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

Attached files

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8-K - OGE ENERGY CORP. 8-K - OGE ENERGY CORP.	oge8k062211.htm
EX-99.01 - EXHIBIT 99.01 - OGE ENERGY CORP.	exhibit9901.htm

Exhibit 99.02

ARKANSAS PUBLIC SERVICE COMMISSION

IN THE MATTER OF THE APPLICATION OF	)
OKLAHOMA GAS & ELECTRIC COMPANY FOR	)	DOCKET NO. 10-067-U
APPROVAL OF A GENERAL CHANGE IN RATES	)	ORDER NO. 6
AND TARIFFS	)

ORDER

Background

On September 28, 2010, Oklahoma Gas and Electric (OG&E) filed in the above-styled Docket its Application and supporting Direct Testimonies & Exhibits,1 which were supplemented and/or revised on October 7, 2010, asserting an annual revenue deficiency of $17,723,253 million and seeking approval of a rate increase in that amount. Application Schedule A-1. OG&E did not provide a revised revenue deficiency or requested rate increase amount through its rebuttal filing. If approved, OG&E’s Application would constitute an overall rate increase of approximately 10.5% in total rates. Direct Testimony of OG&E Witness Howard Motley at 1 (September 28, 2010).

OG&E is a corporation organized under the laws of the State of Oklahoma and is qualified to do business in the States of Oklahoma and Arkansas. It is an investor-owned electric utility company engaged in the business of generating, transmitting and distributing electrical power in the States of Oklahoma and Arkansas. OG&E has approximately 776,500 total customers, of which approximately 64,700 are located in Arkansas. It has additional wholesale customers throughout the region. OG&E’s

1 OG&E filed the Direct Testimonies & Exhibits of OG&E Witnesses Howard Motley; Sheri D. Richard; Donald R. Rowlett; Adam Bigknife; John Wendling; Keith Erickson; John J. Spanos; Donald A. Murry, Ph.D.; Greg Veitch; Bryan J. Scott and Gregory W. Tillman. OG&E also filed the Rebuttal Testimonies & Exhibits of OG&E Witnesses Eric Fox; Katherine Prewitt; Philip L. Crissup; Greg Veitch; Bryan Scott; Donald R. Rowlett (as corrected); John J. Spanos; Howard Motley (as corrected); Donald A. Murray; Kenneth C. Johnson

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electricity comes from eleven company-owned power plants, plus purchased power, and is delivered across an interconnected transmission and distribution system that spans 30,000 square miles. OG&E’s principal office is at 321 North Harvey, Oklahoma City, Oklahoma 73102. The Company’s principal place of business in Arkansas is located at 219 Garrison Avenue, Fort Smith, Arkansas 72902. OG&E is a public utility as defined by Act 324 of 1935, as amended, which is codified at Ark. Code Ann. § 23-1-101, et seq., and is subject to the jurisdiction of the Commission. Application at 1-2.

According to Witness Motley, OG&E is seeking a rate increase at this time because:

Two large capital projects have been completed and placed in service since the test year in our last rate case.2 The OU Spirit renewable wind energy facility (OU Spirit) became commercial in December 2009 and the Windspeed transmission line was energized in April 2010. The total capital investment for both projects is approximately $475 million. ... In addition to the two large capital projects, the Company has also invested additional capital in its utility infrastructure. Considering all the capital investment since the last rate case and the depreciation offset, the Company’s net plant in service has increased $549.3 million. During this time, OG&E has also experienced increases in O&M expense. The primary increase in O&M expense is to extend the service life and reliability of the Company’s generation fleet. In 2010, OG&E plans to spend $14.7 million more on fleet maintenance than in the 2009 test year.

Id. at 4 (Footnote in original).

By Order No. 2, issued on October 12, 2010, the Arkansas Public Service Commission (Commission) suspended OG&E's proposed new rates, established a procedural schedule for the filing of testimony, set a public evidentiary hearing to consider OG&E’s Application to begin on May 24, 2011, in Little Rock, Arkansas, and set a public comment hearing to begin on May 31 2011, in Fort Smith, Arkansas. The Parties

2 Docket No. 08-103-U filed on August 29, 2008 (Test Year: 12 months ending December 31, 2007).

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to this proceeding are OG&E, Northwest Arkansas Industrial Energy Consumers (NWIEC),3 the Consumer Utilities Rate Advocacy Division of the Arkansas Attorney General's Office (AG), and the Commission General Staff (Staff) (the Parties).

Pursuant to the procedural schedule established by Order No. 2, Staff, the AG and NWIEC filed their Direct Testimonies & Exhibits4 on March 15, 2011, in response to OG&E’s Application and Direct Testimonies.

Staff, in its Direct Testimony, refuted OG&E’s claimed revenue deficiency of $17,723,253 annually and, based upon Staff’s fully developed Cost of Service Study (COS), recommended the Commission approve a revenue deficiency or rate increase for OG&E of $4,806,206, which is $12,917,047 less than that claimed by OG&E. Staff Witness Sandra B. Green Direct Testimony at 7 (March 15, 2011). The AG did not perform a COS. The AG, however, did address certain issues related to OG&E’s claimed revenue deficiency as well as the rates and tariffs proposed by OG&E. Although the AG’s “investigation does not involve the detailed accounting audit provided by the Staff” AG Witness William B. Marcus testified that “the AG’s analysis has identified at least $8.591 million in reductions from OG&E’s requested rate increase....” Marcus Direct Testimony at 6. NWIEC filed Direct Testimony recommending certain revenue requirement calculations and changes to certain of OG&E’s cost of service and allocation

3 NWIEC filed its Membership List on February 24, 2011, listing the following members: Gerdau MacSteel (which formally withdrew its Petition as an individual Intervenor on March 14, 2011); River Bend Industries; and Cloyes Gear & Products

4 Staff filed the Direct Testimonies & Exhibits of Staff Witnesses Clark D. Cotten; Cindy L. Ireland; Sandra B. Green; Bill Dennis; Robert H. Swaim; Jeff Hilton; Gayle Freier; J. Richard Hornby; Jo Ann Sterling; Regina L, Butler; and Rick Dunn. The AG filed the Direct Testimony & Exhibits of William B. Marcus. NWIEC filed Responsive Testimonies & Exhibits of Mark E. Garrett and Scott Norwood.

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methodologies. Direct Testimonies of NWIEC Witnesses Scott Norwood at 19-20 and Mark E. Garrett at 52.

In Surrebuttal Testimony, Staff and the AG amended their initial recommendations. NWIEC did not file Surrebuttal Testimony. Staff’s Surrebuttal revenue requirement calculation reflected updates to actual pro forma year-end data, corrections for errors, and amendments to certain initial adjustments that Staff made based on additional information. Staff’s Surrebuttal recommended revenue deficiency or rate increase was $8,840,362 which is $8,882,891 less than claimed by OG&E in its Application. Hilton Surrebuttal Testimony at 4. In Surrebuttal, the AG Witness Marcus continued to recommend his original $8.591 million reductions to OG&E’s requested rate increase, but also adopted certain positions of the other parties, increasing his proposed reductions by $179,000. Marcus Surrebuttal Testimony at 5. Specifically, AG Witness Marcus recommended adoption of Staff’s and NWIEC’s adjustments to coal inventory levels and reduced depreciation for the retired Muskogee Unit 3 plant, which reduced the deficiency for Arkansas by $149,000 and $30,000, respectively. Mr. Marcus also adopted Staff’s recommendation to include all Accumulated Deferred Income Taxes (ADIT) in the capital structure but did not quantify the revenue requirement effect of those proposals. Id.

On May 13, 2011, the Parties filed a Joint Motion to Approve Settlement Agreement (Joint Motion) that included Joint Exhibit 1, which was the proposed Settlement Agreement (Agreement) entered into by the Parties. Also filed on May 13, 2011, in support of the Agreement were the Agreement Testimonies of Mr. Motley on behalf of OG&E, Mr. Davis and Mr. Hilton on behalf of Staff, Mr. M. Shawn McMurray

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on behalf of the AG and Mr. Garrett on behalf of NWIEC. In their Joint Motion, the Parties requested “that an order be issued expeditiously excusing all witnesses...” from the evidentiary hearing except the settlement witnesses. Joint Motion at 5. The Agreement also noted that OG&E “requests, and the Settling Parties do not object, that the new rates become effective for bills rendered as soon as possible after a Commission order approving the Agreement but not later than for bills rendered on July 1, 2011[.]” Agreement at 7. On June 6, 2011, OG&E filed revised Compliance Tariffs to conform to the proposed Agreement. Thereafter, on June 7, 2011, Staff Witness Swaim filed Compliance Testimony testifying that the June 6, 2011 Compliance Tariffs accurately reflected the terms of the Agreement.

For good cause shown, the Commission issued Order No. 5 in this Docket on May 18, 2011, granting the Parties’ request to excuse all witnesses from the May 24, 2011 evidentiary hearing with the exception of Mr. Motley for OG&E, Mr. Garrett for NWIEC, Mr. McMurray for the AG, and Mr. Hilton and Mr. Davis for Staff.

As scheduled by Order No. 2 of this Docket, the evidentiary hearing was conducted by the Commission at its office in Little Rock, Arkansas, on May 24, 2011, and the public comment hearing was conducted by the Commission in Fort Smith, Arkansas, on May 31, 2011.

The Agreement

The Agreement, filed on May 13, 2011, and attached hereto as Exhibit 1, submitted jointly by OG&E, NWIEC, the AG and Staff, which were the only parties to this Docket, calls for a rate increase of $8,787,918 for OG&E with an overall cost of capital of 5.93% and an equity return of 9.95%. The Agreement-proposed rate increase

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is $8,935,335 less than originally requested by OG&E and $52,349 less than Staff recommended in its Surrebuttal case. The Agreement called for the following changes to Staff’s Surrebuttal revenue requirement: a reduction to revenue requirement of $10,290 for a correction to depreciation expense; an increase to revenue requirement of $99,083 for a change to Working Capital Assets; and a reduction to revenue requirement of $141,142 related to the change in the equity return. Agreement at 2-3.

The Agreement-proposed revenue requirement, cost of service (COS) allocation of that revenue requirement to rate class, and resulting design of rates, as well as individual tariff issues, all reflect as its basis Staff’s Surrebuttal case with some adjustments that are delineated in the Agreement. Agreement at 2. The revenue requirement differences represent either corrections or updates to Staff’s Surrebuttal case, which Staff advises in its Agreement Testimony are within the range of reasonableness.

The Agreement-proposed rates would cause a typical OG&E residential customer’s monthly bill, based on 1,000 kWh per month usage, to increase $2.32 per month, including fuel costs, or 3.17%.5 See Letter addressed to Jan Sanders, Secretary of the Commission, which was signed by Counsel for OG&E and filed in this Docket on May 26, 2011. A typical OG&E low-use General Service customer’s monthly bill, based on 2,000 kWh per month usage, would increase $0.32 per month, including fuel costs, or 0.22%. A typical OG&E high-use General Service customer’s bill, based on 7,000 kWh per month usage, would increase $18.37 per month, including fuel costs, or 4.15%. Id.

5 The percentage increase was corrected from 3.71% to 3.17% per Staff Witness Swaim’s Compliance Testimony at 3 (June 7, 2011).

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Following are the major points of the Agreement:

Staff’s rate base, as modified, and Staff’s statement of net operating income, as adjusted, will be used to determine OG&E’s overall revenue requirement;

An overall rate of return on rate base of 5.93% will be used to determine OG&E’s overall revenue requirement;

The overall Agreement non-fuel rate schedule revenue requirement, Arkansas jurisdiction, for OG&E will be $88,607,368, with a resulting revenue deficiency of $8,787,918;

The Agreement relies on Staff’s COS, which was developed using the allocation methods and factors embodied in Staff’s COS as well as the mitigation of customer impact proposed by Staff Witness Green’s Surrebuttal Testimony;

The billing determinants for the Arkansas jurisdiction will be those included in the Staff Witness Swaim’s Direct Exhibit RHS-1;

OG&E’s jurisdictional allocation factors will be based on OG&E’s billing determinants. Staff’s billing determinants will be used to calculate Arkansas’s rate class allocation and to design rates;

Staff’s depreciation rates, as proposed by Staff Witness Gayle Freier in her Surrebuttal Testimony, are adopted;

Consistent with Staff Witness Swaim’s Testimonies, the rate design changes reflected in the Agreement are as follows;

The General Service class customer charge will remain constant but the Residential class customer charge will increase at the system average increase level;

OG&E’s rate design will comply with Staff’s block design recommendations;

OG&E will offer both a demand-based and energy-based Time of Use (TOU) rates for its Power and Light (P&L) customers. Rate Schedules Service Levels (SL) SL-2, SL-3 and SL-4 will be recombined into a single PL-TOU Energy rate schedule. Rate Schedule SL-1 PL-TOU Energy will include a “super peak” period rate within the defined peak during the hours of 4:00 pm to 6:00 pm;

OG&E will offer Residential and General Service Time of Use rates, but will not include a senior citizen discount;

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OG&E will offer Residential and General Service Variable Peak Pricing rates, but will not include a senior citizen discount and customers will pay for incremental meter costs;

OG&E will not offer flat bill rates; and

OG&E will not offer a Customer Education and Demand Rider. OG&E may defer, for accounting purposes, the proposed expenses associated with the customer education program for an amount not to exceed $300,000 per year for a maximum of two years.

