725. Use of the fixed debt-to-equity ratio within Rider FRP is reasonable and consistent with other FRPs adopted by the Commission.

Accordingly, based upon the totality of the evidence presented in this Docket, the Commission finds that the Agreement is just and reasonable and in the public interest. As such, the Commission directs and orders as follows:
1.
The Agreement is approved.
2.
The compliance tariffs filed on May 8, 2017, are approved effective for bills rendered on and after the first billing cycle after this order.


Docket No. 16-052-U
Order No. 8
Page 11




BY ORDER OF THE COMMISSION
 
This 18th day of May, 2017.
 
 
/s/ Ted. J. Thomas
 
Ted J. Thomas, Chairman
 
/s/ Elana C. Wills
 
Elana C. Wills, Commissioner
 
/s/ Kimberly A. O'Guinn
 
Kimberly A. O'Guinn, Commissioner
/s/ Karen Shook
 
Secretary of the Commission
 



Exhibit

BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION

IN THE MATTER OF THE APPLICATION         )
OF OKLAHOMA GAS AND ELECTRIC            )
COMPANY FOR APPROVAL OF A            )
GENERAL CHANGES IN RATES, CHARGES        )    DOCKET NO. 16-052-U
AND TARIFFS                        )

JOINT MOTION TO APPROVE THE SETTLEMENT
AGREEMENT AND FOR THE EXCUSAL OF WITNESSES

Come now Oklahoma Gas and Electric Company (OG&E), the Office of Arkansas Attorney General Leslie Rutledge (AG), Wal-Mart Stores Arkansas, LLC, and Sam’s West, Inc. (collectively “Walmart”), Arkansas River Valley Energy Consumers (ARVEC), and the General Staff (Staff) of the Arkansas Public Service Commission (Commission), (hereinafter referred to as the Settling Parties), and for their Joint Motion to Approve the Settlement Agreement and for the Excusal of Witnesses (Joint Motion) state as follows:

1.     The Settling Parties have reached agreement on the issues outstanding in this docket. This agreement is set forth in the Stipulation and Settlement Agreement (Agreement) attached hereto as a Joint Exhibit. The Settling Parties support the Agreement as a reasonable resolution of the issues in this docket and as being in the public interest. The Agreement, inter alia, establishes OG&E’s revenue requirement in total, the assignment of the revenue among the rate classes, and the rate design for each class.
2. As support for the Agreement and concurrent with the filing of this Joint Motion, the following witnesses are sponsoring Settlement Testimonies:

OG&E:    Donald R. Rowlett    
AG:        M. Shawn McMurray    
Wal-Mart:    Steve W. Chriss
ARVEC:    Larry Blank
Staff:        Matthew S. Klucher, Jeff Hilton, and Regis Powell    

3. The Settling Parties recommend that the current procedural schedule should remain in effect so that the Agreement can be considered at the evidentiary hearing set to begin at 9:30 a.m. on May 2, 2017, in the Hearing Room, Arkansas Public Service Commission Building, 1000 Center Street, Little Rock, Arkansas, for the purpose of considering the merits of the Agreement, taking opening statements, and receiving testimony and public comments. The Settling Parties request that on or before April 25, 2017, all witnesses who filed written testimony in this docket, except for those who are sponsoring settlement testimony, be excused from appearing at the evidentiary hearing on May 2, 2017.
4.    Sierra Club has indicated to counsel for Staff that Sierra Club takes no position on the Agreement.


1


WHEREFORE, the Settling Parties request that the Commission issue an order approving the Agreement attached hereto in consideration of the request for a general change in rates, charges and tariffs; an order excusing all witnesses who filed written testimony in this docket, except for those who are sponsoring settlement testimony; and an order granting all other necessary and proper relief.

Respectfully submitted,

OKLAHOMA GAS AND ELECTRIC COMPANY
                            
By:     /s/ Lawrence Chisenhall, Jr.
Lawrence Chisenhall, Jr.
ABN 74023
Barber Law Firm PLLC
425 West Capitol Ave.
Suite 3400
Little Rock, AR 72201

OFFICE OF ARKANSAS ATTORNEY GENERAL LESLIE RUTLEDGE

By:     /s/ Kevin Lemley
Kevin Lemley, ABN 2005034
Assistant Attorney General
Office of Arkansas Attorney General
323 Center Street, Suite 200
Little Rock, AR 72201
(501) 682-3625
keven.lemley@arkansasag.gov

WAL-MART STORES ARKANSAS, LLC AND SAM’S WEST, INC.
                        
By:    /s/ Rick Chamberlain
Rick Chamberlain
Oklahoma Bar Association No. 11255
State Bar of Texas No. 24081827
Behrens, Wheeler & Chamberlain
6 N.E. 63rd Street, Suite 400
Oklahoma City, OK 73105





2


ARKANSAS RIVER VALLEY ENERGY CONSUMERS
                        
By:    /s/ Thomas Schroedter
Thomas Schroedter, ABN 2015019
Hall Estill Law Firm
320 S. Boston, Suite 200
Tulsa, OK 74103
                                                
GENERAL STAFF OF THE ARKANSAS
PUBLIC SERVICE COMMISSION

By:     /s/ Justin A. Hinton
Justin A. Hinton, ABN 2010025
Christina Baker, ABN 2016001
Staff Attorneys
1000 Center Street
P.O. Box 400
Little Rock, AR 72203-0400
(501) 682-5766
jhinton@psc.state.ar.us






CERTIFICATE OF SERVICE

I, Justin A. Hinton, hereby certify that a copy of the foregoing has been served on all parties of record by electronic mail via the Electronic Filing System this 20th day of April, 2017.


/s/ Justin A. Hinton
Justin A. Hinton




3



BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION

IN THE MATTER OF THE APPLICATION OF        )
OKLAHOMA GAS AND ELECTRIC COMPANY     )
FOR APPROVAL OF A GENERAL CHANGE IN        )    DOCKET NO. 16-052-U
RATES, CHARGES AND TARIFFS                )


SETTLEMENT AGREEMENT

Come now the General Staff of the Arkansas Public Service Commission (“Staff”), Oklahoma Gas and Electric Company (“OG&E”), the Office of the Attorney General Leslie Rutledge (“AG”), the intervenor, Arkansas River Valley Energy Consumers (“ARVEC”), and the intervenors Wal-Mart Stores Arkansas, LLC and Sam’s West Inc. (“Wal-Mart”), hereinafter collectively referred to as “the Settling Parties”, agree to the following terms in settlement of all outstanding issues in the above-referenced Docket. Though Sierra Club is a party to this Docket, they are not a Settling Party, and takes no position on this Agreement.

1. PROCEDURAL SCHEDULE AND RECORD DEVELOPMENT:

OG&E proposed a level of revenue requirement, corresponding rates, and other items in its Application and Direct Testimonies and Exhibits filed August 25, 2016. After conducting extensive discovery, Staff, the AG, ARVEC, and Wal-Mart filed Direct Testimony on January 31, 2017. OG&E filed Rebuttal Testimony on February 28, 2017. Staff, the AG, and ARVEC filed Surrebuttal Testimony on March 30, 2017. OG&E filed Sur-surrebuttal Testimony on April 6, 2017.

The Record has been developed fully as reflected in the filed testimonies and exhibits. In pursuit of settlement, a complete discussion of the issues outstanding was undertaken among the Settling Parties, each being a strong advocate for its respective position. The result is that the Settling Parties to this Agreement have agreed to settle this case in its entirety based on Staff’s recommendations advanced in its Surrebuttal Testimonies and Exhibits, except as indicated below.

2. REVENUE REQUIREMENT:

A.The Settling Parties agree that OG&E's Arkansas jurisdictional base rate revenue requirement is $102,193,196 with a resulting revenue deficiency of $7,116,038 as shown in Settlement Attachment No. 1.
B.While the agreed-upon revenue requirement reflects a negotiated settlement of all revenue requirement issues, the Settling Parties agree that the revenue deficiency and revenue requirement were developed based on Staff's March 30, 2017 Surrebuttal revenue requirement and related recommendations adjusted only as listed below:

1


1.
OG&E’s Advertising adjustment IS-13 is changed from a decrease of $3,296,900 to a decrease of $957,693. This results in an increase to the revenue requirement of $162,772;
2.
The Revenue Conversion Factor ("RCF") is increased by 0.0247. This change is the result of removing the Domestic Production Activities Deduction (“DPAD”) from the RCF, thereby increasing the revenue requirement by $274,009;
3.
The Wind Jurisdictional Allocator is changed from an Energy Allocator of 10.29% to a Demand Allocator of 8.49%, resulting in a decrease to the revenue requirement of $2,102,493;
4.
The Company’s adjustment IS-32 reflects a reduction in Storm Damage expense from $636,625 to $420,401, which decreases the revenue requirement by $429,693; and
5.
Capital Structure is revised from a debt to equity ratio of 52/48 to a debt to equity ratio of 50/50, including Staff's Surrebuttal recommendation of 2.9% of short-term debt. This increases the revenue requirement by $782,400. The return on common equity is 9.50%, unchanged from Staff’s position. The impact of the change to the Capital Structure on the Overall Rate of Return is reflected below.
Overall Rate of Return
Component
Amount
Proportion
Rate
Wtd Cost
Pre-tax
 
 
 
 
 
 
Long Term Debt
$
2,677,668,289

33.76
%
5.68
%
1.92
%
1.92
%
Short Term Debt
$
167,385,484

2.11
%
0.76
%
0.02
%
0.02
%
Common Equity
$
2,885,956,621

36.38
%
9.50
%
3.46
%
5.72
%
Customer Deposits
$
77,441,663

0.98
%
1.47
%
0.01
%
0.01
%
Accumulated Deferred Income Taxes
$
1,812,510,927

22.85
%
0.00
%
0.00
%
0.00
%
Post-1970 ADITC - Long Term Debt
$
1,124,268

0.01
%
5.68
%
0.00
%
0.00
%
Post-1970 ADITC - Short Term Debt
$
70,280

0.00
%
0.76
%
0.00
%
0.00
%
Post-1970 ADITC - Equity
$
1,211,721

0.02
%
9.50
%
0.00
%
0.00
%
Current, Accrued and Other Liabilities
$
301,022,589

3.79
%
0.00
%
0.00
%
0.00
%
Other Capital Items
$
8,082,810

0.10
%
8.53
%
0.01
%
0.01
%
 
 
 
 
 
 
Total
$
7,932,474,651

100.00
%
 
5.42
%
7.68
%
 
 
 
 
 
 
Revenue Conversion Factor
1.6519

 
Wtd Cost/Debt
1.96
%
 

C.The Settling Parties agree the Commission should approve the depreciation rates sponsored by Staff witness Gerrilynn Wolfe, which reflect the depreciation rates proposed in Surrebuttal Exhibit GW-1 as derived from the parameters in Surrebuttal Exhibit GW-2.


2

3. COST ALLOCATION AND RATE DESIGN:

A.The Settling Parties agree, for purposes of settlement, to use as a starting point in setting the overall revenue distribution the Customer Class Cost of Service Study (COS Study), which was developed using the allocation methods and factors embodied in Staff’s COS Study as presented in Surrebuttal Exhibit MSK-1 of Staff witness Matthew S. Klucher.1 This COS Study has been updated to reflect the change to the wind jurisdictional allocator as described in Section 2.B.3 and is set forth in Settlement Attachment No. 1 to the Agreement. A more detailed presentation by rate class is set forth in Settlement Attachment No. 2 to the Agreement.
B.The Settling Parties agree to use OG&E’s filed jurisdictional allocation factors derived using OG&E’s billing determinants for calculating the jurisdictional cost allocations and agree to use Staff’s billing determinants for Arkansas rate class allocation and rate design as recommended by Staff witness Robert H. Swaim in his Surrebuttal Testimony and exhibits and workpapers. The Company’s proposal for “rebanding” the variable peak pricing ("VPP") prices is adopted and the Staff’s billing determinants for VPP will be adjusted accordingly, as proposed by the Company in the Direct and Sur-surrebuttal testimony of Company witness William Wai. In addition, the Company will restart the one year best bill provision for all current VPP subscribers consistent with the recommendation of Staff witness Swaim.
C.The Settling Parties adopt the revenue mitigation plan as presented by Staff witness Matthew S. Klucher in his Surrebuttal Testimony. No class shall receive a reduction in rates. Any reduction a class would have received will be applied so as to mitigate the impact to those classes receiving a rate increase. The resulting agreed-upon rate schedule revenue requirement for each customer class is set forth in the Settlement Attachment No. 3 to the Agreement and is as summarized follows:
Revenue Requirement by Rate Class2
Rate Class
Revenue Requirement
Increase
Residential
$38,919,157
$5,051,207
General Service
$11,861,458
$1,426,447
Power & Light
$28,342,896
$504,015
Power & Light-TOU
$19,865,717
$113,196
Lighting
$3,069,643
$0
Municipal Pumping
$71,136
$11,212
Athletic Field Lighting
$63,189
$9,960
Total AR Retail
$102,193,196
$7,116,038
 
 
 
D.The Settling Parties agree that the Company will file compliance tariffs as soon as practical after the filing of this Agreement. The compliance tariff to be filed will reflect a rate design consistent with the terms of this Agreement. Staff will use its best efforts to work with the Company to insure that the tariffs are consistent with the Agreement.
E.The Settling Parties agree that the customer charge for the Residential class will be $9.75 per month; the customer charge for the General Service class will be $25.00 per month.
                                       
1 While the AG accepts the COS as a starting point, and accepts the mitigated class revenue distribution set forth below in paragraph 3.C. below, the AG does not endorse the allocation methods and factors embodied in Staff's COS Study.
2 The source of the table is the updated Surrebuttal Exhibit MSK-3, which reflects the terms of the Settlement Agreement, as updated by Staff witness Klucher as Attachment No. 3.

