OGE ENERGY CORP. - FORM 8-K - EX-99.02 - EXHIBIT 99.02

Attached files

file	filename
EX-99.01 - EXHIBIT 99.01 - OGE ENERGY CORP.	exhibit99015-19x17.htm
8-K - OGE ENERGY CORP. 8-K - OGE ENERGY CORP.	ogeenergy8-k5x19x17.htm

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.

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. 63^rd Street, Suite 400

Oklahoma City, OK 73105

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 20^th day of April, 2017.

/s/ Justin A. Hinton

Justin A. Hinton

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.	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.

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.

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

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

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. 63^rd Street, Ste. 400

Oklahoma City, OK 73105

(405) 848-1014

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

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

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			Total Revenue Requirement
		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%

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%

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			Total Revenue Requirement
			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%

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%

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 2^nd 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.

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.

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

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

Attached files

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OGE ENERGY CORP. Reports