All OG&E tariffs and tariff provisions will follow Staff’s recommendations unless otherwise provided for within the Agreement and OG&E’s tariffs will not include a Customer Education and Demand Response (CEDR) Rider, a Pension and Other Post-Employment Benefits (OPEB) Rider or a Storm Damage Cost Recovery Rider;

OG&E's Energy Cost Recovery Rider (ECRR) will be the one outlined in Staff Witness Butler’s Surrebuttal Testimony;

OG&E will have a new Transmission Cost Recovery Rider (TCRR) as outlined in Staff Witness Butler’s Surrebuttal Testimony;

OG&E will allow Day-Ahead Pricing (DAP) customers to participate in the Load Reduction (LR) Rider, provided that the terms of both tariffs are properly defined to prevent duplicate benefits for the reduction in load. Purchased power capacity costs related to the LR Rider may be temporarily recovered through Rider ECR until the next rate case. In the next rate case purchased power capacity costs related to the LR Rider will be incorporated in base rates;

OG&E may defer, for accounting purposes, customer education program expenses for an amount not to exceed $300,000 per year for two years and the deferred costs will be reviewed in OG&E’s next rate case;6 and

6 During the evidentiary hearing, in response to Commissioner questioning , OG&E Witness Motley testified that the program’s purpose was “strictly customer education about [OG&E’s] new programs, like the different time of use program[s], the different rate type of proposals,…” in order to help customers select the program that is appropriate for them and to encourage energy efficiency. May 24, 2011 Evidentiary Hearing Transcript (Tr.) 1016. According to Mr. Motley, the Agreement-proposed $300,000 “will be 100 percent use to educate [OG&E’s] customers only on [its] new proposed tariffs and programs.” Id. In addition, OG&E committed to bring its marketing and customer education team to “meet with all the parties in this case and go through where [OG&E is] going to spend those dollars before…” OG&E spends any of the allotted money on its education programs. Id. at 1016-1017. Given the Parties’ litigated positions on the customer education program, the Commission accepts the education spending proposal as part of the concessions made to reach the unanimous Agreement. That said, the

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OG&E shall comply with the Allowance for Funds Used During Construction (AFUDC) recommendation reflected in the Surrebuttal Testimony of Staff Witness Jo Ann Sterling.

Agreement Testimony

OG&E Witness Motlev:

OG&E Witness Motley testified that OG&E “believes the Agreement is a reasonable compromise of the positions of the various parties or stakeholders” and that the Agreement “produces an equitable balance of customer and of shareholder interests.” Further, the “provisions of the Agreement lie within the bounds of the filed positions advocated by the various parties and the end result is just and reasonable.” Motley Agreement Testimony at 6. Viewed in its totality, Mr. Motley testified:

[T]he Agreement provides benefits for all classes of customers and is in the public interest. The result of the Agreement reached by the parties is within the range of likely outcomes if the issues in the proceeding were litigated. The Agreement is a carefully crafted compromise that produces rates that are just and reasonable and are in the public interest, without the need for additional expenditure of time or money by any party in the litigation process. OG&E believes the result reached in the Agreement fairly balances the needs of all stakeholders.

Id. at 6-7.

Finally, Mr. Motley testified that the Agreement “is a targeted balance in protection of customers, fairness to investors and maintaining OG&E’s long-term financial and operational viability. As in any good compromise, the end product does not result in attainment of all the results sought by any one party. ... [but OG&E] supports the Agreement as a reasonable compromise that is in the overall public interest and it is committed to adhere to the obligations pursuant to the Agreement.” Id.

Commission encourages OG&E to consider the potential for such energy efficiency education programs to be included as part of its energy efficiency filings in Docket No. 07-075-TF in the future. See Tr. 1017.

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Staff Witnesses Hilton and Davis:

Staff Witness Hilton testified that three adjustments were made to Staff’s Surrebuttal case but “[a]side from these adjustments, the agreed upon Revenue Requirement reflects Staff’s position in its Surrebuttal case.” Hilton Agreement Testimony at 3. The three adjustments were related to Staff’s depreciation expense, working capital assets, and the return on equity. Id. at 4-5.

Further, Mr. Hilton testified that the Agreement adopts Staff Witness Butler’s Surrebuttal recommendations regarding the ECRR as amended to incorporate her newly-recommended Transmission Cost Recovery Rider (TCRR), which will permit OG&E to recover charges paid to the Southwest Power Pool for transmission-related projects and service, a Day-Ahead Pricing (DAP) tariff and a Load Reduction Rider (LR Rider) to recover the costs of certain reporting requirements related to the DAP as well as amendments to the Uniform Municipal Tax Adjustment Rider (Rider MTA). Hilton Agreement Testimony at 4-7.

Mr. Hilton also notes that the Agreement does not include an OPEB tracker or storm damage cost rider, consistent with Staff’s recommendation in its Direct Testimony. Id. at 6. Mr. Hilton testifies that the Agreement adopts the depreciation rates as recommended by Staff in its Surrebuttal case and are attached to the Agreement as Attachment 2. Id. at 3. In addition, Mr. Hilton notes three recommendations made by Staff Witness Freier related to depreciation expense and accumulated depreciation which were incorporated into the Agreement and accepted by OG&E, specifically the:

Requirement that OG&E maintain depreciation expense and accumulated depreciation on an individual FERC account level, by plant and unit, and report in the same manner in future rate applications;

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Continuing obligation to adjust its accumulated depreciation to reflect Arkansas-approved depreciation rates, however, prospectively in accordance with the functional/FERC account/plant/unit allocation that Staff performed in this case; and

Requirement that OG&E fully explain any adjustment to per book amounts in its initial testimony or depreciation study, or include a workpaper that fully explains and supports the adjustment.

Id. at 6-7.

Finally, as noted previously, Mr. Hilton testified that the Agreement “has as its foundation each of the recommendations set forth in Staff’s Surrebuttal Case and supported by Staff Witnesses.” Id. at 7. Mr. Hilton “supports as reasonable each of the three adjustments which were made to the Revenue Requirement. Otherwise the Agreement reflects in its entirety the recommendations of Staff Witnesses on these issues as reflected in Staff’s Direct and Surrebuttal Testimonies,” Id. As a result, Mr. Hilton testifies that he “support[s] as reasonable these provisions of the Agreement and recommend[s] their approval.” Id.

Staff Witness Kim O. Davis testified that the Agreement “uses the cost classification and allocation methodologies embodied in Staff’s Surrebuttal COS Study as presented in Staff Surrebuttal Exhibit SBG-1 of Staff Witness Green.” Davis Agreement Testimony at 4. In addition, consistent with Staff Witness Green’s Surrebuttal Testimony, the customer impact is mitigated “for the different service levels within a class showing a surplus, the surplus should first be distributed in a fair manner to the other service levels above the system average within that class. Then, the revenue surplus resulting from the Lighting class shall be distributed in a fair manner among the classes/service levels requiring a larger-than-system-average increase.” Id. The resulting

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overall increase in rate schedule revenues is 11.01% and on “a total bill basis, including the cost of fuel, the system average increase is 5.28% with the Residential customer class receiving approximately an 8.41% base rate increase and a 4.61% total bill increase.” Id. at 5.

The Agreement also reflects the Parties’ agreement to design rates using the billing determinants recommended by Staff Witness Swaim in Direct Exhibit RHS-1 and relies on Staff’s rate design recommendations as follows:

The customer charge for the Residential class will increase by the system average increase; The customer charge for the General Service class will not change;

OG&E’s rate design will comply with Staff’s recommendations regarding block design;

OG&E will offer both demand-based and energy-based Power and Light-Time of Use (PL-TOU) rates. Rate schedules SL-2, SL-3 and SL-4 will be recombined into a single PL-TOU Energy rate schedule as is the case in the currently-approved tariff. Rate schedule SL-1 PL-TOU Energy will include a “super peak” period rate during the hours of 4:00 pm to 6:00 pm;

OG&E will offer Residential and General Service Time of Use rates, but will not offer a senior citizen discount;

OG&E will offer Residential and General Service Variable Peak Pricing rates, but will not offer a senior citizen discount and customers will pay for incremental meter costs;

OG&E will not offer flat bill rates; and

OG&E will not offer a CEDR but OG&E may defer, for accounting purposes, the proposed expenses associated with the customer education program for an amount not to exceed $300,000 per year for a maximum of two years. This amount should include only incremental charges, i.e., excluding salaries, postage or other costs already considered in base rates, and should only be for the purposes of educating or informing customers and without the accrual of carrying charges. The deferred costs will be reviewed in

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OG&E’s next retail rate case to ensure the costs reasonably meet the above requirements for future recovery.

Id. at 5-7.

Mr. Davis notes that Section 4 of the Agreement “reflects that OG&E requests, and the Settling Parties do not object, that the new rates become effective for bills rendered as soon as possible after a Commission order approving the Agreement but not later than for bills rendered on July 1, 2011.” Id. at 7. In addition, Mr. Davis states OG&E will file compliance tariffs consistent with the Agreement on or before June 7, 2011, followed by Staff’s Compliance Testimony on or before June 8, 2011. Id.

Mr. Davis testifies he supports as reasonable these provisions of the Agreement and recommends their approval because he believes the Agreement “produces reasonable rates that mitigate adverse rate impact to the customer classes and that are supported by Staff’s Direct and Surrebuttal Testimonies.” Id.

AG Witness McMurray:

AG Witness McMurray first noted that:

OG&E requested an overall rate increase of approximately $17.7 million, including $5.7 million from residential customers, plus several riders, one of which would increase ratepayer bills by more than $875,000 per year. This included a recommended return on equity of 11.25%, and an increase in the residential customer charge from $7.15 to $15.50, and in the General Service class’s customer charge from $21.75 to $32.00.

McMurray Agreement Testimony at 3. Mr. McMurray testified that the AG’s office:

Opposed OG&E’s requested increase, based on (1) substantially lowering the return on equity to 9.6% and adjusting the hypothetical capital structure; and (2) rejecting certain inappropriate expenses, especially involving executive compensation, advertising and dues and donations. The AG also recommended changes in rate design to encourage conservation, and to avoid undue negative impact on lower-income customers and subsidization of electric heat. “We particularly opposed the drastic increase in the monthly residential and commercial customer

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charge.

Id. at 3. Additionally, the AG opposed many of the new riders OG&E proposed, specifically the CEDR Rider. Id. at 4. Noting the AG had concerns with “the overall rate increase requested by OG&E...,” Mr. McMurray testified that the Agreement addresses the AG’s major concerns in the following ways:

It reduces the overall rate increase to OG&E’s customers to $8.8 million - $8.9 million less than originally requested (lowering the increase by 50.3%);

It reduces the increase in rates for the residential class of customers to $2.4 million - $3.3 million less than originally requested (lowering the increase by 57.9%);

The authorized return on equity will be 9.95% - far lower than the requested 11.25% (and between the AG’s recommended 9.6% and Staff’s recommended 10.0%) - and the hypothetical capital structure is 46% equity, as recommended by Staff;

On cost allocation, the Agreement does not materially change cost allocation methodologies recommended by the AG, but does mitigate the impact on larger customers in conformity with accepted Commission practice, which is important given economic development concerns;

The residential customer’s monthly service charge is increased by only 11% (the system average percentage increase), from $7.15 to $7.94, instead of the requested 117% increase to $15.50;

The General Service customer’s monthly service charge remains unchanged, instead of increasing it 47% to $32.00, as requested;

The Rider CEDR is rejected, as is the requested $875,000 budget and program for education and evaluation. Instead, OG&E may defer, for accounting purposes, the proposed expenses associated with the customer education program - but capped at $300,000 per year - for a maximum of two years. Furthermore, this amount may only include incremental charges, (i.e., excluding salaries, postage or other costs already considered in base rates), may only be for the purposes of educating or informing customers (e.g., no image advertising) and cannot accrue carrying charges. Furthermore, review of the costs of customer education and the

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determination of appropriateness for recovery will be considered in OG&E’s next retail rate case; and

Finally, in rate design, the Agreement provides a moderately lower flat winter rate, and in summer rates moves in the direction of more cost-based and conservation-friendly rates, but at the same time minimizing customer impacts.

Id. at 4-5.

As a result, Mr. McMurray stated the Agreement “addresses the concerns of the Attorney General in this docket in a reasonable way. The Agreement is far better for ratepayers than OG&E’s initial proposal.” Id. at 4. In addition, the AG’s office recommended the Agreement “be approved by the Commission, as being in the public interest.” Id. at 3.

NWIEC Witness Garrett:

According to NWIEC Witness Garrett, the Agreement “addresses and satisfactorily resolves certain of the issues raised by NWIEC.” Garrett Agreement Testimony at 1. Mr. Garrett states the Agreement “provides that OG&E will offer a new energy-based Power and Light Time of Use Rate for those customers that elect to take service under this Tariff. This will have a positive impact on those customers who are able to shift load away from higher priced peak hours. This shift in load will also benefit OG&E’s entire system.” Id. at 2. Mr. Garrett notes the inclusion of a “Super Peak” period within the defined peak from 4:00-6:00 pm daily and he asserts establishing such a “Super Peak” provides “a strong incentive for OG&E’s largest customers to shift load off of the peak hours, the most costly hours on the system.” Id. at 2-3. Mr. Garrett notes this benefits customers and OG&E alike by avoiding higher fuel costs and delaying investments in planned plant additions. Id. at 3. In conclusion, Mr. Garrett states the

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Agreement “provides for an overall fair and equitable resolution of the issues raised in this proceeding and is justified by the testimony filed in support thereof.” Id.

Commission Findings

Overall Rate Increase/Revenue Requirement:

Based on the evidence submitted by OG&E, NWIEC, the AG and Staff and through their Testimonies and Exhibits, prior to the initiation of settlement discussions, the Commission finds that OG&E is entitled to a rate increase in this proceeding. If uncontested, the Direct Case evidence submitted by OG&E would support a rate increase of $17,723,253; if uncontested, the Direct Case evidence submitted by the AG’s Witness would support a rate increase of no more than $9,132,309, which after Surrebuttal, would have reduced that increase by another $179,000;7 and if uncontested, the Direct Case evidence submitted by Staff would support a rate increase of $4,806,206, compared to $8,840,362 in Staff’s Surrebuttal case. The Agreement calls for a revenue increase in the amount of $8,787,918. The following Table 1 reflects the litigated Adjusted Rate Base (ARB), Return on Equity (ROE), overall Rate of Return (ROR), Debt-to-Equity ratio (D/E), non-fuel Rate Schedule Revenue Requirement (RR) and Revenue Deficiency (RD) positions of the parties and the resolution of these issues as reflected in the Agreement.