3

F.The Settling Parties agree that OG&E’s rate design will comply with Staff’s recommendations.
G.The Settling Parties agree to adopt OG&E’s proposal to merge PL-TOU-D and PL-TOU-E into a single PL-TOU tariff. The Settling Parties understand that, pursuant to Ark. Code Ann. §23-4-1207(d) and Attachment F of the FRP Rider, the rate design for each class will not change during the annual formula rate plan review proceeding.
H.The Settling Parties agree that OG&E will offer a demand and non-demand version of the Residential standard tariff and the General Service standard tariff, in accordance with the Rebuttal Testimony of Bryan Scott. The demand tariffs will be available as a voluntary option available to Residential customers and General Service customers, respectively. In addition, the Company will offer an initial one year best bill provision for all Residential and General Service demand tariff subscribers.

4. OTHER ISSUES:

A.OG&E requests, and the Settling Parties do not object, that the new rates become effective for bills rendered on the first billing cycle after a Commission order approving the Agreement but not later than for bills rendered on June 1, 2017.
B.The Settling Parties agree that OG&E will be regulated under the Formula Rate Rider, which will reflect the fixed capital structure of 50% debt and 50% equity. The 50% debt portion will be made up of 47.1% long-term debt and 2.9% of short-term debt. The Formula Rate Plan tariff, reflecting these changes is attached as Settlement Attachment No. 4.
C.OG&E agrees not to seek the Large Capital Additions Rider in this Docket.
D.OG&E agrees not to seek the Storm Damage Rider in this Docket.

5. RIGHTS OF THE SETTLING PARTIES:

A.This Agreement is made upon the explicit understanding that it constitutes a negotiated settlement which is in the public interest. Nothing herein shall constitute an admission of any claim, defense, rule or interpretation of law, allegation of fact, principle, or method of ratemaking or cost-of-service determination or rate design, or cost of service allocation methods or factors or terms or conditions of service, or the application of any rule or interpretation of law, that may underlie, or be perceived to underlie, this Agreement.
B.This Agreement is expressly contingent upon its approval by the Commission without any modification. The various provisions of the Agreement are interdependent and unseverable. All parties shall cooperate fully in seeking the Commission's approval of the Agreement. The parties shall not support any alternative proposal or settlement agreement while this Agreement is pending before the Commission.
C.Except as to matters specifically agreed to be done or occur in the future, no party shall be precluded from taking any position on the merits of any issue in any subsequent proceeding in any forum. This Agreement shall not be used or argued as establishing precedent for any methodology or rate treatment in any future proceeding.
D.In the event the Commission does not accept, adopt, and approve this Agreement in its entirety and without modification, the Settling Parties agree that this Agreement may be declared void and of no effect by any party. In that event, however, the Settling Parties

4

agree that: (a) no party shall be bound by any of the provisions or agreements hereby contained; (b) all parties shall be deemed to have reserved all their respective rights and remedies in this proceeding; and
(c) no party shall introduce this Agreement or any related writings, discussions, negotiations, or other communications of any type in any proceeding.

Respectfully submitted,


GENERAL STAFF OF THE ARKANSAS
PUBLIC SERVICE COMMISSION
                            
By: /s/ Justin A. Hinton
    Staff Attorney
Justin Hinton (AR Bar No. 2010025)
1000 Center Street
P.O. Box 400            
Little Rock, AR 72203-0400
(501) 682-5878
                    



OKLAHOMA GAS & ELECTRIC CO.
                            
By: /s/ Lawrence E. Chisenhall, Jr.
Lawrence E. Chisenhall, Jr.
(AR Bar No. 74023)
BARBER LAW FIRM PLLC
425 W. Capitol Avenue, Ste. 3400
Little Rock, AR 72201
(501) 372-6175


ATTORNEY GENERAL OF ARKANSAS

By: /s/ Kevin Lemley
Kevin Lemley, ABN 2005034
Assistant Attorney General
Office of Arkansas Attorney General
323 Center Street, Suite 200
Little Rock, AR 72201
(501) 682-3625
keven.lemley@arkansasag.gov


5


ARKANSAS RIVER VALLEY ENERGY CONSUMERS    

By: /s/ Thomas P. Schroedter
Thomas P. Schroedter
(AR Bar No. 2015019)
Hall, Estill
320 S. Boston Avenue, Ste. 200
Tulsa, OK 74103
(918) 594-0436






WAL-MART STORES ARKANSAS LLC AND SAM’S WEST, INC.

By: /s/ Rick D. Chamberlin
Rick D. Chamberlin
(OK Bar No. 11255)    
BEHRENS, WHEELER & CHAMBERLIN        
6 N.E. 63rd Street, Ste. 400
Oklahoma City, OK 73105    
(405) 848-1014






6
Settlement Attachment No.1

Line No
Description
Total Company
Other Jurisdiction
Arkansas Jurisdiction
Residential Service
General Service
Power & Light
Power & Light TOU
Municipal Pumping
Athletic Field Lighting
Lighting
1
RATE BASE
 
 
 
 
 
 
 
 
 
 
2
  GROSS PLANT IN SERVICE
9,773,423,395

9,012,434,318

760,989,077

306,174,350

87,892,472

212,427,185

129,696,902

642,402

856,009

23,299,756

3
  ACCUMULATED DEPRECIATION
3,888,033,928

3,581,366,635

306,667,293

123,614,188

35,581,954

83,835,822

53,712,401

224,403

288,118

9,410,407

4
    NET PLANT
5,885,389,467

5,431,067,683

454,321,784

182,560,162

52,310,519

128,591,364

75,984,501

417,999

567,891

13,889,349

5
  WORKING CAPITAL ASSETS
440,490,777

396,602,990

43,887,787

15,880,445

4,622,081

12,535,951

10,032,503

32,025

32,893

751,888

6
  OTHER RATE BASE ITEMS
100,222,430

91,717,308

8,505,122

3,337,451

971,391

2,323,112

1,807,404

2,460

2,353

60,950

7
TOTAL RATE BASE
6,426,102,674

5,919,387,981

506,714,693

201,778,058

57,903,991

143,450,427

87,824,408

452,484

603,137

14,702,188

 
 
 
 
 
 
 
 
 
 
 
 
8
NON-FUEL OPERATING REVENUES
 
 
 
 
 
 
 
 
 
 
9
  RETAIL PRESENT RATE SCHEDULE REV
1,258,701,086

1,173,364,971

85,336,115

30,861,067

9,518,040

24,749,924

17,112,925

56,598

50,596

2,986,964

10
  OTHER OPERATING REVENUES
16,435,643

16,109,462

326,181

173,153

35,010

73,802

38,072

373

393

5,378

11
TOTAL OPERATING REVENUE
1,275,136,729

1,189,474,434

85,662,296

31,034,221

9,553,050

24,823,727

17,150,997

56,970

50,989

2,992,342

 
 
 
 
 
 
 
 
 
 
 
 
12
EXPENSES
 
 
 
 
 
 
 
 
 
 
13
  OPERATION & MAINTENANCE EXPENSE
388,318,033

349,907,837

38,410,196

17,297,011

4,616,513

9,881,403

6,166,089

32,662

34,228

382,290

14
  DEPRECIATION & AMORTIZATION EXPENSE
301,168,404

278,367,263

22,801,141

9,030,651

2,573,615

6,132,695

3,884,236

18,609

22,572

1,138,763

15
  TAXES OTHER THAN INCOME TAXES
80,466,699

73,988,274

6,478,425

2,567,063

729,967

1,819,336

1,210,844

4,932

5,974

140,309

16
TOTAL OPERATING EXPENSES
769,953,136

702,263,373

67,689,762

28,894,725

7,920,095

17,833,434

11,261,168

56,202

62,775

1,661,363

17
INCOME TAXES
117,800,237

117,086,947

713,289

(1,684,005
)
(83,559
)
948,103

1,212,046

(5,357
)
(12,165
)
338,227

18
TOTAL EXPENSES
887,753,372

819,350,320

68,403,052

27,210,720

7,836,536

18,781,538

12,473,215

50,845

50,610

1,999,590

 
 
 
 
 
 
 
 
 
 
 
 
19
OPERATING INCOME
387,383,357

370,124,113

17,259,244

3,823,501

1,716,515

6,042,189

4,677,782

6,125

379

992,752

20
Earned Return on Rate Base
6.028
%
6.253
%
3.406
%
1.895
%
2.964
%
4.212
 %
5.326
 %
1.354
%
0.063
%
6.752
 %
 
 
 
 
 
 
 
 
 
 
 
 
21
COST OF SERVICE REVENUE REQUIREMENT
 
 
 
 
 
 
 
 
 
 
22
Required Return on Rate Base
 
 
5.420
%
5.420
%
5.420
%
5.420
 %
5.420
 %
5.420
%
5.420
%
5.420
 %
23
Required Operating Income (L7*L22)
 
 
27,463,936

10,936,371

3,138,396

7,775,013

4,760,083

24,525

32,690

796,859


1
Settlement Attachment No.1

24
Income Deficiency (Surplus)(L23-L19)
 
 
10,204,692

7,112,870

1,421,882

1,732,824

82,300

18,400

32,311

(195,894
)
25
Revenue Conversion Factor
 
 
1.65190

1.65412

1.64811

1.64562

1.64562

1.64560

1.64560

1.64560

 
 
 
 
 
 
 
 
 
 
 
 
26
Revenue Deficiency/(Surplus)(L24*L25)
 
 
16,857,081

11,765,568

2,343,417

2,851,574

135,435

30,279

53,171

(322,363
)
27
Rate Schedule Revenue Requirement (L9+L26)
 
 
102,193,196

42,626,636

11,861,458

27,601,498

17,248,361

86,876

103,767

2,664,601

 
 
 
 
 
 
 
 
 
 
 
 
28
Fuel Revenues @ Present Rates
 
 
62,947,816

17,781,470

5,414,557

19,394,616

19,542,498

30,570

24,198

759,907

29
Other Riders @ Present Rates
 
 
20,292,209

6,903,104

2,077,992

6,377,331

4,738,814

8,376

6,758

179,835

30
Other Riders @ Proposed Rates
 
 
10,551,167

3,896,222

1,161,022

3,288,375

2,099,218

5,050

4,125

97,155

31
Expiring Riders @ Present Rates
 
 
9,741,043

3,006,882

916,970

3,088,956

2,639,596

3,326

2,633

82,680

 
 
 
 
 
 
 
 
 
 
 
 
32
% Increase on Present Rate Schedule Revenue (L26/L9)
 
 
19.75
%
38.12
%
24.62
%
11.52
 %
0.79
 %
53.50
%
105.09
%
(10.79
)%
33
% Increase on Present Rate Sch Rev+Fuel Rev (L26/(L9+L28))
 
 
11.37
%
24.19
%
15.69
%
6.46
 %
0.37
 %
34.74
%
71.09
%
(8.60
)%
34
% Increase on Pres Rate Sch Rev + Fuel Rev + Other Riders ((L26-L31)/(L11+L28+L29))
 
 
4.21
%
15.72
%
8.37
%
(0.47
)%
(6.04
)%
28.10
%
61.67
%
(10.30
)%
 
 
 
 
 
 
 
 
 
 
 
 
35
Total Revenue Requirement (L10+L27+L28+L30)
 
 
176,018,359

64,477,480

18,472,046

50,358,291

38,928,148

122,869

132,483

3,527,041

 
 
 
 
 
 
 
 
 
 
 
 
 
SETTLEMENT PROPOSED REVENUE REQUIREMENT
 
 
 
 
 
 
 
 
 
 
36
Proposed Base Rate Revenue Requirement
 
 
102,193,196

38,919,157

11,861,458

28,342,896

19,865,717

71,136

63,189

3,069,643

37
Total Proposed Revenue Requirement (L10+L36+L28+L30)
 
 
176,018,359

60,770,001

18,472,046

51,099,688

41,545,505

107,129

91,905

3,932,084

38
% Increase on Total Revenue Requirement
 
 
4.21
%
9.07
%
8.37
%
1.00
 %
0.27
 %
11.69
%
12.15
%
0.00
 %
 
 
 
 
 
 
 
 
 
 
 
 
39
Revenue Deficiency/(Surplus) less Expiring Riders (L26-L31)
 
 
7,116,038

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2
Settlement Attachment No.2

Settlement COS Study Results By Rate Class
Rate Class
COS Rate Schedule Revenue Requirement
Present Rate Schedule Revenues
Total Revenue Requirement
Without Expiring Rider Revenues
With Expiring Rider Revenues
Current
Net Increase
% Change
Current
Net Increase
% Change
Current
COS
Net Increase
% Change
(a)
(b)
(c)
(d)=(b)-(c)
(e)=(d)/(c)
(f)
(g)=(b)-(f)
(h)=(g)/(f)
(i)
(j)
(k)=(j)-(i)
(l)=(k)/(i)
Residential S/L 5
$38,572,943
$28,536,404
$10,036,538
35.2%
$31,226,598
$7,346,344
23.5%
$50,770,900
$58,117,245
$7,346,344
14.5%
Residential TOU
$670,997
$406,730
$264,267
65.0%
$452,439
$218,558
48.3%
$785,952
$1,004,510
$218,558
27.8%
Residential VPP
$3,382,696
$1,917,933
$1,464,763
76.4%
$2,188,913
$1,193,784
54.5%
$4,161,942
$5,355,725
$1,193,784
28.7%
Total Res
$42,626,636
$30,861,067
$11,765,568
38.1%
$33,867,950
$8,758,686
25.9%
$55,718,794
$64,477,480
$8,758,686
15.7%
 
 
 


 


 
 