7 AG Witness Marcus’ adoption of Staff’s and NWIEC’s adjustment to coal inventory levels and the Staff reduction to depreciation expense for the retired Muskogee Unit 3 plant reduces the deficiency by $149,000 and $30,000, respectively. Marcus Surrebuttal Testimony at 5.

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Table l Parties’ Proposals for Overall Rate Increase/Revenue Requirement
	OG&E’s Initial Case8	Staff’s Surrebuttal Case	AG’s Direct Case9	Agreement
ARB	$443,875,276	$422,652,614	$443,839,401	$428,864,662
ROE	11.25%	10.0%	9.60%	9.95%
ROR	6.61%	5.95%	5.81%	5.93%
D/E	43% to 57%	54% to 46%	53% to 47%	54% to 46%
RR	$99,789,093	$88,659,813	$91,198,149	$88,607,368
RD	$17,723,253	$8,840,362	$9,132,309	$8,787,918

Staff Witness Hilton testified that three adjustments were made to Staff’s Surrebuttal positions as a result of the Agreement, but otherwise “the agreed upon Revenue Requirement reflects Staff’s position in its Surrebuttal case.” Hilton Agreement Testimony at 3. Further, the AG, who “is charged by statute10 with representing the interests of Arkansas ratepayers” supported the Agreement “as being in the public interest.” McMurray Agreement Testimony at 3. Similarly, OG&E Witness Motley testified that “OG&E supports the Agreement as a reasonable compromise that is in the overall public interest...” Motley Agreement Testimony at 7. Finally, NWIEC Witness Garrett concurs that the Agreement “provides for an overall fair and equitable resolution of the issues raised in this proceeding...” Garrett Agreement Testimony at 3.

Based on the pre-filed Direct, Rebuttal and Surrebuttal Testimonies & Exhibits of OG&E, NWIEC, the AG and Staff, and the Agreement Testimonies of Staff Witnesses Hilton and Davis, AG Witness McMurray, OG&E Witness Motley and NWIEC Witness

8 OG&E did not provide an amended Revenue Requirement and Deficiency calculation incorporating the changes it proposed in its Rebuttal Testimony.

9 AG Witness Marcus testifies that his proffered revenue requirement calculation “does not constitute a complete case on revenue requirements.” Marcus Direct Testimony at 6-7. The AG did not provide a comprehensive recalculation of Revenue Requirement and Deficiency updated to reflect his Surrebuttal position.

10 Ark. Code Ann. § 23-4-301, et seq.

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Garrett, the Commission finds that the Agreement-proposed rate increase of $8,787,918 is supported by substantial evidence and is just and reasonable.

Allocated Cost of Service:

The following Table 2 reflects the percentage non-fuel base rate increases for each of the various customer classes which would have resulted from the litigated Cost of Service positions of the Parties. Table 2 also reflects the unmitigated and mitigated rate increase resulting from the Agreement.

Table 2 Rate Impact – Percentage Increase (Decrease) By Customer Class
	Litigated Case		Agreement Case
Customer Class	OG&E’s Initial	Staff’s Surrebuttal	Unmitigated Agreement	Mitigated Agreement
Total	$17,723,253	$8,840,362	$8,787,918	$8,787,918
Residential	19.44	8.50	8.41	8.41
General Service	18.94	6.15	6.06	6.06
Power & Light (P&L)	24.74	13.31	13.25	12.54
P&L Time-of-Use	26.65	18.92	18.90	17.29
Lighting	(5.16)	(14.79)	(14.91)	0.00
Municipal Pumping	26.30	18.51	18.39	16.56
Athletic Field Lighting	32.25	10.42	10.29	10.29
Total % Retail	21.60%	11.08%	11.01%	11.01%

Staff Witness Davis testifies that the Agreement adopts Staff’s allocation methods and factors in the calculation of the COS Study and, consistent with Staff’s Surrebuttal position “to mitigate customer impact, ... the revenue surplus resulting from the Lighting class shall be distributed in a fair manner among the classes/service levels requiring a larger-than-system-average increase.” Davis Agreement Testimony at 4. Mr. Davis testifies that OG&E’s increase for total bills, including fuel, will be 5.28%, with mitigated total bill increases by customer class as follows: Residential-4.61%; General Service-3.36%; Power & Light (P&L) -5.73%; P&L Time-Of-Use-6.60%; Lighting-0.00%; Municipal Pumping-8.96%; and Athletic Field Lighting-6.15%. Id. at 5.

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AG Witness McMurray testifies that “the Agreement does not materially change cost allocation methodologies recommended by the AG, but does mitigate the impact on larger customers in conformity with accepted Commission practice, which is important given economic development concerns.” McMurray Agreement Testimony at 5. Similarly, NWIEC Witness Garrett supports the Agreement even though NWIEC’s “recommendations regarding class cost of service allocation issues were not incorporated into the Settlement...” because other NWIEC recommendations were addressed by the Agreement. Garrett Agreement Testimony at 1.

The Commission, therefore, finds that the Cost of Service Study methodology and allocations and the resultant mitigated rate increases to each class contained within the Agreement are just and reasonable and are approved.

Rate Design:

The following Table 3 reflects the resulting increases to the fixed monthly Customer Charge by rate class.

Table 3 Proposed Monthly Customer Charge By Customer Class
Class	Current	OG&E Proposed	Agreement Mitigated
Residential	$7.15	$15.50	$7.94
General Service	$21.75	$32.00	$21.75
P&L and P&L TOU-SL-111	$300.00	$500.00	$450.00
P&L and P&L TOU-SL-2,312	$225.00	$300.00	$225.00
P&L and P&L TOU-SL-413	$225.00	$85.00	$225.00
P&L and P&L TOU-SL-5	$75.00	$85.00	$85.00
Municipal Pumping	$28.00	$32.00	$28.0014

11 The Power & Light Time of Use Service Level (P&L TOU SL) Rate Schedules include an Energy (E) and Demand (D) class, but the customer charges will be the same for each.

12 Rate schedules Service Level-2, 3 and 4 will be recombined into a single PL-TOU Energy rate schedule under the Agreement.

13 Id.

14“This rate schedule is closed and is only available to a premise served under this rate schedule as of the December 2011 billing cycle.” Rate Schedule PM-1.

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OG&E’s Compliance Tariffs (June 6, 2011).

Staff Witness Davis testified that the agreed-upon rate design follows the recommendations set forth in the pre-Agreement Testimonies of Staff Witness Swaim, using Mr. Swaim’s recommended Arkansas billing determinants. Davis Agreement Testimony at 5. In recent orders in furtherance of the Commission’s Energy Efficiency (EE) initiatives, the Commission has promoted EE through rate design by directing several utilities to adopt an inclining block rate design structure. The Commission finds that the inclining block rate design proposed in this Docket represents progress toward the Commission’s EE goals. Mr. Davis further testified that the Agreement “produces reasonable rates that mitigate adverse rate impacts to the customer classes....” Id. at 7.

AG Witness McMurray testified that the Agreement “addresses the concerns of the Attorney General ... in a reasonable way...” in light of the AG’s “recommended changes in rate design to encourage conservation, and to avoid undue negative impact on lower-income customers and subsidization of electric heat.” McMurray Agreement Testimony at 3-4. Mr. McMurray also testified that the AG opposed the drastic increases in the customer charges OG&E proposed, and the Agreement-which minimizes or holds constant customer charges-is “in the public interest.” Id.

As a result, the Commission finds that the rate design and resulting rates are just and reasonable and are approved.

Tariffs and Tariff Provisions:

Transmission Cost Recovery Rider (TCRR)

In July 2009, the Commission initiated Docket No. 09-074-U to consider the appropriate rate treatment of regionally-allocated transmission costs charged to

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Southwest Power Pool Regional Transmission Organization (SPP RTO) members, of which OG&E is one. The Commission found as a general principle that retail rate recovery of transmission costs through a rider mechanism is in the public interest so long as it is designed to fairly balance the interests of SPP members and their customers. Docket No. 09-074-U, Order No. 6 at 22 (August 5, 2010). In addition the Commission provided additional guidance with regard to that balancing of interests stating:

Such a rider is fairly balanced if it allows Arkansas’s jurisdictional SPP members to timely recover their transmission costs while ensuring that their customers in return receive the benefits of RTO membership through a transmission rider, the energy cost recovery rider, or similar mechanism.

Id. at 24-25.

Based on the evidence presented in that Docket, the Commission concluded once an Arkansas utility becomes a member of the SPP RTO, the management of the utility has significantly less control over transmission cost levels because planning and construction are determined on a regional basis. The Commission also cited the fact that:

Such an approach is one of the fundamental reasons for the creation of RTOs, The result is that ratepayers, including Arkansas ratepayers, have access to lower cost generation resources while maintaining all jurisdictionally-mandated reliability standards.

Id. at 21-22.

Recently, the Commission found just and reasonable and in the public interest a Transmission Cost Recovery Rider (TCRR) as recommended by Staff for the Empire District Electric Company and as incorporated into a Settlement Agreement proposed by the Parties to that Docket, which was Empire’s most recent rate case. Docket No. 10-052-U, Order No. 7 at 23 (April 12, 2011). The provisions of that Staff-recommended

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TCRR were “designed to: (1) recover the actual amount of SPP charges paid by Empire for the costs included in SPP Schedule lA Administrative Service and SPP Schedule 11 -Base Plan Charges; (2) include the benefits of incremental revenues received by the Company from SPP for point-to-point transmission service; (3) include the benefits of incremental revenues received by the Company from off-system or EIS market sales; and (4) eliminate a rate of return.” Id. at 22.

By its Application in this Docket, OG&E proposed its Southwest Power Pool Cost Recovery Rider (SPPCR) as a modification to “the manner in which it recovers a portion of its transmission costs from Arkansas retail customers.” OG&E Witness Rowlett Direct Testimony at 17. Witness Rowlett testified that OG&E recommends this change as a result of the effect of SPP’s currently-approved methodology for the allocation of regionally-beneficial transmission project costs to SPP members, including OG&E. That cost allocation methodology was developed “with input and guidance from state regulatory commissions through the SPP’s Regional State Committee (RSC)....” Rowlett Direct Testimony at 17. The Commission is a member of the SPP RSC.

Under that methodology, OG&E will be responsible to SPP for its allocated share of regional costs for certain projects built by other members as well as have the right to revenues for certain of its own investments included as part of the regional rate. Under its SPPCR, OG&E proposed (1) the recovery of those regional costs from ratepayers and (2) the return of those regional revenues to ratepayers. Additionally, OG&E requested recovery of SPP administrative charges. Rowlett Direct Testimony at 17-18. Mr. Rowlett testified that both the SPP regional transmission costs as well as the SPP administrative charges “are not only significant but are also outside OG&E’s control... [and w]ithout a

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rider, cost increases occurring between rate cases would be lost and not recoverable.” Id. at 20.

Staff Witness Butler responded to OG&E’s proposed tariff and testified that she agreed:

with the Company’s proposal to recover the SPP administrative fees billed in SPP Schedule lA and the base plan charges related to others billed in SPP Schedule 11. Recovery of regionally-allocated costs is consistent with the Commission’s Order No. 6 in Docket No. 09-074-U, and the development of the Day Two Market is expected to provide benefits to ratepayers through reduced energy costs.... [however]... [t]o fully capture the benefits of RTO membership, ratepayers should be protected from any downside risk of revenues credited to customers being less than the test year level. Thus, the amount of point-to-point transmission revenues credited to customers through the rider should be a minimum of the test year Arkansas jurisdictional level of $830,171 plus any revenues above the test year amount.

Butler Direct Testimony at 8.

Further, because the rider will provide timely recovery of the SPP transmission and administrative costs, Ms. Butler concluded that application of a carrying charge is not appropriate. Id. at 9. Ms. Butler recommended:

that the Commission approve [her] proposed Transmission Cost Recovery Rider (TCR Rider) included as Direct Exhibit RLB-1. [She] recommend[ed] that the TCR Rider be designed to: (1) recover the actual amount of SPP charges paid by OG&E for the costs included in SPP Schedule lA, Tariff Administration Service, and SPP Schedule 11, Base Plan Charges paid to others; (2) include the benefits of revenues received by the Company from SPP for point-to-point transmission service at a minimum of the test year amount and any revenues in excess of the test year level; and (3) eliminate carrying costs.

Id. at 10.

In rebuttal to Ms. Butler’s recommendation to set a minimum revenue level in the Staff-proposed tariff, OG&E Witness Rowlett testifies that “Staff’s proposal has undone the ‘balance of interests’ recognized as appropriate by the Commission ... [and

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that]... [t]he Commission should reject the establishment of minimum levels of revenue credits in the SPPCR....” Rowlett Rebuttal Testimony at 10-11. Mr. Rowlett also testified that the tariff demand allocation factor required adjustment for OG&E’s wholesale customers, which are already billed for these charges. Id. at 11

In her Surrebuttal Testimony, Ms. Butler continued to support the “foundational elements” of her originally-proposed TCRR that she corrected for the demand allocation factor addressed by Mr. Rowlett and updated to reflect actual test year transmission revenues. Butler Surrebuttal Testimony at 5-6. She recommended

that the Commission approve [her] updated TCR Rider attached as Surrebuttal Exhibit RLB-1, which reflects the update to the minimum level of point-to-point transmission revenues and the revised definition for the transmission allocator.