General Service S/L 2
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
General Service S/L 3
$26,084
$20,988
$5,096
24.3%
$24,010
$2,074
8.6%
$43,829
$45,903
$2,074
4.7%
General Service S/L 5
$11,161,280
$9,000,380
$2,160,900
24.0%
$9,845,909
$1,315,371
13.4%
$15,941,352
$17,256,723
$1,315,371
8.3%
General Service S/L TOU
$129,938
$114,156
$15,783
13.8%
$127,800
$2,138
1.7%
$225,221
$227,359
$2,138
0.9%
General Service S/L VPP
$544,156
$382,517
$161,638
42.3%
$437,292
$106,864
24.4%
$835,198
$942,062
$106,864
12.8%
Total GS
$11,861,458
$9,518,040
$2,343,417
24.6%
$10,435,010
$1,426,447
13.7%
$17,045,599
$18,472,046
$1,426,447
8.4%
 
 
 


 


 
 


Power&Light S/L 1
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
Power&Light S/L 2
$1,149,038
$1,314,810
$(165,772)
(12.6)%
$1,482,689
$(333,650)
(22.5)%
$3,039,397
$2,705,747
$(333,650)
(11.0)%
Power&Light S/L 3
$7,348,640
$6,753,480
$595,159
8.8%
$7,702,238
$(353,598)
(4.6)%
$14,676,421
$14,322,822
$(353,598)
(2.4)%
Power&Light S/L 4
$117,864
$164,527
$(46,663)
(28.4)%
$172,013
$(54,149)
(31.5)%
$220,540
$166,391
$(54,149)
(24.6)%
Power&Light S/L 5
$18,985,956
$16,517,107
$2,468,849
14.9%
$18,481,940
$504,015
2.7%
$32,659,314
$33,163,330
$504,015
1.5%
Total Power&Light
$27,601,498
$24,749,924
$2,851,574
11.5%
$27,838,880
$(237,382)
(0.9)%
$50,595,673
$50,358,291
$(237,382)
(0.5)%
 
 
 


 


 
 


PL TOU S/L 1
$6,111,969
$6,780,392
$(668,422)
(9.9)%
$7,773,758
$(1,661,788)
(21.4)%
$18,700,642
$17,038,854
$(1,661,788)
(8.9)%
PL TOU S/L 2
$900,077
$1,040,267
$(140,190)
(13.5)%
$1,258,353
$(358,276)
(28.5)%
$2,569,120
$2,210,844
$(358,276)
(13.9)%
PL TOU S/L 3
$6,731,922
$6,315,166
$416,756
6.6%
$7,329,215
$(597,293)
(8.1)%
$13,843,191
$13,245,898
$(597,293)
(4.3)%
PL TOU S/L 4
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
PL TOU S/L 5
$3,504,392
$2,977,101
$527,291
17.7%
$3,391,196
$113,196
3.3%
$6,319,356
$6,432,552
$113,196
1.8%
Total PL TOU
$17,248,361
$17,112,925
$135,435
0.8%
$19,752,521
$(2,504,161)
(12.7)%
$41,432,309
$38,928,148
$(2,504,161)
(6.0)%
 
 
 


 


 
 


MP S/L 4
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
MP S/L 5
$86,876
$56,598
$30,279
53.5%
$59,924
$26,953
45.0%
$95,916
$122,869
$26,953
28.1%
Total MP
$86,876
$56,598
$30,279
53.5%
$59,924
$26,953
45.0%
$95,916
$122,869
$26,953
28.1%
 
 
 


 


 
 


Ath Field Lighting
$103,767
$50,596
$53,171
105.1%
$53,229
$50,538
94.9%
$81,945
$132,483
$50,538
61.7%

1
Settlement Attachment No.2

Total AFL
$103,767
$50,596
$53,171
105.1%
$53,229
$50,538
94.9%
$81,945
$132,483
$50,538
61.7%
 
 
 


 


 
 


Municipal Lighting
$914,981
$1,057,315
$(142,334)
(13.5)%
$1,083,231
$(168,250)
(15.5)%
$1,353,702
$1,185,452
$(168,250)
(12.4)%
Outdoor Lighting
$1,749,620
$1,929,649
$(180,029)
(9.3)%
$1,986,412
$(236,793)
(11.9)%
$2,578,382
$2,341,589
$(236,793)
(9.2)%
Total Lighting
$2,664,601
$2,986,964
$(322,363)
(10.8)%
$3,069,643
$(405,043)
(13.2)%
$3,932,084
$3,527,041
$(405,043)
(10.3)%
 
 
 


 


 
 


Total Arkansas
$102,193,196
$85,336,115
$16,857,081
19.8%
$95,077,158
$7,116,038
7.5%
$168,902,321
$176,018,359
$7,116,038
4.2%


2
Settlement Attachment No.3


Revenue Allocation - Settlement Proposed Revenue Requirement for Rate Design by Rate Class
Rate Class
COS Rate Schedule Revenue Requirement
Proposed Rate Schedule Revenue Requirement
Present Rate Schedule Revenues
Total Revenue Requirement
Without Expiring Rider Revenues
With Expiring Rider Revenues
Current
Net Increase
% Change
Current
Net Increase
% Change
Current
Proposed
Net Increase
% Change
(a)
(b)
(c)
(d)
(e)=(c)-(d)
(f)=(e)/(d)
(g)
(h)=(c)-(g)
(i)=(h)/(g)
(j)
(k)
(l)=(k)-(j)
(m)=(l)/(j)
Residential S/L 5
$38,572,943
$35,463,296
$28,536,404
$6,926,892
24.3%
$31,226,598
$4,236,698
13.6%
$50,770,900
$55,007,598
$4,236,698
8.3%
Residential TOU
$670,997
$578,483
$406,730
$171,753
42.2%
$452,439
$126,044
27.9%
$785,952
$911,996
$126,044
16.0%
Residential VPP
$3,382,696
$2,877,378
$1,917,933
$959,445
50.0%
$2,188,913
$688,465
31.5%
$4,161,942
$4,850,407
$688,465
16.5%
Total Res
$42,626,636
$38,919,157
$30,861,067
$8,058,089
26.1%
$33,867,950
$5,051,207
14.9%
$55,718,794
$60,770,001
$5,051,207
9.1%
 
 
 
 
 
 
 
 
 
 
 
 
 
General Service S/L 2
$0
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
General Service S/L 3
$26,084
$26,084
$20,988
$5,096
24.3%
$24,010
$2,074
8.6%
$43,829
$45,903
$2,074
4.7%
General Service S/L 5
$11,161,280
$11,161,280
$9,000,380
$2,160,900
24.0%
$9,845,909
$1,315,371
13.4%
$15,941,352
$17,256,723
$1,315,371
8.3%
General Service S/L TOU
$129,938
$129,938
$114,156
$15,783
13.8%
$127,800
$2,138
1.7%
$225,221
$227,359
$2,138
0.9%
General Service S/L VPP
$544,156
$544,156
$382,517
$161,638
42.3%
$437,292
$106,864
24.4%
$835,198
$942,062
$106,864
12.8%
Total GS
$11,861,458
$11,861,458
$9,518,040
$2,343,417
24.6%
$10,435,010
$1,426,447
13.7%
$17,045,599
$18,472,046
$1,426,447
8.4%
 
 
 
 

 
 
 
 
 
 
 
 
Power&Light S/L 1
$0
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
Power&Light S/L 2
$1,149,038
$1,482,689
$1,314,810
$167,879
12.8%
$1,482,689
$0
—%
$3,039,397
$3,039,397
$0
—%
Power&Light S/L 3
$7,348,640
$7,702,238
$6,753,480
$948,758
14.0%
$7,702,238
$0
—%
$14,676,421
$14,676,421
$0
—%
Power&Light S/L 4
$117,864
$172,013
$164,527
$7,486
4.6%
$172,013
$0
—%
$220,540
$220,540
$0
—%
Power&Light S/L 5
$18,985,956
$18,985,956
$16,517,107
$2,468,849
14.9%
$18,481,940
$504,015
2.7%
$32,659,314
$33,163,330
$504,015
1.5%
Total Power&Light
$27,601,498
$28,342,896
$24,749,924
$3,592,971
14.5%
$27,838,880
$504,015
1.8%
$50,595,673
$51,099,688
$504,015
1.0%
 
 
 
 

 
 
 
 
 
 
 
 
PL TOU S/L 1
$6,111,969
$7,773,758
$6,780,392
$993,366
14.7%
$7,773,758
$0
—%
$18,700,642
$18,700,642
$0
—%
PL TOU S/L 2
$900,077
$1,258,353
$1,040,267
$218,086
21.0%
$1,258,353
$0
—%
$2,569,120
$2,569,120
$0
—%
PL TOU S/L 3
$6,731,922
$7,329,215
$6,315,166
$1,014,049
16.1%
$7,329,215
$0
—%
$13,843,191
$13,843,191
$0
—%
PL TOU S/L 4
$0
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
PL TOU S/L 5
$3,504,392
$3,504,392
$2,977,101
$527,291
17.7%
$3,391,196
$113,196
3.3%
$6,319,356
$6,432,552
$113,196
1.8%
Total PL TOU
$17,248,361
$19,865,717
$17,112,925
$2,752,792
16.1%
$19,752,521
$113,196
0.6%
$41,432,309
$41,545,505
$113,196
0.3%
 
 
 
 

 
 
 
 
 
 
 
 
MP S/L 4
$0
$0
$0
$0
—%
$0
$0
—%
$0
$0
$0
—%
MP S/L 5
$86,876
$71,136
$56,598
$14,539
25.7%
$59,924
$11,212
18.7%
$95,916
$107,129
$11,212
11.7%
Total MP
$86,876
$71,136
$56,598
$14,539
25.7%
$59,924
$11,212
18.7%
$95,916
$107,129
$11,212
11.7%
 
 
 
 

 
 
 
 
 
 
 
 
Ath Field Lighting
$103,767
$63,189
$50,596
$12,593
24.9%
$53,229
$9,960
18.7%
$81,945
$91,905
$9,960
12.2%

1
Settlement Attachment No.3


Total AFL
$103,767
$63,189
$50,596
$12,593
24.9%
$53,229
$9,960
18.7%
$81,945
$91,905
$9,960
12.2%
 
 
 
 

 
 
 
 
 
 
 
 
Municipal Lighting
$914,981
$1,083,231
$1,057,315
$25,916
2.5%
$1,083,231
$0
—%
$1,353,702
$1,353,702
$0
—%
Outdoor Lighting
$1,749,620
$1,986,412
$1,929,649
$56,763
2.9%
$1,986,412
$0
—%
$2,578,382
$2,578,382
$0
—%
Total Lighting
$2,664,601
$3,069,643
$2,986,964
$82,680
2.8%
$3,069,643
$0
—%
$3,932,084
$3,932,084
$0
—%
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Arkansas
$102,193,196
$102,193,196
$85,336,115
$16,857,081
19.8%
$95,077,158
$7,116,038
7.5%
$168,902,321
$176,018,359
$7,116,038
4.2%


2

ARKANSAS PUBLIC SERVICE COMMISSION
Original
Sheet No. 80.0
 
Replacing ________
Sheet No. ___
 
OKLAHOMA GAS AND ELECTRIC COMPANY
Name of Company
 
Kind of Service: Electric
Class of Service: All
 
Part I. Rate Schedule No. FRP
 
Title: Formula Rate Plan Rider
PSC File Mark Only
80.0    FORMULA RATE PLAN RIDER
80.1
REGULATORY AUTHORITY
The Arkansas General Assembly has delegated authority to the Arkansas Public Service Commission (“APSC” or the “Commission”) to regulate public utilities in the State of Arkansas, including Oklahoma Gas & Electric (“OG&E” or the “Company”). The Arkansas General Assembly has enacted the Formula Rate Review Act, Ark. Code Ann. §§ 23-4-1201 et seq., which authorizes use of this Formula Rate Plan Rider tariff (“FRP”).
80.2
PURPOSE
The FRP defines the procedure by which all rates and applicable riders (Rate Schedules) on file with the APSC, except those excluded in Attachment A.1 to this FRP, may be periodically adjusted. The FRP shall apply to all electric service billed under the Rate Schedules, whether metered or unmetered.
80.3
DEFINITIONS
A.
EFFECTIVE DATE
Rates pursuant to the initial FRP shall become effective with the first billing cycle of April 2019 and subsequently adjusted FRP rates shall be effective with the first billing cycle of each successive projected year.
B.
FORMULA RATE REVIEW TEST PERIOD
The Formula Rate Review Test Period shall be a test period based upon a Projected Year. A Projected Year shall be the twelve (12) month period ending March 31 of the 2nd year following the filing of an Evaluation Report.
C.
HISTORICAL YEAR
A Historical Year shall be the twelve (12) month period ended March 31 immediately preceding the filing of an Evaluation Report.
D.
FILING YEAR
The Filing Year shall be the twelve (12) months preceding the Formula Rate Review Test Period.

1


ARKANSAS PUBLIC SERVICE COMMISSION
Original
Sheet No. 80.1
 
Replacing ________
Sheet No. ___
 
OKLAHOMA GAS AND ELECTRIC COMPANY
Name of Company
 
Kind of Service: Electric
Class of Service: All
 
Part I. Rate Schedule No. FRP
 
Title: Formula Rate Plan Rider
PSC File Mark Only

80.4
ANNUAL FILING AND REVIEW
A.
ANNUAL FILING
On or about October 1, 2018 and on or about October 1 of each subsequent year, OG&E shall file a report (“Evaluation Report”) with the Commission containing an evaluation of the Company’s earnings pursuant to the FRP for the Formula Rate Review Test Period and the Historical Year when applicable. Attachment A-1 shall be included in each such filing and shall contain the Company’s proposed Rate Adjustment. The Evaluation Report and the Rate Adjustment shall be filed pursuant to the FRP.
B.
REVIEW PERIOD
The Parties shall file a statement of error(s) or objection(s) and supporting Testimony with or without Exhibits at least 90 days before the date on which the Rate Adjustment becomes effective. The Company shall have fifteen (15) days to review the statement of error(s) or objection(s), to work with the Parties to resolve any differences, and to address the error(s) and objection(s) raised by the Parties by filing either a corrected Attachment A.1 or Rebuttal Testimony with or without Exhibits.
C.
HEARING AND APPROVAL OF RATE ADJUSTMENT
Following a hearing at least fifty (50) days before the date on which the Rate Adjustment shall become effective, unless waived by OG&E and the Parties, the Commission shall issue a final order in which it resolves any issues in dispute and approves the Rate Adjustment at least twenty (20) days before the date on which the Rate Adjustment shall become effective. If a final order is not issued by such date, the initially filed or revised Rate Adjustment shall become effective for bills rendered on and after the first billing cycle of April, subject to refund, and shall remain in effect until changed by final order of the Commission or by operation of other provisions of this FRP.
If the Commission’s final ruling on any disputed issues requires changes to the Rate Adjustment, the Company shall file a revised Attachment A-1 containing such further modified Rate Adjustment within five (5) days after receiving the Commission’s order resolving the disputed issues. The Parties shall have three (3) days to review the revised Attachment A-1. The revised Attachment A-1 shall be implemented as ordered by the Commission.