Id, at 7.

In his Agreement Testimony, OG&E Witness Motley testified that the Parties agree to the implementation of a Transmission Cost Recovery Rider as set forth in Staff Witness Butler’s Surrebuttal Exhibit RLB-1. Motley Agreement Testimony at 5. Staff Witness Hilton testified that “[t]he recommended TCR Rider ... is designed to recover Southwest Power Pool (SPP) charges paid by OG&E included in SPP Schedule lA, Tariff Administration Service, and SPP Schedule 11, Base Plan Charges paid to others, and include the benefits of revenues received by the Company from SPP for point-to-point transmission service at a minimum of the pro forma year amount plus any revenues in excess of the pro forma year level.” Hilton Agreement Testimony at 5. Mr. Hilton testified further that, “[a]s noted in Staff Witness Butler’s Surrebuttal Testimony, the foundational elements of Staff s recommendations are consistent with those approved in Docket No. 10-052-U (Commission Order No. 7) for a similar rider for The Empire

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District Electric Company.” Id. at 5.

Energy Cost Recovery Rider (ECRR)

In its Application, OG&E sought changes to its ECRR by which it proposed to:

Incorporate time-differentiated ECRR factors for Time Of Use service customers;

Exclude from the ECRR wind energy purchased or produced by OG&E, absent Commission approval of the related purchase contracts or OG&E-owned wind facilities;

Include a provision for uncollectible account costs as part of the ECRR; and

Include a provision for the pass-through of carbon taxes or other costs of future legislation.

Rowlett Direct Testimony at 26.

Staff Witness Butler recommended approval of OG&E’s requested incorporation of time-differentiated ECRR factors for Time of Use service customers into the tariff as appropriate. Butler Direct Testimony at 13. Ms. Butler further recommended that OG&E seek cost recovery of wind energy through the Arkansas Clean Energy Development Act, which allows for Commission review and approval prior to recovery, and that the ECRR be revised to state that recovery of energy costs associated with wind energy Purchased Power Agreements (PPAs) must be approved by the Commission prior to ECRR recovery. Id. at 14-15. Ms. Butler also recommended that OG&E provide an additional report addressing fuel and purchased energy issues with its annual ECRR filing. Id. at 17.

Addressing OG&E’s proposal to include provisions for the recovery of uncollectible customer account costs and carbon taxes, and other costs of legislation in the ECRR, Ms. Butler testified that inclusion of these provisions is neither necessary nor

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appropriate. Id. at 14-17. In addition, Ms. Butler recommended that “the current benefits of off-system and Energy Imbalance Service (EIS) market sales credited to ratepayers through the ECR Rider should be a minimum of the test year Arkansas jurisdictional level ... plus any revenues in excess of the test year amount.” Id. at 9. Finally, Ms. Butler proposed new reporting requirements related to fuel and purchased energy costs to be included with OG&E’s annual ECR Rider filing. Id. at 17-18. Staff Witness Butler provided as Direct Exhibit RLB-1 her recommended ECRR for Commission approval. Id. at 18.

In Rebuttal, OG&E Witness Rowlett recommended, in conjunction with his recommendation made for the TCRR, rejection of Staff’s proposal to set a minimum test-year level of off-system sales and EIS market sales revenues within the ECRR, testifying that “[t]he Commission should reject the establishment of minimum levels of revenue credits in the... ECR rider[].” Rowlett Rebuttal Testimony at 11.

Staff Witness Butler, in Surrebuttal Testimony, continued to support her proposed provisions for the ECRR, recommending that the Commission approve her “updated ECR Rider, attached as Surrebuttal Exhibit RLB-2, which reflects the update to the minimum level of off-system and EIS market sales revenues ... [and] ... that the currently effective ECR Rider rates be updated to reflect the transfer of the collection of the point-to-point transmission revenues to the TCR Rider,” Butler Surrebuttal at 7.

Staff Witness Hilton, in his Agreement Testimony, testified that Section 315 of the Agreement is consistent with “the Surrebuttal Testimony and Exhibits of Regina L. Butler… [and that]... Rider ECR was included as Surrebuttal Exhibit RLB-2 and reflects

15 Section 3 of the Agreement, styled Cost Allocation And Rate Design, also addresses certain other Tariffs and Tariff Provisions agreed upon by the Parties.

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changes due to the recommended implementation of Rider TCR. In addition, it provides for time-differentiated ECR factors for customers on time-of-use rates, language stating that recovery of energy costs associated with wind energy PPAs must be approved by the Commission prior to recovery through the Rider ECR, and certain reporting requirements.” Hilton Agreement Testimony at 4-5. Mr. Hilton concludes that “the Agreement reflects in its entirety the recommendations of Staff witnesses on these issues as reflected in Staff’s Direct and Surrebuttal Testimonies ...” thus, he supports "as reasonable these provisions of the Agreement and recommend[s] their approval." Id. at 7.

The Commission finds that the TCRR proposed in the Agreement is supported by the record and is both consistent with the Commission’s requirement as set out in Docket No. 09-074-U that such a rider balance the interests of both the utility and its ratepayers and with its approval of the TCRR in Docket No. 10-052-U. In addition, the Commission finds that the ECRR, as well as the other tariffs and tariff provisions proposed in the Agreement, are supported by the filed Testimonies and Exhibits included in the record.

As a result, the Commission finds that the tariffs and tariff provisions as proposed by the Agreement are just and reasonable and they are approved.

Ruling of the Commission

1. Based on the Direct, Rebuttal and Surrebuttal Testimonies & Exhibits, the Agreement and Agreement Testimonies & Exhibits filed in this proceeding by OG&E, NWIEC, the AG and Staff, the Commission finds that the Agreement, in its totality, is

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supported by substantial evidence and is just, reasonable and in the public interest. Accordingly, the Agreement is approved; and

2. Based on Staff Witness Swaim’s Compliance Testimony filed on June 7, 2011, the Commission finds that OG&E’s June 6, 2011 Compliance Tariffs comply with the Agreement’s provisions and, therefore, are approved effective for all customer bills rendered after the date of this Order.

BY ORDER OF THE COMMISSION,

This 17th day of June, 2011.

		/s/ Colette D. Honorable
		Colette D. Honorable, Chairman

		/s/ Olan W. Reeves
		Olan W. Reeves, Commissioner

		/s/ Elana C. Wills
		Elana C. Wills, Commissioner

/s/ K. Rhude (Acting)
Jan Sanders
Secretary of the Commission

BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION

IN THE MATTER OF THE APPLICATION	)
OF OKLAHOMA GAS AND ELECTRIC	)	DOCKET NO. 10-067-U
COMPANY FOR APPROVAL OF A GENERAL	)
CHANGE IN RATES AND TARIFFS	)

JOINT MOTION TO APPROVE SETTLEMENT AGREEMENT

Come now the General Staff of the Arkansas Public Service Commission (Staff), Oklahoma Gas and Electric Company (OG&E), the Consumer Utilities Rate Advocacy Division of the Arkansas Attorney General's Office (AG), and Northwest Arkansas Industrial Energy Consumers (NWIEC), hereinafter collectively referred to as “the Settling Parties” and being all the parties to the above-referenced Docket, and for their Joint Motion to Approve Settlement Agreement (Joint Motion) state as follows:

1. The Settling Parties have reached agreement on the issues outstanding in Docket No. 10-067-U. This Settlement Agreement (Agreement) is set forth in and attached hereto as Joint Exhibit. By this Joint Motion, the Settling Parties are requesting that the Arkansas Public Service Commission (Commission) approve the Agreement. The Agreement, inter alia, resolves all issues, including revenue requirement, and provides for the subsequent filing of compliance tariffs to effectuate this Agreement as soon as possible, but no later than June 7, 2011.

2. As support for the Agreement and concurrent with the filing of this Joint Motion, the following witnesses are sponsoring Settlement Agreement Testimonies:

Howard Motley for OG&E

Jeff Hilton and Kim O. Davis for Staff

Shawn McMurray for the AG

Mark Garrett for NWIEC

3. The Settling Parties state that the timing of this filing is consistent with the provisions of Order No. 2 in this Docket which required “Any settlement agreement along with supporting testimonies and exhibits shall be filed no later than ten (10) days before the scheduled evidentiary hearing, which in this case makes the filing due on or before May 13, 2011”.

4. The Settling Parties recommend that the current procedural schedule should remain in effect so that the Agreement can be considered at the evidentiary hearing which is set to begin at 9:30 a.m. on Wednesday, May 24, 2011, in Commission Hearing Room No. 1, 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 date and time scheduled for the area public hearing in Fort Smith, Arkansas at 6:00 p.m. on May 31, 2011, at the offices of the Arkansas Oil and Gas Commission located at 3309 Phoenix Avenue, should likewise remain the same.

5. The Settling Parties request that on or before Friday, May 20, 2011, an order be issued excusing all witnesses from appearing at the evidentiary hearing except those listed in Paragraph No. 2 above, who are supporting the Agreement.

WHEREFORE, the Settling Parties hereby request that the Commission enter an order on or before Friday, May 20, 2011 excusing all witnesses with the exceptions

found in Paragraph No. 2 of this Joint Motion, approve the Settlement Agreement attached hereto, and grant them all other necessary and proper relief.

Respectfully submitted,

GENERAL STAFF OF THE ARKANSAS

PUBLIC SERVICE COMMISSION

By: /s/Kevin M. Lemley

Staff Attorney

Cynthia Uhrynowycz

Staff Attorney

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.

Chisenhall, Nestrud & Julian

2840 Regions Center

400 W. Capitol Avenue

Little Rock, AR 72201

(501) 372-5800

ATTORNEY GENERAL OF ARKANSAS

By: /s/M. Shawn McMurray

Senior Asst. Attorney General

Emon Mahony

Asst. Attorney General

323 Center Street, Suite 200

Little Rock, AR 72201

(501) 682-1053

NORTHWEST ARKANSAS INDUSTRIAL

ENERGY CONSUMERS

By: /s/Thomas P. Schroedter

Hall, Estill, Hardwick, Gable,

Golden & Nelson, P.C.

320 S. Boston Avenue, Suite 400

Tulsa, OK 74103-3708

(918) 594-0436

CERTIFICATE OF SERVICE

I, Kevin M. Lemley, hereby certify that a copy of the foregoing has been served on all parties of record by electronic mail this _13th_ day of May, 2011.

/s/Kevin M. Lemley

JOINT EXHIBIT

BEFORE THE ARKANSAS PUBLIC SERVICE COMMISSION

IN THE MATTER OF THE APPLICATION	)
OF OKLAHOMA GAS AND ELECTRIC	)	DOCKET NO. 10-067-U
COMPANY FOR APPROVAL OF A GENERAL	)
CHANGE IN RATES AND TARIFFS	)

SETTLEMENT AGREEMENT

Come now the General Staff of the Arkansas Public Service Commission (Staff), Oklahoma Gas and Electric Company (OG&E), the Consumer Utilities Rate Advocacy Division of the Arkansas Attorney General's Office (AG), and Northwest Arkansas Industrial Energy Consumers (NWIEC), hereinafter collectively referred to as “the Settling Parties” and being all the parties to the above-referenced Docket, agree to the following terms in settlement of all outstanding issues in the above-referenced Docket.

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 September 28, 2010, and revised on September 29, 2010, and October 7, 2010. After conducting extensive discovery, Staff, the AG, and NWIEC filed Direct Testimony on March 15, 2011. OG&E filed Rebuttal Testimony on April 5, 2011, as corrected on April 14, 2011. Staff and the AG filed Surrebuttal Testimony on April 26, 2011.

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

JOINT EXHIBIT

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 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 non-fuel rate schedule revenue requirement, Arkansas jurisdiction, is $88,607,368 with a resulting revenue deficiency of $8,787,918, as shown in 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 April 26, 2011 Surrebuttal revenue requirement and related recommendations adjusted only as listed below:

1.	Decrease depreciation expense in the amount of $107,419 to correct an error in Staff’s calculation in its Surrebuttal case. The decrease in revenue requirement resulting from this change is $10,290;

2.	Increase working capital assets in the amount of $10,575,133 based on additional information provided by the Company. The increase in retail revenue requirement resulting from this change is $99,083; and

JOINT EXHIBIT

The return on equity is reduced from 10% to 9.95% and as a result the overall rate of return reduced from 5.95% to 5.93% as shown below. The decrease in revenue requirement resulting from this change is $141,142. All other capital components and cost rates are unchanged, including the weighted cost of debt of 2.45%.

Overall Rate of Return
				Weighted
Component	Amount	Proportion	Rate	Cost

Long-Term Debt	$2,006,378,121	37.94%	6.31%	2.39%
Short-Term Debt	160,510,250	3.03%	0.34%	0.01%
Common Equity	1,845,867,871	34.90%	9.95%	3.47%
Customer Deposits	63,198,986	1.19%	1.64%	0.02%
ADIT	1,000,655,618	18.92%	0.00%	0.00%
Post-1970 ADITC – Long-Term Debt	4,685,854	0.09%	6.31%	0.01%
Post-1970 ADITC – Short-Term Debt	374,868	0.01%	0.34%	0.00%
Post-1970 ADITC – Equity	4,310,985	0.08%	9.95%	0.01%
CAOL	190,466,043	3.60%	0.00%	0.00%
Other Capital Items	12,216,233	0.23%	7.76%	0.02%

Totals	$5,288,664,829	100.00%		5.93%

C. The Settling Parties agree the Commission should approve the depreciation rates sponsored by Staff witness Gayle Freier as set forth in Attachment No. 2 hereto, which reflect the depreciation rates proposed in Surrebuttal Exhibit GF-1 as derived from the parameters in Surrebuttal Exhibit GF-2.

D. The Settling Parties agree to the billing determinants set forth in Direct Exhibit RHS-1 of Staff witness Robert H. Swaim.

JOINT EXHIBIT

3. COST ALLOCATION AND RATE DESIGN:

A. The Settling Parties agree to use 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 SBG-1 of Staff witness Sandra B. Green. The results of the agreed upon COS Study are set forth in Attachment No.1 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 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 presented in his Direct Exhibit RHS-1.

C. Consistent with Staff Witness Sandra B. Green’s Surrebuttal Testimony (page 9, lines 1 – 10), to mitigate customer impact, the revenue surplus resulting from the Lighting class shall be distributed in a fair manner among the classes/service levels requiring a larger-than-system-average increase. The resulting non-fuel rate schedule revenue requirement for each customer class is as follows:

	Revenue
Rate Class	Requirement	Increase
Residential	$31,204,181	$2,420,238
General Service	$9,260,801	$529,179
Power & Light	$22,496,833	$2,507,125
Power & Light TOU	$22,492,255	$3,315,960
Lighting	$3,023,370	$0
Municipal Pumping	$67,497	$9,588
Athletic Field Lighting	$62,431	$5,827
Total Arkansas Retail	$88,607,368	$8,787,918

JOINT EXHIBIT

D. The Settling Parties agree that the Company will file compliance tariffs on or before Tuesday, June 7, 2011, which will reflect a rate design consistent with the terms of this Agreement. Staff will file Compliance Testimony addressing the tariffs by Wednesday, June 8, 2011. Staff will use its best efforts to work with the Company in advance of these dates to insure that the tariffs are consistent with the Agreement prior to these filing deadlines.

E. The Settling Parties agree that the customer charge for the Residential class will increase by the system average increase; the customer charge for the General Service class will not change.

F. The Settling Parties agree that OG&E’s rate design will comply with Staff’s recommendations regarding block design.

G. The Settling Parties agree that OG&E will offer both Demand-based and Energy-based Power and Light-Time of Use rates. Rate schedules SL-2, SL-3 and SL-4 will be re-combined into a single PL-TOU Energy rate schedule as is the case in the currently approved tariff. Rate schedule SL-1 PL-TOU Energy will include a “super peak” period rate during the hours of 4pm to 6pm.

H. The Settling Parties agree that OG&E will include Residential and General Service Time of Use rates, but will not offer a senior citizen discount.

I. The Settling Parties agree that OG&E will include Residential and General Service Variable Peak Pricing rates, but will not offer a senior citizen discount and customers will pay for incremental meter costs.

JOINT EXHIBIT

J. The Settling Parties agree that OG&E will not offer flat bill rates.

K. The Settling Parties agree to reject OG&E’s proposal for a Customer Education and Demand Rider.

L. The Settling Parties agree that OG&E will offer a Transmission Cost Recovery Rider as set forth in Staff witness Butler’s Surrebuttal Exhibit RLB-1.

M. The Settling Parties agree the Commission should approve Staff’s recommended Energy Cost Recovery Rider (Rider ECR) as set forth in Staff witness Butler’s Surrebuttal Exhibit RLB-2, which does not include uncollectible accounts expense or carbon taxes or other costs associated with future legislation.

N. The Settling Parties agree the Commission should approve OG&E’s proposed Load Reduction Rider (LR Rider) as recommended in Staff witness Butler’s Direct and Surrebuttal Testimonies. OG&E will allow Day-Ahead Pricing (DAP) customers to participate in the LR Rider provided that the terms of both tariffs are properly defined to prevent duplicate benefits for the reduction in load. Purchased power capacity costs related to the LR Rider may be temporarily recovered through Rider ECR until the next rate case. In the next rate case purchased power capacity costs related to the LR Rider will be incorporated in base rates.

O. The Settling Parties agree the Commission should approve a revision to DAP tariff, which implements a risk and recovery factor (RRF) of $.003 per kWh and imposes certain reporting requirements as recommended in the Surrebuttal Testimony of Staff witness Butler. Purchased power capacity payments will be recovered in base rates and the energy component will be recovered through Rider ECR.

JOINT EXHIBIT

4. OTHER ISSUES:

A. OG&E requests, and the Settling Parties do not object, that the new rates become effective for bills rendered as soon as possible after a Commission order approving the Agreement but not later than for bills rendered on July 1, 2011;

B. The Settling Parties agree the Commission should approve Staff’s recommendation to reject OG&E’s proposal for pension and OPEB trackers.

C. The Settling Parties agree the Commission should approve Staff’s recommendation to reject OG&E’s proposal for a storm rider or tracker.

D. OG&E may defer, for accounting purposes, the proposed expenses associated with the customer education program for an amount not to exceed $300,000 per year for a maximum of two years. This amount should include only incremental charges, i.e., excluding salaries, postage or other costs already considered in base rates, and should only be for the purposes of educating or informing customers and without the accrual of carrying charges. The deferred costs will be reviewed in OG&E’s next retail rate case to ensure the costs reasonably meet the above requirements for future recovery.

E. OG&E shall comply with the Allowance for Funds Used During Construction (AFUDC) recommendation reflected in the Surrebuttal Testimony of Staff witness Jo Ann Sterling at page 14, line 20 through page 15, line 2. The overall rate of return is 5.93%. Nothing herein alters OG&E’s obligation in future rate case applications, pursuant to Docket No. 08-103-U, to make whatever adjustment may be necessary to accurately state gross plant consistent with the terms of this provision.

JOINT EXHIBIT

F. On a prospective basis, OG&E shall keep depreciation expense and likewise accumulated depreciation on an individual FERC account level, by plant and unit, and report in the same manner in future rate applications.

G. On a prospective basis, OG&E shall utilize the functional/FERC account/plant/unit allocation that Staff performed in this case as the Arkansas adjustment to accumulated depreciation. Nothing herein alters OG&E’s obligation for future rate case applications, pursuant to Docket No. 08-103-U, to make an adjustment to accurately reflect net plant at Arkansas-approved depreciation rates.

H. In future rate cases OG&E shall fully explain any adjustment to per book amounts in its initial testimony or depreciation study, or include a workpaper that fully explains and supports the adjustment.

I. OG&E’s compliance tariffs will include an attachment to its Rider for Uniform Municipal Tax Adjustment, which lists the name of the municipality and the rate applied to customers’ bills.

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 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

JOINT EXHIBIT

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/Kevin M. Lemley

Staff Attorney

Cynthia Uhrynowycz

Staff Attorney

1000 Center Street

P.O. Box 400

Little Rock, AR 72203-0400

(501) 682-5878

JOINT EXHIBIT

OKLAHOMA GAS & ELECTRIC CO.

By: /s/Lawrence E. Chisenhall, Jr.

Chisenhall, Nestrud & Julian

2840 Regions Center

400 W. Capitol Avenue

Little Rock, AR 72201

(501) 372-5800

ATTORNEY GENERAL OF ARKANSAS

By: /s/M. Shawn McMurray

Senior Asst. Attorney General

Emon Mahony

Asst. Attorney General

323 Center Street, Suite 200

Little Rock, AR 72201

(501) 682-1053

NORTHWEST ARKANSAS INDUSTRIAL

ENERGY CONSUMERS

By: /s/Thomas P. Schroedter

Hall, Estill, Hardwick, Gable,

Golden & Nelson, P.C.

320 S. Boston Avenue, Suite 400

Tulsa, OK 74103-3708

(918) 594-0436

OKLAHOMA GAS AND ELECTRIC COMPANY									ATTACHMENT NO. 1
DOCKET NO. 10-067-U									PAGE 1 OF 1
COST OF SERVICES STUDY

		TOTAL		TOTAL
		COMPANY	OTHER	ARKANSAS		GENERAL	POWER &	POWER &		MUNICIPAL	ATH. FLD.
LINE		PRO FORMA	JURSIDICTIONS	JURISDICTION	RESIDENTIAL	SERVICE	LIGHT	LIGHT TOU	LIGHTING	PUMPING	LIGHTING
NO.	DESCRIPTION	(1)	(2)	(3)	(4)	(5)	(6)	(7)	(8)	(9)	(10)

	RATE BASE
1	Gross Plant in Service	$7,014,769,793	$6,352,108,372	$662,661,420	$226,390,964	$69,815,151	$171,024,549	$173,587,185	$20,882,546	$506,243	$454,783
2	Accumulated Depreciation	$2,993,001,922	$2,703,226,092	$289,775,829	$98,026,625	$29,829,558	$74,143,636	$79,229,888	$8,194,186	$193,037	$158,899
3	Total Net Plant	$4,021,767,871	$3,648,882,280	$372,885,591	$128,364,339	$39,985,593	$96,880,912	$94,357,297	$12,688,359	$313,207	$295,884
4	Plant Held for Future Use	$0	$0	$0	$0	$0	$0	$0	$0	$0	$0
5	Working Capital Assets & Misc. Other	$570,816,681	$514,837,610	$55,979,071	$18,505,774	$5,578,103	$14,523,495	$16,034,464	$1,273,356	$34,526	$29,354
6	TOTAL RATE BASE	$4,592,584,552	$4,163,719,890	$428,864,662	$146,870,113	$45,563,696	$111,404,407	$110,391,761	$13,961,716	$347,732	$325,237

	NON-FUEL OPERATING REVENUES
7	Present Rate Schedules/Class	$1,654,472,988	$1,574,653,537	$79,819,451	$28,783,943	$8,731,622	$19,989,708	$19,176,295	$3,023,370	$57,909	$56,604
8	Other Revenues	$37,516,492	$36,925,005	$591,487	$467,362	$76,304	$24,627	$19,851	$2,857	$424	$62
9	TOTAL OPERATING REVENUES	$1,691,989,480	$1,611,578,542	$80,410,938	$29,251,305	$8,807,926	$20,014,335	$19,196,146	$3,026,227	$58,333	$56,666

	OPERATING EXPENSES
10	Operations and Maintenance	$1,056,622,369	$1,023,173,404	$33,448,965	$12,327,590	$3,373,973	$8,270,529	$8,710,146	$721,891	$24,091	$20,744
11	Depreciation and Amortization	$190,598,517	$172,844,703	$17,753,814	$6,062,099	$1,854,341	$4,596,586	$4,651,157	$563,543	$13,634	$12,454
12	TOTAL OPERATING EXPENSES	$1,247,220,886	$1,196,018,107	$51,202,779	$18,389,689	$5,228,314	$12,867,115	$13,361,303	$1,285,435	$37,725	$33,198

13	TAXES OTHER THAN INCOME	$71,609,219	$64,798,676	$6,810,543	$2,338,787	$710,208	$1,751,712	$1,797,421	$202,643	$5,163	$4,609

14	FEDERAL & STATE INCOME TAXES	$84,162,112	$81,870,760	$2,291,352	$1,270,964	$488,827	$397,694	-$306,734	$436,190	$1,297	$3,114

15	TOTAL EXPENSES	$1,402,992,217	$1,342,687,543	$60,304,674	$21,999,441	$6,427,348	$15,016,521	$14,851,990	$1,924,267	$44,185	$40,921

16	OPERATING INCOME	$288,997,263	$268,890,999	$20,106,264	$7,251,865	$2,380,577	$4,997,814	$4,344,156	$1,101,959	$14,148	$15,745

17	PRESENT RATE OF RETURN	6.2927%	6.4580%	4.6883%	4.9376%	5.2247%	4.4862%	3.9352%	7.8927%	4.0687%	4.8412%


	REVENUE REQUIREMENT DETERMINATION
18	REQUIRED RATE OF RETURN			5.93%	5.93%	5.93%	5.93%	5.93%	5.93%	5.93%	5.93%
19	REQUIRED OPERATING INCOME (L6*L18)			$25,431,674	$8,709,398	$2,701,927	$6,606,281	$6,546,231	$827,930	$20,621	$19,287
20	OPERATING INCOME DEFICIENCY / (SURPLUS) (L19-L16)			$5,325,410	$1,457,533	$321,350	$1,608,467	$2,202,076	-$274,030	$6,472	$3,541
21	REVENUE CONVERSION FACTOR			1.650186	1.660503	1.646738	1.646210	1.646210	1.645559	1.645559	1.645559
22	REVENUE DEFICIENCY / (SURPLUS) (L20*L21)			$8,787,918	$2,420,238	$529,179	$2,647,875	$3,625,079	($450,932)	$10,651	$5,827
23	% INCREASE (L22/L7)			11.01%	8.41%	6.06%	13.25%	18.90%	-14.91%	18.39%	10.29%
24	COS RATE SCHED. / CLASS REV. REQ. (L9 + L22)			$89,198,855	$31,671,544	$9,337,105	$22,662,210	$22,821,225	$2,575,295	$68,984	$62,493

	REVENUE REQUIREMENT DETERMINATION WITH RIDERS
25	REVENUE DEFICIENCY / (SURPLUS) (L22)			$8,787,918	$2,420,238	$529,179	$2,647,875	$3,625,079	($450,932)	$10,651	$5,827
26	NON-FUEL RATE SCHEDULE REVENUE REQUIREMENT (L7+L25)			$88,607,368	$31,204,181	$9,260,801	$22,637,583	$22,801,374	$2,572,438	$68,560	$62,431
27	TOTAL OTHER REVENUES (L8)			$591,487	$467,362	$76,304	$24,627	$19,851	$2,857	$424	$62
28	TRANSMISSION RIDER (Allocated on 12CP)			$1,006,540	$325,440	$95,880	$260,755	$319,128	$4,582	$577	$178
29	FUEL REVENUES (CURRENT ECR RATE)			$84,973,039	$22,917,814	$6,849,832	$23,486,093	$30,717,177	$916,149	$48,128	$37,846
30	TOTAL REVENUE REQUIREMENT (L26+L27+L28+L29)			$175,178,434	$54,914,798	$16,282,816	$46,409,058	$53,857,530	$3,496,026	$117,688	$100,518
31	% INCREASE IN NON-FUEL RATE SCHEDULE REVENUES (L25 / L7)			11.01%	8.41%	6.06%	13.25%	18.90%	-14.91%	18.39%	10.29%
32	% INCREASE IN RATE SCHEDULE REVENUES INCLUDING FUEL ((L25) / (L7+L29))			5.33%	4.68%	3.40%	6.09%	7.27%	-11.45%	10.04%	6.17%
33	% INCREASE TO TOTAL BILL ((L25) / (L30 - L25))			5.28%	4.61%	3.36%	6.05%	7.22%	-11.42%	9.95%	6.15%