2

ARKANSAS PUBLIC SERVICE COMMISSION
Original
Sheet No. 80.2
 
Replacing ________
Sheet No. ___
 
OKLAHOMA GAS AND ELECTRIC COMPANY
Name of Company
 
Kind of Service: Electric
Class of Service: All
 
Part I. Rate Schedule No. FRP
 
Title: Formula Rate Plan Rider
PSC File Mark Only

80.5
ANNUAL DETERMINATION OF RATE ADJUSTMENT
80.5.1.
INDEX OF ATTACHMENTS
Attachment
Description
Projected Year
Historical Year
A-1
FRP Rate Adjustment (Rate Adjustment).
x
 
A-2
FRP Revenue Change and includes the calculation of the total FRP Revenue to be collected in the Projected Year.
x
 
B-1, D-1
Earned Rate of Return (“ERR”) on Common Equity. The ERR is the Company’s return on common equity calculated by dividing the weighted earned common equity rate by the common equity ratio percentage.
B-1
D-1
B-2, D-2
Rate Base
B-2
D-2
B-3, D-3
Operating Income
B-3
D-3
B-4, D-4
Income Tax
B-4
D-4
B-5, D-5
Benchmark Rate of Return on Rate Base (“BRORB”). The BRORB is the composite weighted, embedded cost of capital reflecting OG&E’s annual costs of long-term debt, preferred stock, common equity, and other capital components as of September 30.
B-5
D-5
B-6, D-6
Revenue Redetermination Formula using the Rate of Return on Common Equity Bandwidth which is an Upper Bandwidth limit equal to the Target Return Rate (TRR) plus 0.5% (50 basis points) and a Lower Bandwidth limit equal to the TRR minus 0.5% (50 basis points). The TRR is the Company’s cost rate for common equity as established by the Commission in Docket No. 16-052-U.
B-6
D-6
C
FRP Adjustments
x
x
E
FRP Filing Requirements and description of the supporting documents to be included with the annual Evaluation Report.
x
x
F
Formula Rate Protocols which include the FRP general provisions and filing requirements for the annual Evaluation Report.
x
x



3

ARKANSAS PUBLIC SERVICE COMMISSION
Original
Sheet No. 80.3
 
Replacing ________
Sheet No. ___
 
OKLAHOMA GAS AND ELECTRIC COMPANY
Name of Company
 
Kind of Service: Electric
Class of Service: All
 
Part I. Rate Schedule No. FRP
 
Title: Formula Rate Plan Rider
PSC File Mark Only

80.5.2.
FRP BANDWIDTH CALCULATION
The Total FRP revenue level shall be adjusted in the FRP review mechanism based on a comparison of the ERR to the TRR calculated using the following formula:
A.
If the ERR is less than the TRR minus five-tenths percent (0.50%), the Total FRP Revenue level shall be increased by the amount necessary to increase the ERR to the TRR.
B.
If the ERR is greater than the TRR plus five-tenths percent (0.50%), the Total FRP Revenue level shall be decreased by the amount necessary to decrease the ERR to the TRR.
C.
There shall be no change to the FRP Revenue level if the ERR is less than or equal to the TRR plus five-tenths percent (0.50%), and greater than or equal to the TRR minus five-tenths percent (0.50%).
80.5.3.
NETTING OF HISTORICAL YEAR DIFFERENCES ADJUSTMENT
The Netting of Historical Year Differences Adjustment shall be the adjustment to net any differences between the Historical Year change in FRP Revenue and the Formula Rate Review Test Period change in FRP revenue for that same year. The Netting of Historical Year Differences Adjustment shall be determined in accordance with Attachment D-6. The Netting of Historical Year Differences Adjustment shall then be applied to the Formula Rate Review Test Period FRP Revenue to derive the Total FRP Revenue as set out in Attachment A-2. Netting shall not begin until there is an actual twelve (12) months of Historical Year to report.
80.5.4.
FRP REVENUE ALLOCATION
The total change in the formula rate revenue level shall be allocated to each applicable rate class based on an equal percentage of the base rate revenue used in the development of rates approved by the Commission in Docket No. 16-052-U. The total amount of such revenue increase or decrease for each rate class shall not exceed four percent (4%) of each rate class’s revenue for the Filing Year.
80.6
TERM
The initial term of the FRP rider shall not exceed five (5) years from the date of the Commission’s final order in Docket No. 16-052-U. If OG&E requests an extension of the FRP rider, OG&E shall make such request in accordance with the Extension of Term provisions of the Formula Rate Protocols.
If the FRP is not extended, the then-existing Total FRP rates shall continue to be in effect until new base rates reflecting the then-existing Total FRP Revenue are duly approved and implemented and until the Company recovers or returns the remaining Netting of Historical Year Differences Adjustments.



4
Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment A-1
Formula Rate Plan Rate Adjustment
All retail base rates and applicable riders on file with the APSC will be increased or decreased by a percentage of base revenues listed below, except those specifically excluded below:
Rate Class
FRP Rate (%)
Residential
XX.XXXX%
General Service
XX.XXXX%
Power and Light
XX.XXXX%
Other*
XX.XXXX%
*Other includes Municipal Water Pumping, Municipal Roadway and Area Lighting, Outdoor Security Lighting, Athletic Field Lighting, and the LED lighting rates
Excluded Schedules:        Energy Cost Recovery Rider (ECR)
Energy Efficiency Cost Recovery Rider (EECR)
Transmission Cost Recovery Rider (TCR)
Environmental Compliance Plan Rider (ECP)
Day-Ahead Pricing (DAP) (DAP energy component only)
Flex Pricing (FP) (FP energy component only)
Rider for Municipal Tax Adjustment (MTA)
Renewable Energy Program Rider (REP)
Load Reduction Rider (LR)

Special Rate Contracts:
Special Contracted Rates shall be included or excluded pursuant to the terms of the Special Rate Contract.

5

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment A-2
FRP Rider Revenue Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line No.
Description
Total
Residential
General Service
Power and Light
Other
A
B
C
D
E
F
H
 
 
 
 
 
 
 
1
Base Rate Revenues: Docket No. 16-052-U
$102,193,196
$38,919,157
$11,861,458
$48,208,613
$3,203,968
2
Rate Class Allocation:(Percent of total calculated from L1)
 
38.08%
11.61%
47.17%
3.14%
3
FRP Constraint Calculation [1] x                                                                                         
 
 
 
 
 
4
Total Annualized Filing Year Revenues by Rate Class
 
 
 
 
 
5
FRP Revenue Change = ±4% per Rate Class
 
4.00%
4.00%
4.00%
4.00%
6
+Projected Year upper FRP Revenue Constraint
 
-
-
-
-
7
-Projected Year lower FRP Revenue Constraint
 
-
-
-
-
8
Net Change in Req. FRP Revenue Calc [2]
 
 
 
 
 
9
ROE Bandwidth Rate Adjustment (B.6 L10 * L2)
 
 
 
 
 
10
Netting Adjustment (D.6 L13 * L2)
 
 
 
 
 
11
Net Change in Required FRP Revenue
 
 
 
 
 
 
 
 
 
 
 
 
12
Incremental FRP Base Rate Change
 
 
 
 
 
 
(L11 ÷ (L1 + L14))
13
Cumulative FRP Revenue Calculation [3] x                                                                                                                                  
 
 
 
 
 
14
Maximum Inc/Dec in FRP Revenue calculated on L11 bounded by the constraint defined on L6 and L7.
 
 
 
 
 
15
Annualized Filing Year FRP Rider Revenue [4]
 
 
 
 
 
16
Cumulative Total FRP Rider revenue (L14+L15)
 
 
 
 
 
17
FRP Rate Development Calculation [5]
 
 
 
 
 
18
Projected Year Base Rate Revenue (B.3 L2)
 
 
 
 
 
 
 
 
 
 
 
 
19
FRP Projected Year Rate Change (L16 ÷ L18)
 
 
 
 
 
NOTES:
 
 
 
 
 
[1]
 
The FRP Constraint Calculation determines the limit of the FRP revenue increase/decrease per rate class, which shall not exceed four percent (4%) of Total Unadjusted Annualized Filing Year (the year in which the Evaluation Report is filed) revenues.
[2]
 
The Net Change in Required FRP Revenue Calculation takes the Total Projected Year Rate Change in FRP Revenue (B.6 Line 10) and the Historical Year Netting adjustment (D.6 Line 13) and allocates the amount required to each rate class based on the class allocation approved by the Commission in Docket No. 16-052-U listed on Line 2. The amounts required are added together by rate class to determine each rate class' net change in required FRP revenue. The netting adjustment on line 10 shall be zero (0) until there is an actual twelve (12) months of Historical Year data to report.
[3]
 
The Cumulative FRP revenue calculation adjusts the Required FRP revenue determined on Line 11 to be within the limits of the FRP constraint calculation and adds the Annualized Filing Year FRP Revenues to calculate Cumulative Total FRP Revenue required in the Projected Year.
[4]
 
The Annualized Filing Year FRP Rider Revenue in the initial Filing Year will be zero ($0). In subsequent Filing Years, the Annualized Filing Year FRP Rider Revenue will include actual FRP Rider revenues collected in the Filing Year (up to the latest month the Company has actual data for) to calculate the Annualized FRP Rider Revenue amount to be used in the Cumulative FRP Rider Revenue Calculation.
[5]
 
The FRP Rider Rate Development Calculation determines the percent increase/decrease that will be applied to all base rate components not listed as an excluded schedule on Attachment A-1. The percent increase/decrease is calculated by taking the Total FRP Rider Revenue listed on Line 16 and dividing it by the Adjusted Projected Year Revenues listed in Line 18.

6

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment B-1
Oklahoma Gas & Electric
Formula Rate Plan
Earned Rate of Return on Common Equity Formula
For the Projected Year xxxx
 
 
 
 
 
 
 
 
Line
Description
Source
Adjusted
No
 
 
Amount
TOTAL COMPANY
 
 
 
 
1
RATE BASE
B-2, Line 25
 
2
BENCHMARK RATE OF RETURN ON RATE BASE
B-5, Line 12, Column F
 
 
 
 
 
3
REQUIRED OPERATING INCOME
Line 1 * Line 2
 
4
NET UTILITY OPERATING INCOME
B-3, Line 30
 
5
OPERATING INCOME DEFICIENCY/(EXCESS)
Line 3 - Line 4
 
6
REVENUE CONVERSION FACTOR
Note [1]
 
7
REVENUE DEFICIENCY/(EXCESS)
Line 5 * Line 6
 
 
PRESENT RATE REVENUES
 
 
8
RETAIL RATE SCHEDULE REVENUE
B-3, Line 2
 
9
WHOLESALE SALES
B-3, Line 3
 
10
REVENUE REQUIREMENT
Line 7 + Line 8 + Line 9
 
 
 
 
 
TOTAL ARKANSAS RETAIL
 
 
 
 
11
REVENUE REQUIREMENT ALLOCATION FACTOR
Line 12/Line 10
 
12
RETAIL REVENUE REQUIREMENT
Note 2
 
13
RETAIL RATE SCHEDULE REVENUE
B-3, Line 2
 
14
RETAIL REVENUE DEFICIENCY/(EXCESS)
Line 12 - Line 13
 
15
REVENUE CONVERSION FACTOR
Note [1]
 
16
RETAIL OPERATING INCOME DEFICIENCY/(EXCESS)
Line 14 / Line 15
 
17
RATE BASE ALLOCATION FACTOR
Line 18/Line1
 
18
RETAIL RATE BASE
Note [3]
 
19
COMMON EQUITY DEFICIENCY/(EXCESS) (%)
Line 16 / Line 18
 
20
WEIGHTED EVALUATION PERIOD COST RATE FOR COMMON EQUITY (%)
B-5, Line 3, Column F
 
21
WEIGHTED EARNED COMMON EQUITY RATE (%)
Line 20 - Line 19
 
22
COMMON EQUITY RATIO (%)
B-5, Line 3, Column C
 
23
EARNED RATE OF RETURN ON COMMON EQUITY (%)
Line 21 / Line 22
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
[1]
Revenue Conversion Factor = 1 / [(1 - Composite Tax Rate (Net of Manufacturing Tax Deduction only if OGE, as a stand-alone company, has taxable income available for the Projected Year) * (1 - Bad Debt)].
 
 
 
 
 
[2]
Arkansas Jurisdictional Revenue Requirement as determined by running the total company projected costs through the approved Cost of Service model from Docket No. 16-052-U.
 
 
 
 
[3]
Arkansas Jurisdictional Rate Base as determined by running the total company projected costs through the approved Cost of Service model from Docket No. 16-052-U.