34	Mitigation Adjustment			($0)	$0	$0	($140,750)	($309,119)	$450,932	($1,062)	$0

	MITIGATED REVENUE REQUIREMENT DETERMINATION WITH RIDERS
35	MITIGATED REVENUE DEFICIENCY			$8,787,918	$2,420,238	$529,179	$2,507,125	$3,315,960	$0	$9,588	$5,827
36	NON-FUEL RATE SCHEDULE REVENUE REQUIREMENT			$88,607,368	$31,204,181	$9,260,801	$22,496,833	$22,492,255	$3,023,370	$67,497	$62,431
37	TOTAL OTHER REVENUES			$591,487	$467,362	$76,304	$24,627	$19,851	$2,857	$424	$62
38	TRANSMISSION RIDER (Allocated on 12CP)			$1,006,540	$325,440	$95,880	$260,755	$319,128	$4,582	$577	$178
39	FUEL REVENUES (CURRENT ECR RATE)			$84,973,039	$22,917,814	$6,849,832	$23,486,093	$30,717,177	$916,149	$48,128	$37,846
40	TOTAL REVENUE REQUIREMENT			$175,178,434	$54,914,798	$16,282,816	$46,268,307	$53,548,411	$3,946,958	$116,626	$100,518
41	% INCREASE IN NON-FUEL RATE SCHEDULE REVENUES			11.01%	8.41%	6.06%	12.54%	17.29%	0.00%	16.56%	10.29%
42	% INCREASE IN RATE SCHEDULE REVENUES INCLUDING FUEL			5.33%	4.68%	3.40%	5.77%	6.65%	0.00%	9.04%	6.17%
43	% INCREASE TO TOTAL BILL			5.28%	4.61%	3.36%	5.73%	6.60%	0.00%	8.96%	6.15%

				ATTACHMENT NO. 2
				Page 1 of 18

STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

	INTANGIBLE PLANT

302	Franchise and Consents	3.65%
303.2	Miscellaneous Intangible Plant-Software	10.51%

	PRODUCTION PLANT

	STEAM PRODUCTION - GAS

310.200	Land Rights
	Horseshoe Lake 6	0.06%
	Mustang 1	0.77%	*
	Seminole 1	1.48%

311	Structures and Improvements
	Horseshoe Lake 6	2.29%
	Horseshoe Lake 7	1.74%
	Horseshoe Lake 8	1.24%
	Mustang 1	2.92%
	Mustang 2	0.76%
	Mustang 3	0.94%
	Mustang 4	1.49%
	Seminole 1	2.82%
	Seminole 2	2.84%
	Seminole 3	2.09%

311.500	Security
	Horseshoe Lake 6	10.00%
	Mustang 1	10.00%
	Seminole 1	10.00%

312	Boiler Plant Equipment
	Horseshoe Lake 6	1.89%
	Horseshoe Lake 7	1.45%
	Horseshoe Lake 8	0.99%
	Mustang 1	2.28%
	Mustang 2	1.45%
	Mustang 3	0.27%
	Mustang 4	0.96%
	Seminole 1	2.73%
	Seminole 2	2.50%
	Seminole 3	1.78%

312.011	CEM - Continuous Emission Monitoring
	Horseshoe Lake 6	10.00%	*
	Horseshoe Lake 7	10.00%	*
	Horseshoe Lake 8	10.00%	*

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

				ATTACHMENT NO. 2
				Page 2 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

	Mustang 1	10.00%
	Mustang 3	10.00%	*
	Mustang 4	10.00%	*
	Seminole 1	10.00%	*
	Seminole 2	10.00%	*
	Seminole 3	10.00%	*

314	Turbogenerator Units
	Horseshoe Lake 6	0.76%
	Horseshoe Lake 7	0.76%
	Horseshoe Lake 8	0.53%
	Mustang 1	0.70%
	Mustang 2	1.07%	*
	Mustang 3	1.07%	*
	Mustang 4	0.20%
	Seminole 1	2.16%
	Seminole 2	2.11%
	Seminole 3	1.35%
	Seminole GT	1.07%	*

315	Accessory Electric Equipment
	Horseshoe Lake 6	0.71%
	Horseshoe Lake 7	0.33%
	Horseshoe Lake 8	0.20%
	Mustang 1	0.32%
	Mustang 2	0.94%	*
	Mustang 3	0.94%	*
	Mustang 4	0.94%	*
	Seminole 1	1.69%
	Seminole 2	2.20%
	Seminole 3	1.10%

316	Miscellaneous Power Plant Equipment
	Horseshoe Lake 6	5.62%
	Horseshoe Lake 7	1.21%
	Horseshoe Lake 8	1.30%
	Mustang 1	21.31%
	Mustang 2	5.87%	*
	Mustang 3	5.87%	*
	Mustang 4	2.26%
	Seminole 1	3.45%
	Seminole 2	6.81%
	Seminole 3	5.00%

317	ARO
	Muskogee 3	1.67%
	Horseshoe Lake 8	1.39%
	Mustang 4	1.59%
	Seminole 3	1.35%

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

				ATTACHMENT NO. 2
				Page 3 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

	STEAM PRODUCTION - COAL

310.200	Land Rights
	Muskogee 4	1.03%
	Sooner 1	3.49%

311	Structures and Improvements
	Muskogee 4	2.01%
	Muskogee 5	1.87%
	Muskogee 6	1.73%
	Sooner 1	1.77%
	Sooner 2	1.92%

311.500	Security
	Muskogee 4	10.00%
	Sooner 1	10.00%

312	Boiler Plant Equipment
	Muskogee 4	1.74%
	Muskogee 5	1.68%
	Muskogee 6	1.60%
	Sooner 1	1.56%
	Sooner 2	1.78%

312.011	CEM - Continuous Emission Monitoring
	Muskogee 4	10.00%
	Muskogee 5	10.00%	*
	Muskogee 6	10.00%	*
	Sooner 1	10.00%
	Sooner 2	10.00%	*

314	Turbogenerator Units
	Muskogee 4	1.46%
	Muskogee 5	1.36%
	Muskogee 6	1.39%
	Sooner 1	1.25%
	Sooner 2	1.53%

315	Accessory Electric Equipment
	Muskogee 4	1.08%
	Muskogee 5	1.02%
	Muskogee 6	1.03%
	Sooner 1	0.91%
	Sooner 2	1.14%

316	Miscellaneous Power Plant Equipment
	Muskogee 4	2.14%
	Muskogee 5	3.04%
	Muskogee 6	1.49%
	Sooner 1	3.73%
	Sooner 2	1.91%
	Power Supply Svcs	8.28%

317	ARO
	Muskogee 6	1.37%
	Sooner 2	1.35%

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

			ATTACHMENT NO. 2
			Page 4 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

	OTHER PRODUCTION

341	Structures and Improvements
	Tinker	3.16%
	Enid	4.66%
	Woodward	4.35%
	Horseshoe Lake 9 & 10	3.24%
	McClain Gas 1	4.16%
	McClain Gas 2	4.43%
	McClain Steam 1	4.45%
	McClain HRSG 1	4.16%
	McClain HRSG 2	4.43%
	Centennial Wind Farm	3.95%
	Redbud 1	3.08%
	OU Spirit Wind Farm	4.06%

342	Fuel Holders, Producers and Accessories
	Tinker	3.18%
	Enid	4.53%
	Woodward	4.10%
	Horseshoe Lake 9 & 10	3.24%
	McClain Gas 1	4.46%
	McClain Gas 2	4.69%
	McClain Steam 1	4.67%
	McClain HRSG 1	4.46%
	McClain HRSG 2	4.69%
	Redbud 1	3.04%
	Redbud 2	3.04%
	Redbud 3	3.05%
	Redbud 4	3.04%

343	Prime Movers
	Tinker	3.18%
	Enid	4.40%
	Horseshoe Lake 9 & 10	3.23%
	McClain Gas 1	4.30%
	McClain Gas 2	4.13%
	McClain Steam 1	4.18%
	McClain HRSG 1	4.30%
	McClain HRSG 2	4.13%
	Redbud 1	3.04%
	Redbud 2	3.03%
	Redbud 3	3.37%
	Redbud 4	3.07%

343.2	LTSA 2-year
	McClain Gas 1	50.00%
	McClain Gas 2	50.00%

343.3	LTSA 3-year
	McClain Gas 1	33.34%
	McClain Gas 2	33.34%

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

				ATTACHMENT NO. 2
				Page 5 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

343.4	LTSA 4-year
	McClain Gas 1	25.00%

343.5	LTSA 5-year
	McClain Gas 1	20.00%
	McClain Gas 2	20.00%
	Redbud 1	20.00%
	Redbud 2	20.00%
	Redbud 3	20.00%

343.6	LTSA 6-year
	McClain Gas 1	16.67%	*
	McClain Gas 2	16.67%
	Redbud 3	16.67%	*
	Redbud 4	16.67%	*

343.7	LTSA 7-year
	McClain Gas 1	14.29%
	McClain Gas 2	14.29%

343.20	LTSA 20-year
	Redbud 2	5.00%
	Redbud 3	5.00%

343.24	LTSA 24-year
	McClain Steam 1	4.17%
	Redbud 1	4.17%
	Redbud 2	4.17%
	Redbud 3	4.17%
	Redbud 4	4.17%

343.30	LTSA 30-year
	McClain Gas 1	3.33%
	McClain Gas 2	3.33%

343.99	CEM - Continuous Emission Monitoring
	McClain Gas 1	10.00%
	McClain Gas 2	10.00%
	McClain HRSG 1	10.00%
	McClain HRSG 2	10.00%
	Redbud 1	10.00%
	Redbud 2	10.00%
	Redbud 3	10.00%
	Redbud 4	10.00%

344	Generators
	Tinker	3.16%
	Enid	4.31%
	Woodward	3.95%
	Horseshoe Lake 9 & 10	3.36%
	McClain Gas 1	3.78%	*
	Centennial Wind Farm	3.96%
	OU Spirit Wind Farm	3.95%

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

				ATTACHMENT NO. 2
				Page 6 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

345	Accessory Electric Equipment
	Tinker	3.19%
	Enid	4.40%
	Woodward	3.98%
	Horseshoe Lake 9 & 10	3.45%
	McClain Gas 1	4.32%
	McClain Gas 2	4.38%
	McClain Steam 1	4.37%
	McClain HRSG 1	4.32%
	McClain HRSG 2	4.38%
	Redbud 1	3.02%
	Redbud 2	3.03%
	Redbud 3	3.01%
	Redbud 4	3.03%

346	Miscellaneous Power Plant Equipment
	Tinker	13.05%
	Enid	4.42%
	Woodward	3.98%
	Horseshoe Lake 9 & 10	3.22%
	McClain Gas 1	4.48%
	McClain Gas 2	4.62%
	McClain Steam 1	4.62%
	McClain HRSG 1	4.48%
	McClain HRSG 2	4.62%
	Centennial Wind Farm	4.11%
	Redbud 1	1.93%

347	ARO
	Enid	1.82%
	Woodward	1.82%
	Centennial Wind Farm	1.01%
	OU Spirit Wind Farm	2.86%

	TRANSMISSION PLANT

350.2	Land Rights	3.00%
350.3	Land Rights-Power Supply	3.59%
352	Structures and Improvements-Transmission	1.70%
352.100	Structures and Improvements-Power Supply	1.57%
353	Station Equipment	2.41%
353.130	Security	10.00%
353.905	Step Up Transformers (Power Supply)
	Horseshoe Lake 6	0.15%
	Horseshoe Lake 7	0.15%
	Horseshoe Lake 8	0.15%
	Muskogee 4	2.84%
	Muskogee 5	1.56%
	Muskogee 6	1.91%
	Mustang 1	3.12%
	Mustang 2	3.12%
	Mustang 4	1.95%	*
	Mustang 3	1.97%
	Seminole 1	0.20%
	Seminole 2	0.74%
	Seminole 3	0.99%

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

			ATTACHMENT NO. 2
			Page 7 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

	Sooner 1	1.37%
	Sooner 2	4.39%
	Centennial Wind Farm	3.44%
	McClain GSU	2.93%
	Redbud Power Plant	2.30%
	OU Spirit Wind Farm	3.80%
354	Towers and Fixtures	1.86%
355	Poles and Fixtures	2.83%
355.1	Poles and Fixtures-Power Supply	2.72%
356	Overhead Conductors and Devices	2.13%
356.1	Overhead Conductors and Devices-Power Supply	1.86%
358	Underground Conductors and Devices	0.83%
359	ARO	1.01%

	DISTRIBUTION PLANT

360.2	Land Rights	1.66%
361	Structures and Improvements	1.92%
362	Station Equipment	2.30%
362.100	Security	10.00%
362.900	Step Up Transformers for Power Supply-Tinker	7.47%
362.900	Step Up Transformers for Power Supply-Woodward	7.41%
364	Poles, Towers, and Fixtures	2.36%
365	Overhead Conductors and Devices	2.71%
366	Underground Conduit	2.24%
367	Underground Conductors and Devices	2.45%
368	Line Transformers	4.04%
369	Services	1.73%
370.2	Meters-Standard	2.58%
370.3	Meters-Equipment	2.58%
371	Installation on Customer Premises	2.89%
373	Street Lighting and Signal Systems	2.55%