7

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment B-2
Oklahoma Gas & Electric
Formula Rate Plan
Rate Base
For the Projected Year xxxx
 
 
 
 
 
 
 
 
 
 
 
 
Line
 
 
Projected Year
Adjustments
Adjusted Projected Year
No
 
Description
 
 
 
 
 
 
A
B [1]
C
 
 
 
 
 
 
1
PLANT IN SERVICE
 
 
 
2
 
Beginning Balance
 
 
 
3
 
Ending Balance
 
 
 
4
 
Average Balance
 
 
 
 
 
 
 
 
 
5
ACCUMULATED DEPRECIATION
 
 
 
6
 
Beginning Balance
 
 
 
7
 
Ending Balance
 
 
 
8
 
Average Balance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
 
AVERAGE NET UTILITY PLANT (L4 +L8)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10
PLANT ACQUISITION ADJUSTMENT
 
 
 
11
 
Beginning Balance
 
 
 
12
 
Ending Balance
 
 
 
13
 
Average Balance
 
 
 
 
 
 
 
 
 
14
 AMORTIZATION OF ACQUISITION ADJ
 
 
 
 
15
 
Beginning Balance
 
 
 
16
 
Ending Balance
 
 
 
17
 
Average Balance
 
 
 
 
 
 
 
 
 
18
 WORKING CAPITAL ASSETS:
  MATERIALS AND SUPPLIES
  PREPAYMENTS
     FUEL INVENTORY
     WORKING CASH
          TOTAL WORKING CAPITAL ASSETS
 
 OTHER
 
 
 TOTAL RATE BASE (L9+L13+L17+L23+L24)
 
 
 
 
19
 
 
 
20
 
 
 
21
 
 
 
22
 
 
 
23
 
 
 
 
 
 
 
24
 
 
 
 
 
 
 
25
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
 
[1]
Adjustments as set out in Attachment C to this FRP.
 
 

8

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment B-3
Oklahoma Gas & Electric
Formula Rate Plan
Operating Income
For the Projected Year xxxx
 
 
 
 
 
 
 
 
 
 
Line
 
Adjusted Historical Year
Adjustments
Adjusted Projected Year
No
Description
 
 
 
 
 
A [1]
B [2]
C
 
 
 
 
 
 
REVENUES
 
 
 
1
SALES TO ULTIMATE CUSTOMERS
 
 
 
2
RETAIL RATE SCHEDULE REVENUE
 
 
 
3
WHOLESALE SALES
 
 
 
4
TOTAL SALES TO ULTIMATE CUSTOMERS (L2 + L3)
 
 
 
 
 
 
 
 
5
OTHER SALES REVENUE
 
 
 
6
OTHER ELECTRIC REVENUE
 
 
 
7
TOTAL OPERATING REVENUES (Sum of L4 thru L6)
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
8
OPERATION & MAINTENANCE
 
 
 
9
PRODUCTION
 
 
 
10
TRANSMISSION
 
 
 
11
REGIONAL MARKET
 
 
 
12
DISTRIBUTION
 
 
 
13
CUSTOMER ACCOUNTING
 
 
 
14
CUSTOMER SERVICE & INFORMATION
 
 
 
15
SALES
 
 
 
16
ADMINISTRATIVE & GENERAL
 
 
 
17
TOTAL O&M EXPENSE (Sum of L9 thru L16)
 
 
 
 
 
 
 
 
18
GAIN FROM DISPOSITION OF ALLOWANCES
 
 
 
19
REGULATORY DEBITS & CREDITS
 
 
 
20
 DEPRECIATION & AMORTIZATION EXPENSES 
 
 
 
21
ACCRETION EXPENSES
 
 
 
22
AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT
 
 
 
23
OTHER CREDIT FEES
 
 
 
24
TAXES OTHER THAN INCOME
 
 
 
25
CURRENT STATE INCOME TAX [3]
 
 
 
26
CURRENT FEDERAL INCOME TAX [3]
 
 
 
27
GAIN/LOSS – DISPOSITION OF UTILITY PLANT
 
 
 
28
OTHER
 
 
 
29
TOTAL UTILITY OPERATING EXPENSE (Sum of L17 thru L28)
 
 
 
 
 
 
 
 
30
NET UTILITY OPERATING INCOME (L7 – L29)
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
 
[1]
Reference Attachment D-3.
 
 
 
[2]
Adjustments as set out in Attachment C to this FRP.
 
 
 
[3]
Reference Attachment B-4
 
 
 

9

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment B-4
 
 
 
 
 
Oklahoma Gas & Electric
Formula Rate Plan
Income Tax
For the Projected Year xxxx
 
 
 
 
 
 
 
 
 
 
Line
 
Projected Year
Adjustments
Adjusted Projected Year
No
Description
 
 
 
 
 
A
B [1]
C
 
 
 
 
 
1
TOTAL OPERATING REVENUES
 
 
 
 
 
 
 
 
2
TOTAL O&M EXPENSE
 
 
 
3
GAIN FROM DISPOSITION OF ALLOWANCES
 
 
 
4
REGULATORY DEBITS AND CREDITS
 
 
 
5
DEPRECIATION & AMORTIZATION EXPENSE
 
 
 
6
ACCRETION EXPENSE
 
 
 
7
AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT
 
 
 
8
OTHER CREDIT FEES
 
 
 
9
TAXES OTHER THAN INCOME
 
 
 
10
GAIN/LOSS – DISPOSITION OF UTILITY PLANT
 
 
 
11
OTHER
 
 
 
12
INTEREST EXPENSE [2]
 
 
 
 
 
 
 
 
13
NET INCOME BEFORE INCOME TAXES (L1- (Sum L2-L12))
 
 
 
 
 
 
 
 
14
ADJUSTMENTS TO NET INCOME BEFORE TAXES [3]
 
 
 
15
TAXABLE INCOME (L13 + L14)
 
 
 
 
 
 
 
 
 
COMPUTATION OF STATE INCOME TAX
 
 
 
 
 
 
 
 
16
TAXABLE INCOME (L15)
 
 
 
17
STATE ADJUSTMENTS [3]
 
 
 
18
STATE TAXABLE INCOME (L16 + L18)
 
 
 
19
STATE INCOME TAX BEFORE ADJUSTMENTS (L18 * Tax Rate) [1]
 
 
 
20
ADJUSTMENTS TO STATE TAX [3]
 
 
 
21
STATE INCOME TAX (L19 + L20)
 
 
 
 
 
 
 
 
 
COMPUTATION OF FEDERAL INCOME TAX
 
 
 
 
 
 
 
 
22
TAXABLE INCOME (L15)
 
 
 
23
STATE INCOME TAX BEFORE ADJUSTMENTS (L19)
 
 
 
24
FEDERAL ADJUSTMENTS [3]
 
 
 
25
TOTAL FEDERAL TAXABLE INCOME (L22- L23 +L24)
 
 
 
26
FEDERAL INCOME TAX BEFORE ADJUSTMENTS (L25 * Tax Rate) [1]
 
 
 
27
ADJUSTMENTS TO FEDERAL TAX [3]
 
 
 
28
FEDERAL INCOME TAX (L26 + L27)
 
 
 
 
 
 
 
 
Notes:
 
 
 
[1]
Adjustments and applicable tax rate as set out in Attachment C to this FRP.
 
 
[2]
Interest Expense for Col. C is Weighted Cost of Debt (COD) Rate as derived from COD elements reflected in Attachment B-5 x Rate Base per Attachment B-2, Column C.
 
 
[3]
List all adjustments including descriptions in a supporting schedule.
 
 
 
 
 
 
 
 

10

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment B-5
Oklahoma Gas & Electric
Formula Rate Plan
Benchmark Rate of Return on Rate Base
For the Projected Year xxxx
 
 
 
 
 
 
(A)
(B)
(C)
(D)
(E)
(F)
 
 
 
 
 
Benchmark
 
 
Capital
Capital
Cost
Rate Of
 
 
Amount ($)
Ratio (%)
Rate (%)
Return On
Line No.
Description
[1]
[2]
[3]
Rate Base [4]
 
 
 
 
 
 
1
Long-Term Debt
 
 
 
 
2
Preferred Stock
 
 
 
 
3
Common Equity
 
 
 
 
4
Accumulated Deferred Income Taxes
 
 
 
 
5
Pre-1971 ADITC
 
 
 
 
6
Post-1970 ADITC
 
 
 
 
7
Customer Deposits
 
 
 
 
8
Short-Term/Interim Debt
 
 
 
 
9
Current Accrued, and Other Liabilities
 
 
 
 
10
Capital Leases
 
 
 
 
 
 
 
 
 
 
11
Other Capital Items
 
 
 
 
 
 
 
 
 
 
12
Total
 
 
 
 
Notes:
 
 
 
 
 
[1]
The capital balances for Long-Term Debt, Capital Leases, Preferred Equity, Common Equity and Other Capital shall be mid-year (September 30) balances adjusted to reflect any intercompany payables balances using a 13 month average, if applicable, consistent with Commission Order in Docket No. 16-052-U. Support for the 13 month average of the intercompany payables calculations shall be provided. The total debt-to-equity ratio (DTE) for external capital, including the short-term debt percentage of 2.9%, shall be fixed at 50/50, consistent with Commission Order in Docket No. 16-052-U. Capital amounts shall include mid-year (September 30) balances for Post-1970 Investment Tax Credits, Customer Deposits, and Short-Term debt balances, beginning and ending year average for Accumulated Deferred Income Tax (ADIT), and 13-month average balances for Current, Accrued and Other Liabilities (CAOL), if applicable. A September 30 balance sheet should be provided as well as a reconciliation between the balance sheet and Column (C) amounts. Support for the CAOL balances shall include the same format and detail as required by the Filing Requirements in Attachment E, Item No. 15.

[2]
Capital amounts each divided by the Total Capital Amount.
[3]
The cost rates shall be calculated in accordance with the calculation applied by the Commission in Docket No. 16-052-U. Support for the cost of Long-Term debt and cost of Preferred Stock shall be provided in the same format and level of detail required by the Filing Requirements, respectively. Support for the Short-Term debt cost rate and the DOE Obligation cost rate, if applicable, should include a general description of how the interest rate is determined and the same level of detail provided in the Filing Requirements in Attachment E, Item No. 15. The cost rate for Customer Deposits shall be the Commission-approved rate in effect during the year. The Cost Rate for Common Equity shall be that approved by Commission Order in Docket No. 16-052-U.
[4]
The components in Column F are the corresponding Cost Rates multiplied by the associated Capital Ratio.

11

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80



Attachment B-6
 
Oklahoma Gas & Electric
 
 
Formula Rate Plan
 
 
FRP Revenue Redetermination Formula
 
 
For the Projected Year xxxx
 
 
 
 
 
 
 
 
 
 
 
SECTION 1
 
 
 
 
 
 
BANDWIDTH DEVELOPMENT
 
 
Line
 
 
 
 
 
 
 
 
No
 
DESCRIPTION
 
REFERENCE
 
 
 
 
1
 
Earned Rate of Return on Common Equity ("ERR") [1]
 
B-1, Line 23
 
 
 
 
2
 
Target Return Rate ("TRR") [2]
 
B-5, Line 3, Column E
 
 
 
 
3
 
Upper Bandwidth Limit
 
Line 2 + 0.50%
 
0.50
 %
 
 
4
 
Lower Bandwidth Limit
 
Line 2 - 0.50%
 
-0.50
 %
 
 
5
 
ROE Adjustment
 
If L1 < L4, then L2 - L1; If L1 > L3, then L2 - L1, but no adjustment if L1 ≥ L4 or L1 ≤ L3
 
 
 
 
 
 
 
 
 
 
 
 
 
SECTION 2
 
 
 
 
 
 
ROE BANDWIDTH RATE ADJUSTMENT
 
 
 
 
 
Line
 
 
 
 
 
 
 
 
No
 
DESCRIPTION
 
REFERENCE
 
 
 
 
6
 
ROE Adjustment
 
Per Line 5
 
 
 
 
7
 
Common Equity Capital Ratio
 
B-5, Line 3, Column D
 
 
 
 
8
 
Retail Rate Base
 
B-1, Line 18
 
 
 
 
9
 
Revenue Conversion Factor
 
B-1, Line 15
 
 
 
 
10
 
Total Rate Change in FRP Revenue
 
Line 6 * Line 7 * Line 8 * Line 9
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
 
 
 
[1]
 
The ERR is the Earned Rate of Return on Common Equity, calculated by dividing the weighted earned common equity rate by the common equity ratio percentage.
 
 
[2]
 
The TRR is the Company's cost rate for common equity as established by the Commission in Docket No. 16-052-U.
 

12

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment C
Oklahoma Gas & Electric
FORMULA RATE PLAN ADJUSTMENTS

The amounts reflected in Attachments B and D shall be adjusted to reflect the following:

I.
General

A)
The rate base, revenue and expense effects associated with riders which recover specific costs or other rate mechanisms the utility may have in effect shall not be included in the Formula Rate Plan Projected and Historical Year periods.

B)
The Historical Year balance sheet shall be the source for rate base and capital for the Historical Year used in Attachment D. The Historical Year income statement shall be the source for revenue and expense amounts used in Attachment D.

C)
The Historical Year shall be adjusted to remove rider revenue and expenses, remove amounts, or otherwise make adjustments, consistent with the most recent general rate case, and other adjustments as described in Attachment C.

D)
The Company’s Projected Year will be built utilizing Historical Year data adjusted for reasonably known and measurable changes and will include other adjustments as documented in this Attachment C

E)
The Projected Year shall be adjusted to remove rider revenue and expenses, remove amounts, or otherwise make adjustments, consistent with the Commission’s Order in Docket No. 16-052-U, and other adjustments as described in Attachment C.

F)
Rate base amounts for both the Historical Year and the Projected Year shall exclude construction work in progress (CWIP), Non-Utility Plant, and Plant Held for Future Use. Plant and Accumulated Depreciation amounts for both the Historical Year and the Projected Year shall be adjusted to remove Asset Retirement Obligations.

G)
No adjustments shall be made in either the Projected or Historical Year to annualize any expense.

H)
During the term of the FRP the Lost Contribution to Fixed Costs portion of the utility’s Energy Efficiency Rider shall be set to zero.

I)
The revenue conversion factor in Attachment B for the Projected Year, shall only include the manufacturing tax deduction if OG&E, as a stand-alone Company, has taxable income available for that year. For purposes of netting, the Historical Year in Attachment D shall treat the manufacturing tax deduction consistent with the previously filed Projected Year.

J)
Depreciation Expenses and Accumulated Depreciation shall reflect Commission-approved rates. No changes in depreciation rates shall be made in the annual FRP filing. During an annual FRP filing, a utility may request an interim rate for plant added which has no approved depreciation rate, excluding major plant acquisitions. OG&E shall request depreciation rates for major plant acquisitions within the docket requesting approval for the purchase of the plant. 

K)
Revenue and cost effects that were imputed in the general rate case shall be similarly imputed in the annual FRP filing.


13

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


L)
OG&E shall not record a regulatory asset or a regulatory liability representing the amount by which an FRP increase or decrease absent the operation of the 4 percent cap exceeds the actual FRP increase or decrease that is implemented pursuant to the operation of this tariff.

II.
Cost of Service Categories

A.
Revenues

1.
For the Projected Year, revenue shall be based on OG&E’s projected annualized billing determinants and rates which will be in effect at year-end. Adjustments for customer growth and thirty-year weather normalized average usage and average demands established from 16-052-U.

2.
The Historical Year shall reflect actual revenues. No adjustments for growth or weather shall be included.

3.
Revenues associated with special rate contracts shall be treated consistent with the terms of the contract.

B.
Rate Base

1.
For the Historical Year, plant shall reflect the average of beginning and ending year balances.

2.
For the Projected Year plant shall reflect the average of beginning and ending year balances. Plant shall include adjustments based on projections, including but not limited to, CCN/CECPN projects approved or expected to be approved by the Commission and in service by the beginning of the Projected Year for the beginning year balances, and include projects in-service by the end of the Projected Year for ending year balances.

3.
For the Historical Year, WCA shall reflect a 13-month average.

4.
For the Projected Year, WCA shall reflect a 13-month average of the Historical Year with adjustments or projections to reflect a more representative balance.

C.
Expenses

1.
The Historical Year shall reflect actual expenses, adjusted as described in Attachment C.

D.
Income Tax Expense

All state and federal income tax effects including 1) adjustments to taxable income, 2) adjustments to current taxes, and 3) provisions for deferred income tax (debit and credit) shall be adjusted or eliminated, as appropriate, to comport with the following principles:

1.
All Projected Year and Historical Year interest expenses shall be eliminated and replaced with an imputed interest expense amount equal to the rate base multiplied by the weighted embedded cost of debt;

2.
Effects associated with other adjustments shall be similarly and consistently adjusted;

3.
The Projected Year shall reflect the corporate state and federal income tax laws legally in effect on the date the Evaluation Report is filed. The Historical Year shall reflect the corporate state and federal income tax laws legally in effect at year-end;

4.
The manufacturing tax deduction is a nine percent (9%) deduction to income attributable to domestic production activities created by the American Jobs Creation Act of 2004 as discussed in Section 199, Income Attributable to Domestic Production, of the Internal Revenue Code. The manufacturing tax deduction shall only be included for purposes of determining Projected Year taxes in Attachment B and

14

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Historical Year taxes in Attachment D, if OG&E, as a stand-alone company, has taxable income available for each of those respective years; and

5.
For the Projected Year and Historical Year, tax effects normally excluded for ratemaking purposes shall be eliminated.

E.
Benchmark Rate of Return on Rate Base

For the Projected Year and the Historical Year, the following adjustments shall be made:

1.
CAOL shall be based on the Historical Year 13-month averages, as adjusted, and include all accounts consistent with those ordered by the Commission in Docket No. 16-052-U;

2.
Accumulated Deferred Income Taxes (ADIT) shall be based on the beginning and ending test year average and include all accounts consistent with those ordered by the Commission in Docket No. 16-052-U;

3.
The capital balances for Long-Term Debt, Capital Leases, Preferred Equity, Common Equity, DOE Obligation and Other Capital shall be mid-year (September 30) balances adjusted to reflect intercompany payables balances using any 13 month average, if applicable, consistent with those ordered by the Commission in Docket No. 16-052-U;

4.
The DTE ratio for external capital, including the short-term debt percentage of 2.9%, shall be fixed at 50/50.
5.
The return on equity shall be the value determined in Docket No. 16-052-U.

III.
Other Adjustments

A.
Reclassifications

1.
For the Historical Year and Projected Year, revenues included in Other Electric Revenue shall be reclassified to the appropriate jurisdictional rate schedule revenue category.

2.
For the Projected Year and Historical Year, costs not allowable for ratemaking purposes shall be excluded as specified in Section I, or removed by adjustment. Likewise, costs that are allowed, but recorded below the utility operating income line, shall be included in the annual FRP filing cost data through appropriate reclassification adjustments.

B.
Out-of-Period Items

Expenses and revenues that are related to transactions occurring prior to the Historical Year but are recorded in the Historical Year shall be eliminated, including any associated tax adjustments.

C.
Other

Nothing in this Attachment shall preclude OG&E or any party from proposing additional adjustment(s) beyond those described above.

15

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment D-1
Oklahoma Gas & Electric
Formula Rate Plan
Earned Rate of Return on Common Equity Formula
For the Historical Year xxxx
 
 
 
 
 
 
 
 
Line
Description
Source
Adjusted
No
 
 
Amount
 
 
 
 
TOTAL COMPANY
 
 
 
 
1
RATE BASE
D-2, Line 27
 
2
BENCHMARK RATE OF RETURN ON RATE BASE
D-5, Line 12, Column F
 
 
 
 
 
3
REQUIRED OPERATING INCOME
Line 1 * Line 2
 
4
NET UTILITY OPERATING INCOME
D-3, Line 30
 
5
OPERATING INCOME DEFICIENCY/(EXCESS)
Line 3 - Line 4
 
6
REVENUE CONVERSION FACTOR
Note [1]
 
7
REVENUE DEFICIENCY/(EXCESS)
Line 5 * Line 6
 
 
PRESENT RATE REVENUES
 
 
8
RETAIL RATE SCHEDULE REVENUE
D-3, Line 2
 
9
WHOLESALE SALES
D-3, Line 3
 
10
REVENUE REQUIREMENT
Line 7 + Line 8 + Line 9
 
 
 
 
 
TOTAL ARKANSAS RETAIL
 
 
 
 
11
REVENUE REQUIREMENT ALLOCATION FACTOR
Line 12/Line 10
 
12
RETAIL REVENUE REQUIREMENT
Note 2
 
13
RETAIL RATE SCHEDULE REVENUE
Line 8
 
14
RETAIL REVENUE DEFICIENCY/(EXCESS)
Line 12 - Line 13
 
15
REVENUE CONVERSION FACTOR
Note [1]
 
16
RETAIL OPERATING INCOME DEFICIENCY/(EXCESS)
Line 14 / Line 15
 
17
RATE BASE ALLOCATION FACTOR
Line 18/Line 1
 
18
RETAIL RATE BASE
Note 3
 
19
COMMON EQUITY DEFICIENCY/(EXCESS) (%)
Line 16 / Line 18
 
20
WEIGHTED EVALUATION PERIOD COST RATE FOR COMMON EQUITY (%)
D-5, Line 3, Column F
 
21
WEIGHTED EARNED COMMON EQUITY RATE (%)
Line 20 - Line 19
 
22
COMMON EQUITY RATIO (%)
D-5, Line 3, Column D
 
23
EARNED RATE OF RETURN ON COMMON EQUITY (%)
Line 21 / Line 22
 
 
 
 
 
 
 
 
 
Notes:
 
 
[1]
Revenue Conversion Factor = 1 / [(1 - Composite Tax Rate (Net of Manufacturing Tax Deduction in accordance with Attachment C) * (1 - Bad Debt)].
[2]
Arkansas Jurisdictional Revenue Requirement as determined by running the total company projected costs through the approved Cost of Service model from Docket No. 16-052-U.
[3]
Arkansas Jurisdictional Rate Base as determined by running the total company projected costs through the approved Cost of Service model from Docket No. 16-052-U.

16

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment D-2
 
 
 
 
 
 
 
Oklahoma Gas & Electric
Formula Rate Plan
Rate Base
For the Historical Year xxxx
 
 
 
 
 
 
 
 
 
 
 
 
Line
 
 
Historical Year
Historical Year
Adjusted
No
 
Description
Per Books
Adjustments
Historical Year
 
 
 
A
B [1]
C
 
 
 
 
 
 
1
PLANT IN SERVICE
 
 
 
2
 
Beginning Balance
 
 
 
3
 
Ending Balance
 
 
 
4
 
Average Balance
 
 
 
 
 
 
 
 
 
5
ACCUMULATED DEPRECIATION
 
 
 
6
 
Beginning Balance
 
 
 
7
 
Ending Balance
 
 
 
8
 
Average Balance
 
 
 
 
 
 
 
 
 
9
 
AVERAGE NET UTILITY PLANT (L4 + L8)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10
PLANT ACQUISITION ADJUSTMENT
 
 
 
11
 
Beginning Balance
 
 
 
12
 
Ending Balance
 
 
 
13
 
Average Balance
 
 
 
 
 
 
 
 
 
14
 AMORTIZATION OF ACQUISITION ADJ
 
 
 
 
15
 
Beginning Balance
 
 
 
16
 
Ending Balance
 
 
 
17
 
Average Balance
 
 
 
 
 
 
 
 
 

18
 WORKING CAPITAL ASSETS
  MATERIALS AND SUPPLIES
  PREPAYMENTS
     FUEL INVENTORY
  WORKING CASH
 
 
 
19
 
 
 
20
 
 
 
21
 
 
 
22
 
 
 
23
 
TOTAL WORKING CAPITAL ASSETS
0
0
 
 
 
 
 
 
 
24
OTHER
0
 
 
 
 
 
 
 
 
25
 TOTAL RATE BASE:
 Ending Balances (L3+L7+L12+L16+L23+L24)
 Adj. Historical Year (L9+L13+L17+L23+L24)
 
 
 
26
0
 
 
27
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
 
 
[1]
Adjustments as set out in Attachment C to this FRP.
 
 

17

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment D-3
Oklahoma Gas & Electric
Formula Rate Plan
Operating Income
For the Historical Year xxxx
 
 
 
 
 
 
 
 
 
 
Line
 
Historical Year
Historical Year
Adjusted
No
Description
Per Books
Adjustments
Historical Year
 
 
A
B [1]
C
 
 
 
 
 
 
REVENUES
 
 
 
 
 
 
 
 
1
SALES TO ULTIMATE CUSTOMERS
 
 
 
2
RETAIL RATE SCHEDULE REVENUE
 
 
 
3
WHOLESALE SALES
 
 
 
4
TOTAL SALES TO ULTIMATE CUSTOMERS (L2 + L3)
 
 
 
 
 
 
 
 
5
OTHER SALES REVENUE
 
 
 
6
OTHER ELECTRIC REVENUE
 
 
 
7
TOTAL OPERATING REVENUES (Sum of L4 thru L6)
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 8
OPERATION & MAINTENANCE
 
 
 
9
PRODUCTION
 
 
 
10
TRANSMISSION
 
 
 
11
REGIONAL MARKET
 
 
 
12
DISTRIBUTION
 
 
 
13
CUSTOMER ACCOUNTING
 
 
 
14
CUSTOMER SERVICE & INFORMATION
 
 
 
15
SALES
 
 
 
16
ADMINISTRATIVE & GENERAL
 
 
 
17
TOTAL O & M EXPENSE (Sum of L9 thru L16)
 
 
 
 
 
 
 
 
18
GAIN FROM DISPOSITION OF ALLOWANCES
 
 
 
19
REGULATORY DEBITS & CREDITS
 
 
 
20
 DEPRECIATION & AMORTIZATION EXPENSES 
 
 
 
21
ACCRETION EXPENSES
 
 
 
22
AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT
 
 
 
23
OTHER CREDIT FEES
 
 
 
24
TAXES OTHER THAN INCOME
 
 
 
25
CURRENT STATE INCOME TAX [2]
 
 
 
26
CURRENT FEDERAL INCOME TAX [2]
 
 
 
27
GAIN/LOSS – DISPOSITION OF UTILITY PLANT
 
 
 
28
OTHER
 
 
 
29
TOTAL UTILITY OPERATING EXPENSE (Sum of L17 thru L28)
 
 
 
 
 
 
 
 
30
NET UTILITY OPERATING INCOME (L7 – L29)
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
[1]
Adjustments as set out in Attachment C to this FRP.
 
 
 
[2]
Reference Attachment D-4.
 