	GENERAL PLANT

	POWER DELIVERY
389.200	Land Rights	0.72%
390	Structures and Improvements	1.82%
391	Office Furniture and Equipment-Accrued	14.59%
391	Office Furniture and Equipment-Amortized	6.67%
391.1	Computer Equipment-Accrued	34.96%
391.1	Computer Equipment-Amortized	20.00%
391.3	Fax and Copier Equipment-Amortized	20.00%
393	Stores Equipment-Accrued	0.16%
393	Stores Equipment-Amortized	4.00%
394	Tools, Shop and Garage Equipment-Accrued	1.90%
394	Tools, Shop and Garage Equipment-Amortized	4.00%
395	Laboratory Equipment-Accrued	5.10%
395	Laboratory Equipment-Amortized	5.00%
396	Power Operated Equipment	3.41%
397	Communication Equipment-Accrued	0.00%
397	Communication Equipment-Amortized	10.00%
398	Miscellaneous Equipment-Accrued	0.00%
398	Miscellaneous Equipment-Amortized	5.00%

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

				ATTACHMENT NO. 2
				Page 8 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

	FLEET EQUIPMENT - POWER SUPPLY
392.1	Standard Cars	6.39%
392.3	Pickup Trucks	2.02%
392.4	Light Trucks	0.64%
392.5	Heavy Trucks	7.98%	*
392.6	Trailers	0.23%

	FLEET EQUIPMENT - POWER DELIVERY
392.1	Standard Cars	0.16%
392.3	Pickup Trucks	4.10%
392.4	Light Trucks	4.36%	*
392.5	Heavy Trucks	6.86%
392.6	Trailers	2.88%	*

	FLEET EQUIPMENT - TRANSMISSION
392.1	Standard Cars	3.09%
392.3	Pickup Trucks	5.43%	*

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

				ATTACHMENT NO. 2
				Page 9 of 18
STAFF RECOMMENDED DEPRECIATION RATES

Account	Description	Depreciation Rate

	OG&E HOLDING COMPANY

	INTANGIBLE PLANT

303.200	Software - Depreciable	14.10%

	GENERAL PLANT

	OFFICE FURNITURE AND EQUIPMENT
391.10	Computers and Printers	20.00%
391.12	Security	33.33%
391.40	Fax Machines	20.00%
391.50	Copiers	33.34%	*
391.60	Tables, Cubes, and Stands	6.67%
391.90	Miscellaneous	6.67%

	TRANSPORTATION EQUIPMENT
392.01	Standard Cars	10.44%
392.03	Pickup Trucks	10.16%
392.04	Light Trucks	8.07%
392.05	Heavy Trucks	9.10%
392.06	Trailers	5.52%

393	Stores Equipment	4.00%
395	Laboratory Equipment	5.00%
396	Power Operated Equipment	5.00%

	COMMUNICATION EQUIPMENT
397.02	Radio Systems	10.00%
397.40	Wireless Networks	10.00%
397.01	Telephone Equipment	10.00%
397.50	Comm. Miscellaneous	10.00%

398	Miscellaneous Equipment	5.00%

*Fully-reserved or over-accrued for the purposed of Docket No. 10-067-U.

					ATTACHMENT NO. 2
					Page 10 of 18


STAFF RECOMMENDED DEPRECIATION PARAMETERS

Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

INTANGIBLE PLANT
302	Franchise and Consents	SQ	25	-	13.7	0%	50%
303.2	Miscellaneous Intangible Plant-Software	SQ	3	-	1.6	0%	83%

PRODUCTION PLANT

STEAM PRODUCTION - GAS

310.200	Land Rights
	Horseshoe Lake 6	S4	100	2018	8.5	0%	100%
	Mustang 1	S4	100	2016	6.5	0%	101%
	Seminole 1	S4	100	2025	15.5	0%	77%

311	Structures and Improvements
	Horseshoe Lake 6	R3	102	2018	8.4	-20%	101%
	Horseshoe Lake 7	R3	102	2024	14.2	-20%	95%
	Horseshoe Lake 8	R3	102	2029	19.1	-20%	96%
	Mustang 1	R3	102	2016	6.5	-20%	101%
	Mustang 2	R3	102	2016	6.5	-20%	115%
	Mustang 3	R3	102	2017	7.4	-20%	113%
	Mustang 4	R3	102	2020	10.4	-20%	105%
	Seminole 1	R3	102	2025	15.3	-20%	77%
	Seminole 2	R3	102	2026	16.2	-20%	74%
	Seminole 3	R3	102	2030	20.1	-20%	78%

311.500	Security
	Horseshoe Lake 6	SQ	10	-	-	-	-
	Mustang 1	SQ	10	-	-	-	-
	Seminole 1	SQ	10	-	-	-	-

312	Boiler Plant Equipment
	Horseshoe Lake 6	R1.5	105	2018	8.4	-15%	99%
	Horseshoe Lake 7	R1.5	105	2024	14.2	-15%	94%
	Horseshoe Lake 8	R1.5	105	2029	18.9	-15%	96%
	Mustang 1	R1.5	105	2016	6.4	-15%	100%
	Mustang 2	R1.5	105	2016	6.5	-15%	106%
	Mustang 3	R1.5	105	2017	7.4	-15%	113%
	Mustang 4	R1.5	105	2020	10.3	-15%	105%
	Seminole 1	R1.5	105	2025	15.2	-15%	74%
	Seminole 2	R1.5	105	2026	16.0	-15%	75%
	Seminole 3	R1.5	105	2030	19.8	-15%	80%

312.011	CEM-Continuous Emission Monitoring
	Horseshoe Lake 6	SQ	10	-	-	-	-
	Horseshoe Lake 7	SQ	10	-	-	-	-
	Horseshoe Lake 8	SQ	10	-	-	-	-

						ATTACHMENT NO. 2
						Page 11 of 18

STAFF RECOMMENDED DEPRECIATION PARAMETERS

Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

	Mustang 1	SQ	10	-	-	-	-
	Mustang 3	SQ	10	-	-	-	-
	Mustang 4	SQ	10	-	-	-	-
	Seminole 1	SQ	10	-	-	-	-
	Seminole 2	SQ	10	-	-	-	-
	Seminole 3	SQ	10	-	-	-	-

314	Turbogenerator Units
	Horseshoe Lake 6	R1	54	2018	7.9	-5%	99%
	Horseshoe Lake 7	R1	54	2024	12.9	-5%	95%
	Horseshoe Lake 8	R1	54	2029	17.2	-5%	96%
	Mustang 1	R1	54	2016	6.5	-5%	100%
	Mustang 2	R1	54	2016	6.2	-5%	115%
	Mustang 3	R1	54	2017	7.0	-5%	113%
	Mustang 4	R1	54	2020	9.7	-5%	103%
	Seminole 1	R1	54	2025	14.1	-5%	75%
	Seminole 2	R1	54	2026	14.9	-5%	74%
	Seminole 3	R1	54	2030	18.3	-5%	80%
	Seminole GT	R1	54	2007	0.5	-5%	114%

315	Accessory Electric Equipment
	Horseshoe Lake 6	S1	124	2018	8.5	0%	94%
	Horseshoe Lake 7	S1	124	2024	14.3	0%	95%
	Horseshoe Lake 8	S1	124	2029	19.2	0%	96%
	Mustang 1	S1	124	2016	6.5	0%	98%
	Mustang 2	S1	124	2016	6.5	0%	115%
	Mustang 3	S1	124	2017	7.4	0%	113%
	Mustang 4	S1	124	2020	10.4	0%	104%
	Seminole 1	S1	124	2025	15.3	0%	74%
	Seminole 2	S1	124	2026	16.2	0%	64%
	Seminole 3	S1	124	2030	20.1	0%	78%

316	Miscellaneous Power Plant Equipment
	Horseshoe Lake 6	R1.5	60	2018	8.3	-10%	63%
	Horseshoe Lake 7	R1.5	60	2024	13.7	-10%	93%
	Horseshoe Lake 8	R1.5	60	2029	18.1	-10%	86%
	Mustang 1	R1.5	60	2016	6.4	-10%	-26%
	Mustang 2	R1.5	60	2016	6.1	-10%	0%
	Mustang 3	R1.5	60	2017	6.9	-10%	112%
	Mustang 4	R1.5	60	2020	10.0	-10%	87%
	Seminole 1	R1.5	60	2025	14.6	-10%	60%
	Seminole 2	R1.5	60	2026	14.8	-10%	9%
	Seminole 3	R1.5	60	2030	19.1	-10%	14%

317	ARO
	Muskogee 3	-	-	-	-	-	-
	Horseshoe Lake 8	-	-	-	-	-	-
	Mustang 4	-	-	-	-	-	-
	Seminole 3	-	-	-	-	-	-

						ATTACHMENT NO. 2
						Page 12 of 18

STAFF RECOMMENDED DEPRECIATION PARAMETERS


Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

STEAM PRODUCTION - COAL

310.200	Land Rights
	Muskogee 4	S4	100	2034	24.5	0%	75%
	Sooner 1	S4	100	2034	24.5	0%	15%

311	Structures and Improvements
	Muskogee 4	R3	102	2034	24.0	-20%	72%
	Muskogee 5	R3	102	2033	23.0	-20%	77%
	Muskogee 6	R3	102	2039	28.9	-20%	70%
	Sooner 1	R3	102	2034	24.1	-20%	77%
	Sooner 2	R3	102	2035	25.0	-20%	72%

311.500	Security
	Muskogee 4	SQ	10	-	-	-	-
	Sooner 1	SQ	10	-	-	-	-

312	Boiler Plant Equipment
	Muskogee 4	R1.5	105	2034	23.6	-15%	74%
	Muskogee 5	R1.5	105	2033	22.7	-15%	77%
	Muskogee 6	R1.5	105	2039	28.2	-15%	70%
	Sooner 1	R1.5	105	2034	23.6	-15%	78%
	Sooner 2	R1.5	105	2035	24.5	-15%	71%

312.011	CEM-Continuous Emission Monitoring
	Muskogee 4	SQ	10	-	-	-	-
	Muskogee 5	SQ	10	-	-	-	-
	Muskogee 6	SQ	10	-	-	-	-
	Sooner 1	SQ	10	-	-	-	-
	Sooner 2	SQ	10	-	-	-	-

314	Turbogenerator Units
	Muskogee 4	R1	54	2034	22.2	-5%	73%
	Muskogee 5	R1	54	2033	21.0	-5%	76%
	Muskogee 6	R1	54	2039	25.2	-5%	70%
	Sooner 1	R1	54	2034	21.7	-5%	78%
	Sooner 2	R1	54	2035	22.5	-5%	71%

315	Accessory Electric Equipment
	Muskogee 4	S1	124	2034	23.8	0%	74%
	Muskogee 5	S1	124	2033	22.9	0%	77%
	Muskogee 6	S1	124	2039	28.7	0%	70%
	Sooner 1	S1	124	2034	23.8	0%	78%
	Sooner 2	S1	124	2035	24.8	0%	72%

316	Miscellaneous Power Plant Equipment
	Muskogee 4	R1.5	60	2034	22.6	-10%	62%
	Muskogee 5	R1.5	60	2033	21.6	-10%	44%
	Muskogee 6	R1.5	60	2039	25.8	-10%	72%
	Sooner 1	R1.5	60	2034	22.4	-10%	26%
	Sooner 2	R1.5	60	2035	22.4	-10%	67%
	Power Supply Svcs	R1.5	60	2020	10.3	-10%	25%

317	ARO
	Muskogee 6	-	-	-	-	-	-
	Sooner 2	-	-	-	-	-	-

						ATTACHMENT NO. 2
						Page 13 of 18

STAFF RECOMMENDED DEPRECIATION PARAMETERS


Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

OTHER PRODUCTION

341	Structures and Improvements
	Tinker	S3	50	2018	8.5	0%	73%
	Enid	S3	50	2013	3.3	0%	85%
	Woodward	S3	50	2013	3.2	0%	86%
	Horseshoe Lake 9 & 10	S3	50	2035	24.9	0%	19%
	McClain Gas 1	S3	50	2031	21.4	0%	11%
	McClain Gas 2	S3	50	2031	21.3	0%	6%
	McClain Steam 1	S3	50	2031	21.3	0%	5%
	McClain HRSG 1	S3	50	2031	21.4	0%	11%
	McClain HRSG 2	S3	50	2031	21.3	0%	6%
	Centennial Wind Farm	S3	50	2031	21.4	0%	15%
	Redbud 1	S3	50	2035	25.2	0%	22%
	OU Spirit Wind Farm	S3	50	2034	24.4	0%	1%

342	Fuel Holders, Producers and Accessories
	Tinker	R4	55	2018	8.5	0%	73%
	Enid	R4	55	2013	3.4	0%	85%
	Woodward	R4	55	2013	3.4	0%	86%
	Horseshoe Lake 9 & 10	R4	55	2035	25.4	0%	18%
	McClain Gas 1	R4	55	2031	21.4	0%	5%
	McClain Gas 2	R4	55	2031	21.4	0%	0%
	McClain HRSG 1	R4	55	2031	21.4	0%	5%
	McClain HRSG 2	R4	55	2031	21.4	0%	0%
	Redbud 1	R4	55	2035	25.3	0%	23%
	Redbud 2	R4	55	2035	25.3	0%	23%
	Redbud 3	R4	55	2035	25.3	0%	23%
	Redbud 4	R4	55	2035	25.3	0%	23%