 
 
 
 
 

18

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment D-4
Oklahoma Gas & Electric
Formula Rate Plan
Income Tax
For the Historical Year xxxx
 
 
 
 
 
 
 
 
 
 
Line
 
Historical Year
Historical Year
Adjusted
No
Description
Per Books
Adjustments
Historical Year
 
 
A
B [1]
C
 
 
 
 
 
1
TOTAL OPERATING REVENUES
 
 
 
 
 
 
 
 
2
TOTAL O&M EXPENSE
 
 
 
3
GAIN FROM DISPOSITION OF ALLOWANCES
 
 
 
4
REGULATORY DEBITS AND CREDITS
 
 
 
5
DEPRECIATION & AMORTIZATION EXPENSE
 
 
 
6
ACCRETION EXPENSE
 
 
 
7
AMORTIZATION OF PLANT ACQUISITION ADJUSTMENT
 
 
 
8
OTHER CREDIT FEES
 
 
 
9
TAXES OTHER THAN INCOME
 
 
 
10
GAIN/LOSS – DISPOSITION OF UTILITY PLANT
 
 
 
11
OTHER
 
 
 
12
INTEREST EXPENSE [2]
 
 
 
 
 
 
 
 
13
NET INCOME BEFORE INCOME TAXES (L1- (Sum L2-L12))
 
 
 
 
 
 
 
 
14
ADJUSTMENTS TO NET INCOME BEFORE TAXES [3]
 
 
 
15
TAXABLE INCOME (L12 + L13)
 
 
 
 
 
 
 
 
 
COMPUTATION OF STATE INCOME TAX
 
 
 
 
 
 
 
 
16
TAXABLE INCOME (L15)
 
 
 
17
STATE ADJUSTMENTS [3]
 
 
 
18
STATE TAXABLE INCOME (L16 + L17)
 
 
 
19
STATE INCOME TAX BEFORE ADJUSTMENTS (L18 * Tax Rate) [1]
 
 
 
20
ADJUSTMENTS TO STATE TAX [3]
 
 
 
21
STATE INCOME TAX (L19 + L20)
 
 
 
 
 
 
 
 
 
COMPUTATION OF FEDERAL INCOME TAX
 
 
 
 
 
 
 
 
22
TAXABLE INCOME (L15)
 
 
 
23
STATE INCOME TAX BEFORE ADJUSTMENTS (L19)
 
 
 
24
FEDERAL ADJUSTMENTS [3]
 
 
 
25
TOTAL FEDERAL TAXABLE INCOME (L22 - L23 + L24)
 
 
 
26
FEDERAL INCOME TAX BEFORE ADJUSTMENTS (L25 * Tax Rate) [1]
 
 
 
27
ADJUSTMENTS TO FEDERAL TAX [3]
 
 
 
28
FEDERAL INCOME TAX (L26 + L27)
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
 
[1]
Adjustments and applicable tax rate as set out in Attachment C to this FRP.
 
 
[2]
Interest Expense is Per Books for Column A, Weighted Cost Of Debt (COD) Rate as derived from COD elements reflected in Attachment D-5 x Rate Base per Attachment D-2, Column C.
 
[3]
List all adjustments including descriptions in a supporting schedule.
 
 
 

19

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment D-5
Oklahoma Gas & Electric
Formula Rate Plan
Benchmark Rate of Return on Rate Base
For the Historical Year xxxx
 
 
 
 
 
 
(A)
(B)
(C)
(D)
(E)
(F)
 
 
 
 
 
Benchmark
 
 
Capital
Capital
Cost
Rate Of
 
 
Amount ($)
Ratio (%)
Rate (%)
Return On
Line No.
Description
[1]
[2]
[3]
Rate Base [4]
 
 
 
 
 
 
 
 
 
 
 
 
1
Long-Term Debt
 
 
 
 
2
Preferred Stock
 
 
 
 
3
Common Equity
 
 
 
 
4
Accumulated Deferred Income Taxes
 
 
 
 
5
Pre-1971 ADITC
 
 
 
 
6
Post-1970 ADITC
 
 
 
 
7
Customer Deposits
 
 
 
 
8
Short-Term/Interim Debt
 
 
 
 
9
Current Accrued, and Other Liabilities
 
 
 
 
10
Capital Leases
 
 
 
 
11
Other Capital Items
 
 
 
 
 
 
 
 
 
 
12
Total
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
 
 
 
 
 
 
 
[1]
The capital balances for Long-Term Debt, Capital Leases, Preferred Equity, Common Equity and Other Capital shall be mid-year (September 30) balances adjusted to reflect any intercompany payables balances using any 13 month average, if applicable, consistent with Commission Order in Docket No. 16-052-U. Support for the 13 month average of the money pool calculations shall be provided. The total debt-to-equity ratio (DTE) for external capital, including the short-term debt percentage of 2.9%, shall be fixed at 50/50, consistent with Commission Order in Docket No. 16-052-U. Capital amounts shall include mid-year (September 30) balances for Post-1970 Investment Tax Credits, Customer Deposits, and Short-Term debt balances, beginning and ending year average for ADIT, and 13-month average balances for CAOL, if applicable. A September 30 balance sheet should be provided as well as a reconciliation between the balance sheet and Column (C) amounts. Support for the CAOL balances shall include the same format and detail as required by the Filing Requirements in Attachment E, Item No. 15.

[2]
Capital amounts each divided by the Total Capital Amount.
[3]
The cost rates shall be calculated in accordance with the calculation applied by the Commission in Docket No. 16-052-U. Support for the cost of Long-Term debt and cost of Preferred Stock shall be provided in the same format and level of detail required by the Filing Requirements, respectively. Support for the Short-Term debt cost rate and DOE Obligation cost rate, if applicable, should include a general description of how the interest rate is determined and the same level of detail provided in the Filing Requirements in Attachment E, Item No. 15. The cost rate for Customer Deposits shall be the Commission-approved rate in effect during the year. The cost rate for Common Equity shall be that approved by Commission Order in Docket No. 16-052-U.
[4]
The components in Column F are the corresponding Cost Rates multiplied by the associated Capital Ratio.


20

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment D-6
 
Oklahoma Gas & Electric
 
Formula Rate Plan
 
FRP Revenue Redetermination Formula
 
For the Historical Year xxxx
 
 
 
 
 
 
 
 
 
SECTION 1
 
 
 
 
 
BANDWIDTH DEVELOPMENT
 
Line
 
 
 
 
 
 
 
No
 
DESCRIPTION
 
REFERENCE
 
 
 
1
 
Earned Rate of Return on Common Equity ("ERR") [1]
 
D-1, Line 23
 
 
 
2
 
Target Return Rate ("TRR")
 
D-5, Line 3, Column E
 
 
 
3
 
Upper Bandwidth Limit
 
Line 2 + 0.50%
 
0.50
 %
 
4
 
Lower Bandwidth Limit
 
Line 2 - 0.50%
 
-0.50
 %
 
5
 
ROE Adjustment
 
If L1 < L4, then L2 - L1; If L1 > L3, then L2 - L1, but no adjustment if L1 ≥ L4 or L1 ≤ L3
 
 
 
 
 
 
 
 
 
 
 
SECTION 2
 
 
 
 
 
 
 
ROE BANDWIDTH RATE ADJUSTMENT
 
Line
 
 
 
 
 
 
 
No
 
DESCRIPTION
 
REFERENCE
 
 
 
6
 
ROE Adjustment
 
Per Line 5
 
 
 
7
 
Common Equity Capital Ratio
 
D-5, Line 3, Column D
 
 
 
8
 
Retail Rate Base
 
D-1, Line 18
 
 
 
9
 
Revenue Conversion Factor
 
D-1, Line 15
 
 
 
10
 
Total Rate Change in FRP Revenue
 
Line 6 * Line 7 * Line 8 * Line 9
 
 
 
 
 
 
 
 
 
 
 
SECTION 3
 
 
 
 
 
TOTAL BANDWIDTH RATE ADJUSTMENT
 
Line
 
 
 
 
 
 
 
No
 
DESCRIPTION
 
REFERENCE
 
 
 
11
 
(Reduction) / Increase in FRP Revenue
 
Line 10
 
 
 
12
 
Adjusted Historical Year FRP Rider Revenue
 
Note [3]
 
 
 
13
 
Netting of Historical Year Differences Adj. [4]
 
Line 11 - Line 12
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
 
 
 
 
 
[1]
The ERR is the Earned Rate of Return on Common Equity, calculated by dividing the weighted earned common equity rate by the common equity ratio percentage.
 
[2]
The TRR is the Company's cost rate for common equity as established by the Commission in Docket No. 16-052-U.

 
[3]
Adjusted Historical Year FRP Rider revenue is the total FRP Rider revenue received in the Historical Year less the Netting Adjustment revenue determined when the Historical Year was a Projected Year.

 
 
 
[4]
Netting shall not begin until there is an actual twelve (12) months of Historical Year to report.

21

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment E
OKLAHOMA GAS & ELECTRIC
FORMULA RATE PLAN
FILING REQUIREMENTS
Item No.
Filing Requirements
1
OG&E shall file all FRP Attachments supporting the Historical and Projected Year.

The following information shall be provided to the Parties:
2
Comparative Balance Sheet for the Historical Year and as of December 31 for the four (4) years preceding the Filing Year. Reconcile to the Trial Balances and the Attachment D Schedules that it supports, and reconcile to the FERC Form 1 and FERC Form 3-Q, as applicable.

3
Operating statement of revenues and expenses for the Historical Year and for twelve months ending December 31 for the four (4) years preceding the Filing Year. Reconcile to the Trial Balances and the Attachment D Schedules that it supports, and reconcile to the FERC Form 1 and FERC Form 3-Q, as applicable.

4
Trial Balance by detail general ledger subaccount number for the Historical Year and for the four (4) years preceding the Filing Year. Reconcile to the Balance Sheets and the Attachment D Schedules that it supports.

5
Monthly Trial Balances (FERC and Natural accounts) by detail general ledger subaccount number for the beginning of the Historical Year and each of the monthly balances for the fiscal year. Reconcile to the Balance Sheet, Income Statement, and the Attachment D Schedules that it supports. Also, provide the monthly Trial Balance information for the Filing Year to date.

6
Monthly balances for the “300" series plant amounts for the beginning of and each month-end of the Historical Year (13 months). In additional columns, the accumulated depreciation balances, the removal of securitized amounts (plant and accumulated depreciation) and asset retirement obligations and any other adjustments by each “300” series plant amount for the beginning of and each month-end of the Historical Year (13 months). Reconcile to the utility plant accounts in the Trial Balance and the Attachment D Schedules it supports.

7
Monthly plant and accumulated depreciation balances by account and plant and unit, if applicable, for the Historical Year showing the additions and retirements and any adjustments. Provide the cost of removal and salvage amounts by plant account for the year. Reconcile all amounts to the monthly Trial Balances for the “300" series plant accounts.

8
Identify all construction projects or purchases that closed to plant during the Historical Year. Include the project number, project description, start date, completion date, date closed to plant, cost to complete, and plant accounts where it was closed. Provide the detailed costs, including the AFUDC calculation, included in the five (5) largest projects completed during the year.

9
Identify any construction project or proposed purchase, noting if it is approved or expected to be approved by the Commission (CCN, CECPN) and in-service by the end of the Projected Year. Include the project number, project description, start date, expected completion date and expected cost to complete and plant accounts where it will be closed. Reconcile the total amount of the projects for both the beginning and the end of the Projected Year with the plant additions included on Attachment Schedule B-2.


22

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


10
Plant balances by subaccount and plant/unit, as applicable for the ten (10) years preceding the Filing Year showing the additions and retirements. Include the 10-year average of each and explain any amount that deviates from the average by more than thirty percent (30%). Provide the cost of removal and salvage amounts by plant subaccount and plant/unit, as applicable for the same ten (10) years. Determine the 10-year average percentage of plant additions, by plant account, for retirements, and the 10-year average percentage of retirements by plant (accumulated depreciation) account for cost of removal and salvage. Reconcile the total amount of the retirements as a 10-year average percent of plant additions and the cost of removal and salvage as a 10-year average percent of retirements for both the beginning and the end of the Projected Year with the plant and accumulated depreciation amounts included on Attachment Schedule B-2.

11
Detailed chart of accounts, including subaccounts and detailed description (i.e. MFR E-9). List of project codes, activity codes, resource codes and detailed description for each.


12
OG&E internal and external audit reports for the Historical Year and any proposed auditor’s adjustments.


13
The most recently filed State and Federal Income Tax Returns for OG&E and OGE Energy Corp..

14
Web access for the period of time between filing and a final order in the formula rate review process to OG&E’s database containing all general ledger accounting activity for the Historical Year and Filing Year to date.

15
Rules of Practice and Procedure, Appendix 8-1 Minimum Filing Requirements (MFR) Schedules, as modified to substitute the Historical Year for the test year and the Projected Year for the pro forma year, B-1, B-2, B-4, B-5, B-10, C-4, C-5, C-8, C-9, C-10, C-11, C-12, D-2, D-3, D-5, D-6.1, D-6.2, D-6.3, D-7, F-1, G-1, G-2, G-3 and G-4, including the supporting cost of service study (Jurisdictional Only). These schedules shall be used to support the adjustments described in Items 18 and 19 below. Note, C-5 shall be used to recalculate the revenue conversion factor and should be revised to include the manufacturing tax deduction. Note, D-2 and D-3 shall be modified to substitute the Historical Year as of September 30 for the test year and the Filing Year and Projected Year through September 30 for the pro forma year.

16
Schedule of the expenses paid to each vendor for the Historical Year and Filing Year to date sorted by vendor name.
17
Web access for the period of time between filing and a final order in the formula rate review process to invoices for all vendors, regardless of originating company (OG&E and OGE Energy Corp.) included in Item 16.

18
Separate schedules of proposed adjustments to the actual financial statement amounts in determining the Adjusted Historical Year by general ledger subaccount for 1) rate base, 2) revenues and expenses (excluding current and deferred income taxes), 3) current and deferred income taxes, 4) CAOL, 5) ADIT and 6) other capital components. Within each schedule, the adjustments should be in separate columns, but grouped by 1) adjustments to remove rider revenue and expenses, 2) those consistent with adjustments ordered by the Commission in Docket No. 16-052-U (such as removal of disallowed expenses such as charitable contributions, or exclusion of temporary accounts from WCA), or 3) or other adjustments. The adjustments within each schedule (rate base, revenues and expense, income taxes, cost of capital components) shall directly support and reconcile to the appropriate Attachment D Schedules.

19
Separate schedules of proposed adjustments used in determining the Adjusted Projected Year by general ledger subaccount for 1) rate base, 2) revenues and expenses (excluding current and deferred income taxes), 3) current and deferred income taxes, 4) CAOL, 5) ADIT and 6) other capital components. Within each schedule, the adjustments should be in separate columns, but grouped by 1) adjustments to remove excluded rider revenue and expenses, 2) those consistent with Docket No. 16-052-U (such as removal of disallowed expenses such as charitable contributions, or exclusion of temporary accounts from WCA), or 3) or other adjustments. The adjustments within each schedule (rate base, revenues and expense, income taxes, cost of capital components) shall directly support and reconcile to the appropriate Attachment B Schedules. Adjustments shall include certain items such as additional plant in service approved by the Commission per CCN/CECPN, if required.