343	Prime Movers
	Tinker	R4	112	2018	8.5	0%	73%
	Enid	R4	112	2013	3.5	0%	85%
	Horseshoe Lake 9 & 10	R4	112	2035	25.5	0%	18%
	McClain Gas 1	R4	112	2031	21.5	0%	8%
	McClain Gas 2	R4	112	2031	21.5	0%	11%
	McClain Steam 1	R4	112	2031	21.5	0%	10%
	McClain HRSG 1	R4	112	2031	21.5	0%	8%
	McClain HRSG 2	R4	112	2031	21.5	0%	11%
	Redbud 1	R4	112	2035	25.5	0%	23%
	Redbud 2	R4	112	2035	25.5	0%	23%
	Redbud 3	R4	112	2035	25.5	0%	14%
	Redbud 4	R4	112	2035	25.5	0%	22%

343.2	LTSA - 2 year
	McClain Gas 1	SQ	2	-	-	-	-
	McClain Gas 2	SQ	2	-	-	-	-

343.3	LTSA - 3 year
	McClain Gas 1	SQ	3	-	-	-	-
	McClain Gas 2	SQ	3	-	-	-	-

						ATTACHMENT NO. 2
						Page 14 of 18

STAFF RECOMMENDED DEPRECIATION PARAMETERS


Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

343.4	LTSA - 4 year	SQ	4	-	-	-	-
	McClain Gas 1

343.5	LTSA - 5 year
	McClain Gas 1	SQ	5	-	-	-	-
	McClain Gas 2	SQ	5	-	-	-	-
	Redbud 1	SQ	5	-	-	-	-
	Redbud 2	SQ	5	-	-	-	-
	Redbud 3	SQ	5	-	-	-	-

343.6	LTSA - 6 year
	McClain Gas 1	SQ	6	-	-	-	-
	McClain Gas 2	SQ	6	-	-	-	-
	Redbud 3	SQ	6	-	-	-	-
	Redbud 4	SQ	6	-	-	-	-

343.7	LTSA - 7 year
	McClain Gas 1	SQ	7	-	-	-	-
	McClain Gas 2	SQ	7	-	-	-	-

343.20	LTSA - 20 year
	Redbud 2	SQ	20	-	-	-	-
	Redbud 3	SQ	20	-	-	-	-

343.24	LTSA - 24 year
	McClain Steam 1	SQ	24	-	-	-	-
	Redbud 1	SQ	24	-	-	-	-
	Redbud 2	SQ	24	-	-	-	-
	Redbud 3	SQ	24	-	-	-	-
	Redbud 4	SQ	24	-	-	-	-

343.30	LTSA - 30 year
	McClain Gas 1	SQ	30	-	-	-	-
	McClain Gas 2	SQ	30	-	-	-	-

343.99	CEM-Continuous Emission Monitoring
	McClain Gas 1	SQ	10	-	-	-	-
	McClain Gas 2	SQ	10	-	-	-	-
	McClain HRSG 1	SQ	10	-	-	-	-
	McClain HRSG 2	SQ	10	-	-	-	-
	Redbud 1	SQ	10	-	-	-	-
	Redbud 2	SQ	10	-	-	-	-
	Redbud 3	SQ	10	-	-	-	-
	Redbud 4	SQ	10	-	-	-	-

344	Generators
	Tinker	S1.5	62	2018	8.5	0%	73%
	Enid	S1.5	62	2013	3.5	0%	85%
	Woodward	S1.5	62	2013	3.5	0%	86%
	Horseshoe Lake 9 & 10	S1.5	62	2035	24.5	0%	18%
	McClain Gas 1	S1.5	62	2031	24.5	0%	n/a
	Centennial Wind Farm	S1.5	62	2031	21.3	0%	16%
	OU Spirit Wind Farm	S1.5	62	2034	24.2	0%	4%

						ATTACHMENT NO. 2
						Page 15 of 18

STAFF RECOMMENDED DEPRECIATION PARAMETERS


Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

345	Accessory Electric Equipment
	Tinker	R4	106	2018	8.5	0%	73%
	Enid	R4	106	2013	3.5	0%	85%
	Woodward	R4	106	2013	3.5	0%	86%
	Horseshoe Lake 9 & 10	R4	106	2035	25.5	0%	12%
	McClain Gas 1	R4	106	2031	21.5	0%	7%
	McClain Gas 2	R4	106	2031	21.5	0%	6%
	McClain Steam 1	R4	106	2031	21.5	0%	6%
	McClain HRSG 1	R4	106	2031	21.5	0%	7%
	McClain HRSG 2	R4	106	2031	21.5	0%	6%
	Redbud 1	R4	106	2035	25.5	0%	23%
	Redbud 2	R4	106	2035	25.5	0%	23%
	Redbud 3	R4	106	2035	25.5	0%	23%
	Redbud 4	R4	106	2035	25.5	0%	23%

346	Miscellaneous Power Plant Equipment
	Tinker	R4	83	2018	8.5	0%	-1444%
	Enid	R4	83	2013	3.5	0%	85%
	Woodward	R4	83	2013	3.5	0%	86%
	Horseshoe Lake 9 & 10	R4	83	2035	25.4	0%	18%
	McClain Gas 1	R4	83	2031	21.5	0%	4%
	McClain Gas 2	R4	83	2031	21.5	0%	1%
	McClain Steam 1	R4	83	2031	21.5	0%	1%
	McClain HRSG 1	R4	83	2031	21.5	0%	4%
	McClain HRSG 2	R4	83	2031	21.5	0%	1%
	Centennial Wind Farm	R4	83	2031	21.5	0%	12%
	Redbud 1	R4	83	2035	25.5	0%	51%

347	ARO
	Enid	-	-	-	-	-	-
	Woodward	-	-	-	-	-	-
	Centennial Wind Farm	-	-	-	-	-	-
	OU Spirit Wind Farm	-	-	-	-	-	-

TRANSMISSION PLANT

350.2	Land Rights	R4	70	-	26.1	0%	22%
350.3	Land Rights-Power Supply	R4	70	-	26.1	0%	6%
352	Structures and Improvements-Transmission	R2.5	65	-	50.7	0%	14%
352.100	Structures and Improvements-Power Supply	R2.5	65	-	50.7	0%	20%
353	Station Equipment	L0.5	51	-	40.2	-22%	25%
353.130	Security	SQ	10	-	7.0	0%	35%
353.905	Step Up Transformers (Power Supply)
	Horseshoe Lake 6	R2.5	40	-	25.8	0%	96%
	Horseshoe Lake 7	R2.5	40	-	25.8	0%	96%
	Horseshoe Lake 8	R2.5	40	-	25.8	0%	96%
	Muskogee 4	R2.5	40	-	25.8	0%	27%
	Muskogee 5	R2.5	40	-	25.8	0%	60%
	Muskogee 6	R2.5	40	-	25.8	0%	51%
	Mustang 1	R2.5	40	-	25.8	0%	19%
	Mustang 2	R2.5	40	-	25.8	0%	19%
	Mustang 4	R2.5	40	-	25.8	0%	129%
	Mustang 3	R2.5	40	-	25.8	0%	49%
	Seminole 1	R2.5	40	-	25.8	0%	95%
	Seminole 2	R2.5	40	-	25.8	0%	81%
	Seminole 3	R2.5	40	-	25.8	0%	74%

						ATTACHMENT NO. 2
						Page 16 of 18

STAFF RECOMMENDED DEPRECIATION PARAMETERS

Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

	Sooner 1	R2.5	40	-	25.8	0%	65%
	Sooner 2	R2.5	40	-	25.8	0%	-13%
	Centennial Wind Farm	R2.5	40	-	25.8	0%	11%
	McClain GSU	R2.5	40	-	25.8	0%	25%
	Redbud Power Plant	R2.5	40	-	25.8	0%	41%
	OU Spirit Wind Farm	R2.5	40	-	25.8	0%	2%
354	Towers and Fixtures	L3	69	-	50.8	-15%	20%
355	Poles and Fixtures	L1	52	-	42.3	-52%	32%
355.1	Poles and Fixtures-Power Supply	L1	52	-	42.3	-52%	37%
356	Overhead Conductors and Devices	R2.5	58	-	45.8	-30%	32%
356.1	Overhead Conductors and Devices-Power Supply	R2.5	58	-	45.8	-30%	45%
358	Underground Conductors and Devices	R2.5	40	-	8.3	0%	93%
359	ARO	-	-	-	-	-	-


DISTRIBUTION PLANT

360.2	Land Rights	S4	60		44.8	0%	26%
361	Structures and Improvements	R2	55		46.4	-10%	21%
362	Station Equipment	L0	51		42.7	-25%	27%
362.100	Security	SQ	10		7.0	0%	17%
362.900	Step Up Transformers for Power Supply-Tinker	R2.5	40		13.5	0%	-1%
362.900	Step Up Transformers for Power Supply-Woodward	R2.5	40		13.5	0%	0%
364	Poles, Towers, and Fixtures	L0.5	47		41.6	-40%	42%
365	Overhead Conductors and Devices	L1	49		37.2	-36%	35%
366	Underground Conduit	L2.5	53		46.0	-30%	27%
367	Underground Conductors and Devices	S1	47		42.3	-31%	27%
368	Line Transformers	R1	35		24.0	-20%	23%
369	Services	L1.5	51		44.0	-20%	44%
370.2	Meters-Standard	L1	30		24.3	-5%	42%
370.3	Meters-Equipment	L1	30		24.3	-5%	42%
371	Installation on Customer Premises	S2	30		28.5	0%	18%
373	Street Lighting and Signal Systems	S1.5	40		34.1	-30%	43%


GENERAL PLANT

	POWER DELIVERY
389.200	Land Rights	R4	45	-	20.4	0%	85%
390	Structures and Improvements	R3.5	34	-	18.4	0%	67%
391	Office Furniture and Equipment-Accrued	SQ	15	-	-	-	-
391	Office Furniture and Equipment-Amortized	SQ	15	-	-	-	-
391.1	Computer Equipment-Accrued	SQ	5	-	-	-	-
391.1	Computer Equipment-Amortized	SQ	5	-	-	-	-
391.3	Fax and Copier Equipment-Amortized	SQ	5	-	-	-	-
393	Stores Equipment-Accrued	SQ	25	-	-	-	-
393	Stores Equipment-Amortized	SQ	25	-	-	-	-
394	Tools, Shop and Garage Equipment-Accrued	SQ	25	-	-	-	-
394	Tools, Shop and Garage Equipment-Amortized	SQ	25	-	-	-	-
395	Laboratory Equipment-Accrued	SQ	20	-	-	-	-
395	Laboratory Equipment-Amortized	SQ	20	-	-	-	-
396	Power Operated Equipment	L1	16	-	11.4	18%	43%
397	Communication Equipment-Accrued	SQ	10	-	-	-	-
397	Communication Equipment-Amortized	SQ	10	-	-	-	-
398	Miscellaneous Equipment-Accrued	SQ	20	-	-	-	-
398	Miscellaneous Equipment-Amortized	SQ	20	-	-	-	-

						ATTACHMENT NO. 2
						Page 17 of 18

STAFF RECOMMENDED DEPRECIATION PARAMETERS


Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

	FLEET EQUIPMENT - POWER SUPPLY
392.1	Standard Cars	R3	9.5	-	8.7	8%	36%
392.3	Pickup Trucks	S2.5	10	-	5.5	8%	81%
392.4	Light Trucks	L2.5	11	-	7.3	8%	87%
392.5	Heavy Trucks	L3	13	-	5.2	8%	115%
392.6	Trailers	S0.5	25	-	17.8	8%	88%

	FLEET EQUIPMENT - POWER DELIVERY
392.1	Standard Cars	R3	9.5	-	7.0	8%	91%
392.3	Pickup Trucks	S2.5	10	-	6.1	8%	67%
392.4	Light Trucks	L2.5	11	-	7.9	8%	106%
392.5	Heavy Trucks	L3	13	-	8.7	8%	32%
392.6	Trailers	S0.5	25	-	16.1	8%	100%

	FLEET EQUIPMENT - TRANSMISSION
392.1	Standard Cars	R3	9.5	-	7.0	8%	70%
392.3	Pickup Trucks	S2.5	10	-	6.1	8%	0%

						ATTACHMENT NO. 2
						Page 18 of 18


STAFF RECOMMENDED DEPRECIATION PARAMETERS

Account	Description	Curve Shape	Interim Survivor Curve/Average Service Life	Retirement Year	Remaining Life	Net Salvage Percent	Reserve Ratio at 12/31/10

OG&E HOLDING COMPANY

INTANGIBLE PLANT

303.200	Software - Depreciable	SQ	5	-	3.2	0%	55%

GENERAL PLANT

	OFFICE FURNITURE AND EQUIPMENT
391.10	Computers and Printers	SQ	5	-	-	-	-
391.12	Security	SQ	3	-	-	-	-
391.40	Fax Machines	SQ	5	-	-	-	-
391.50	Copiers	SQ	3	-	-	-	-
391.60	Tables, Cubes, and Stands	SQ	15	-	-	-	-
391.90	Miscellaneous	SQ	15	-	-	-	-

	TRANSPORTATION EQUIPMENT
392.01	Standard Cars	R0.5	7.5	-	6.7	0%	30%
392.03	Pickup Trucks	R2.5	10	-	6.1	0%	38%
392.04	Light Trucks	R3	11	-	7.0	0%	44%
392.05	Heavy Trucks	R4	10	-	8.1	0%	26%
392.06	Trailers	R2.5	16	-	13.4	0%	26%

393	Stores Equipment	SQ	25	-	-	-	-
395	Laboratory Equipment	SQ	20	-	-	-	-
396	Power Operated Equipment	R2	20	-	15.5	0%	35%

	COMMUNICATION EQUIPMENT
397.02	Radio Systems	SQ	10	-	-	-	-
397.40	Wireless Networks	SQ	10	-	-	-	-
397.01	Telephone Equipment	SQ	10	-	-	-	-
397.50	Comm. Miscellaneous	SQ	10	-	-	-	-

398	Miscellaneous Equipment	SQ	20	-	-	-	-

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