23

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


20
 For the Historical Year, by rate class and rate schedule, provide a statement showing customer count, kWh, weather adjusted kWh, base rate revenues, and rider revenues. For the Projected Year, by rate class and rate schedule, provide a statement showing customer count, kWh, base rate revenues, and rider revenues. Provide work papers that explain the variance analysis between the Historical Year and Projected Year information.
 
21
Provide expense totals for the Historical Year and the four (4) years preceding the Historical Year by subaccount, source resource code, source activity code, project code, and bill resource code. Each year should include separate columns for expenses included in the determination of base rates and other riders (non-base rates) expenses. Reconcile to Trial Balance.

22
Schedule of total payroll and related costs supporting base rates (excluding riders) by FERC subaccount (expense and non-expense accounts) for the Historical Year and four (4) years preceding the Historical Year. The costs should be shown in separate groups of columns for each company (OG&E and OGE Energy Corp.). Within each company, for full-time employees only, include separate columns for: base pay, overtime, STI, LTI, other bonuses (identify each separately),and payroll taxes. Provide part-time pay and payroll taxes. Include a separate column for reductions for any payroll costs paid by other affiliates or other companies per loaned labor/mutual assistance programs.

23
Non-payroll balances supporting base rates (excluding riders) by FERC subaccount, and source resource code and at the 300 FERC subaccount level for Plant in Service, for the twelve (12) months ending December 31 for the Historical Year and four (4) years preceding the Filing Year. Either in a separate analysis or in separate columns, identify the expense amounts in each subaccount, and source resource code by company (OG&E and OGE Energy Corp.). Identify and explain all significant changes in accounting procedures during the five (5) years. For any accounting reclassifications identified in the accounting changes, align and reconcile accounts that reflect accounting changes in order to consistently track the accounting change through the five-year period. Identify and explain changes between the twelve (12) months ending December 31 of the Historical Year costs and the five-year average by FERC Account for all variances greater than thirty percent (30%) and five hundred thousand dollars ($500,000). The explanation and work papers shall include the specific underlying reason for the variance.

24
Provide an analysis of non-payroll, non-rider expenses and plant amounts using the historical data and results of Items 10 and 23. In addition to the averages developed in the other Items, determine a trended average, or average of annual changes, for each FERC subaccount balance for the five years of historical expense data and 10 years of historical plant data, ending with the Historical Year (Plant in Service will be presented at the 300 FERC subaccount and plant/unit level). Summarize the results, showing a comparison of the Historical Year balances, averages, and trended averages, by FERC subaccount or plant subaccount and plant/unit, if applicable.
25
Affiliate transaction analysis of OG&E expense account and project code shown in separate columns for the following: a) amounts billed, segregated between direct and allocated, from each affiliated company with separate columns for each affiliate; b) amounts directly incurred by OG&E for its own operations; c) all other amounts in the account not corresponding to (a) or (b); and d) the sum of columns (a) through (c) which would equal the account’s general ledger balance at the end of the Historical Year. Provide an explanation of all items in (c). Provide copies of all allocation manuals used in allocating common costs among and between the Company and its affiliates, and billing method tables for all affiliates which have direct-billed or allocated charges to OG&E.

24

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


Attachment F
FORMULA RATE PROTOCOLS
Section I. General Provisions

1.    Applicability and Scope

A.
The following protocols shall apply to the annual Evaluation Report filings made pursuant to the Formula Rate Plan Rider Tariff (FRP) approved by the Commission in Docket No. 16-052-U.

B.
The Rules of Practice and Procedure (RPPs) shall apply to all annual Evaluation Report filings, except the following for which the Commission has granted an exemption by approving the FRP:

Rule 3.08;
Rule 4.02 (a)(2)(A);
Rule 4.02 (a)(3);
Rule 4.02 (a)(4);
Rule 4.03 (c);
Rule 4.04 (a)(2);
Rule 4.10 (a)(2) & (3); and
Rule 5.05(b), (c), & (d).

C.
Any proposed modification of the FRP Tariff, including these protocols, is outside the scope of an annual Evaluation Report filing and as such, no Party shall seek to modify the FRP Tariff, including these protocols, as part of any annual Evaluation Report filing. Proposed modifications to the FRP Tariff, including these protocols, shall be brought in a separate docket.

D.
The filing of an annual Evaluation Report is a Formal Application. The filings of an annual Evaluation Report are not to be construed as a General Rate Change Application, nor are adjustments to rates that result from the filings of an annual Evaluation Report to be construed as a general change in rates pursuant to any provision of the Arkansas Code that references a general change in rates.

E.
The Commission may grant an exemption from compliance with these Protocols if the exemption is found to be in the public interest and for good cause shown.


2.    Public Notice

A.
At least thirty (30) days prior to filing an annual Evaluation Report, OG&E shall give public notice of its intent to file.

B.
The notice shall indicate that it is from OG&E and shall include: the docket number, if known; the date on or about which the annual Evaluation Report is to be filed; the effective date of FRP rates; reference to the RPPs and these protocols for persons interested in intervening, making a limited appearance, or submitting public comments in writing or orally at the hearing; deadlines for intervention as provided herein; the name, address, phone number and email address of the Secretary of the Commission and the URL address of the Commission website; and that further information may be obtained by contacting the Secretary of the Commission or viewing the Commission’s website.

25

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80




C.
Public notice shall be given by any method including but not limited to: bill notation, direct mail, email exploder list, publication on OG&E’s website, through social media, or publication in a newspaper of general circulation in OG&E’s service area.

D.
An annual Evaluation Report filing shall include a declaration that these notice provisions have been complied with.

3.
Intervention    

A.
A Petition to Intervene shall be filed within ten (10) calendar days from the date the annual Evaluation Report is filed.

B.
Any Party desiring to file a Response to a Petition to Intervene shall file the Response within five (5) calendar days of the filing of the Petition. No additional responses or replies shall be permitted unless specifically authorized by the Commission.

C.
The Commission shall rule on the Petition to Interveners within seven (7) calendar days from the date the Petition is filed. If the Commission does not rule within that time frame, the Petition to Intervene shall be deemed denied.

4.
Discovery

A.
Time Within Which to Respond or Object

1.
The Party upon whom discovery is sought shall serve a written response or objection within ten (10) calendar days after service of the discovery. Responses or objections to requests for admission shall be served within ten (10) calendar days of service of the requests. The Commission may prescribe a shorter or longer time. Any objections shall state the specific reasons for such objection.

2.
If the response to the discovery request contains protected information for which no Protective Order has been issued, the responsive Party shall apply for a Protective Order as soon as reasonably practicable after receipt of the discovery request so as to avoid any delays in responding to discovery, and to the greatest extent practicable no later than five (5) calendar days after receipt of the discovery request. OG&E shall respond to the discovery request on the next business day after the Protective Order is issued or on the date the discovery response is due.

B.
Discovery Initiation

Unless otherwise ordered, a Party may initiate discovery at any time after filling of an annual Evaluation Report so long as responses or objections and depositions shall be completed at least sixty (60) days before the date on which rates determined by the formula rate review mechanism will go into effect for each year or ten (10) days before a hearing on the merits, whichever is earlier.

26

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80



C.
Service and Format

1.
Service shall be made by electronic mail, facsimile transmission, hand delivery, or overnight delivery service unless unusual circumstances otherwise justify delivery by another method and the Parties agree to the method chosen.

2.
Attachments to documents shall be provided in native electronic format, with formulae and viable links intact.

3.
Any discovery document served electronically or by facsimile after Commission Business Hours but before midnight or received on a non-business day shall be deemed served on Persons on the Official Service List with electronic mail on the next business day. Any discovery document served electronically or by facsimile between midnight and the beginning of Commission Business Hours on a business day shall be deemed served on Persons on the Official Service List on that business day. Any discovery document served by hand delivery or overnight delivery service shall be deemed served pursuant to Rule 3.07 of the RPPs.

D.
Computation of Time for Performance or Response

In computing the time within which an act must be performed or a response made, the Day of the act from which the designated period of time begins to run shall not be included and the last Day shall be included unless it is a Saturday, Sunday, Legal Holiday, or other Day in which the Commission’s office is closed, in which event the period shall extend to the next business Day. Service by mail or commercial delivery service is prohibited; therefore no additional response time as contemplated by the RPPs is necessary.

5.
General Filing Matters

A.
Beginning with the initial annual Evaluation Report filing after the FRP is approved by the Commission in Docket No. 16-052-U, a separate docket shall be established by the Secretary of the Commission for the annual Evaluation Report filings with an “FR” docket designation.

B.
The initial and all subsequent annual Evaluation Reports filed in the “FR” docket. OG&E shall submit the annual Evaluation Report with a Commission-approved tariff Docket Summary Cover Sheet. In addition to any other information required by the coversheet, OG&E shall reference Docket No. 16-052-U.

C.
Stipulations or Settlements

1.
Parties shall propose by written motion that the Commission adopt stipulations or settlements. Such motion shall be filed, along with supporting testimony, no later than seven (7) calendar days prior to the hearing scheduled in the annual Evaluation Report filing. If the seventh day falls on a weekend or state holiday such settlement agreement and supporting testimony shall be filed on the last business day prior to the seventh day. The motion shall set forth the factual, legal, policy, and other consideration which form the basis for the Parties’ recommendation that the stipulation or agreement be adopted, and shall be supported by written testimony.

2.
A Party not joining a proposed stipulation or settlement may file a response no later than five (5) calendar days prior to the scheduled date of the hearing.


27

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80


3.
Such a response shall set forth the factual, legal, policy, and other consideration which form the basis for the Party’s opposition to the proposed stipulation or settlement or portions thereof.

Section II. Filing Requirements

1.
Testimony and Exhibits

A.
Testimony with or without Exhibits shall be filed simultaneously with the annual Evaluation Report and address, at a minimum:

1.
A description of the filed schedules and all of the adjustments proposed;

2.
A description of any significant cost drivers;

3.
A description of any changes in accounting policies, practices, and procedures if they affect inputs to the FRP or the rate redetermination to be made under the FRP; and

4.    A narrative explanation of the rate impact.
 
2.
Workpapers and Supporting Documentation


A.
The annual Evaluation Report and any revisions thereto shall include:

1.
Data-populated schedules including fully functioning EXCEL spreadsheet with all formulas and links intact, showing all calculations in the annual Evaluation Report;

2.
Sufficient information to enable the Parties to replicate the calculation of the formula results from the applicable schedules; and

3.
Documentation fully supporting all calculations and adjustments.
  
B.
Workpapers shall be provided to the Parties simultaneously with the filing of the annual Evaluation Report and any revisions thereto, and shall include:

1.
All supporting calculations and documents that explain the calculations in theannual Evaluation Report;

2.
Both references to and support from detailed source information; and

3.
A complete description of any statistical model used, the data used, and the results of the analysis if not addressed in testimony or exhibits.

28

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80



C.
With respect to any change in accounting that affects inputs to the FRP or the resulting rate redetermination to be billed under the FRP, OG&E shall identify and provide narrative explanation of the individual impact of such changes on rate redetermination to be billed under the FRP including:
 
1.
The initial implementation of an accounting standard or policy;

2.
The initial implementation of accounting practices for unusual or unconventional items where the Commission has not provided specific accounting direction;

3.
Correction of errors and prior period adjustments that impact the FRP;

4.
The implementation of new estimation methods or policies that change prior estimates; and

5.    Changes to income tax elections.

D.
OG&E shall identify any reorganization or merger transaction and explain the effect of the accounting for such transaction(s) on the inputs to the FRP or the resulting rate determination to be billed under the FRP.

3.
Waiver of Requirements

OG&E may omit specific items of information from the annual Evaluation Report filing only with prior Commission approval.
 
4.
Filing Deficiencies

A.
The Arkansas Public Service Commission General Staff (“Staff”) may review each annual Evaluation Report filing to ascertain whether it complies with the provisions of these Filing Requirements and the FRP, including the provisions of all of the Attachments thereto.

B.
If Staff determines that any deficiencies exist Staff shall file a notice detailing the deficiencies within seven (7) calendar days from the date the annual Evaluation Report is filed.

C.
OG&E shall correct the deficiencies, within seven (7) calendar days of filing of the notification of deficiency, or upon objection being filed by OG&E within that timeframe; the Commission may set a longer period as may be reasonable.

D.
Staff shall review corrections made by OG&E to determine compliance with all information required by the Filing Requirements and the FRP, including the provisions of all of the Attachments thereto.

E.
No more than three (3) business days from the filing of corrections, Staff may file a (1) statement of compliance or (2) a second notice of deficiencies, listing each requirement not met and a brief explanation in support.

F.
The Commission shall resolve any dispute as to deficiencies within seven (7) calendar days of the filing of the second notice of deficiencies by either accepting the corrections made by OG&E or by directing additional corrections to be filed by OG&E.

29

Settlement Attachment No.4
Docket No. 16-052-U
Order No. XX
Effective: XX/XX/201X
Rate Schedule No. 80



5.    Dispute Procedures

A.
Any Party filing with the Commission a statement of errors or objections to the Evaluation Report shall file Testimony with or without Exhibits simultaneously with the statement of errors or objections and the filing shall:

1.
Clearly identify and explain the error in or objection to the annual Evaluation Report;

2.
Make a good faith effort to quantify the financial impact of the error or objection;

3.
State specifically any proposed changes to the annual Evaluation Report that the Party recommends; and

4.
Include all documents and workpapers that support the calculation of the error or the facts supporting the objection.    

B.
OG&E shall file a corrected FRP rate or Rebuttal Testimony with or without Exhibits to the errors and objections raised by the Parties.

6.     Extension of Term

A.
If OG&E requests an extension of the initial term of the FRP, OG&E shall include such request as part of its fourth annual Evaluation Report filing.

B.
OG&E shall provide a class cost of service study for forecasted year-end 2023.

C.
The Commission shall enter a decision on OG&E’s request no later than April 1, 2022.



30