Tn the Matter of the Application of Southwest Power Pool, Inc

TN THE MATTER OF THE APPLICATION OF SOUTHWEST POWER POOL, INC. FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY FOR THE LIMITED DOCKET NO. 04-137-U PURPOSE OF MANAGING AND ORDERNO. 6 COORDINATING THE USE OF CERTAIN FACILITIES LOCATED WITHIN THE STATE OF ARKANSAS

IN THE MATTER OF THE APPLICATION OF ) OKLAHOMA GAS & ELECTRIC COMPANY ) FOR APPROVAL OF ITS PARTICIPATION IN ) DOCKET NO. 04- 1 11 -U THE SOUTHWEST POWER POOL REGIONAL ) ORDERNO. 1 TRANSMISSION ORGANIZATION 1

IN THE MATTER OF A PROTECTIVE ORDER ) FOR THE COST BENEFIT STUDY 1 REGARDING THE SOUTHWEST POWER ) DOCKET NO. 04-129-U POOL REGIONAL TRANSMISSION 1 ORDERNO. 2 ORGANIZATION

IN THE MATTER OF THE APPLICATION OF ) SOUTHWESTERN ELECTRIC POWER ) COMPANY’S RELATIONSHIP TO THE ) DOCKET NO. 04-143-U SOUTHWEST POWER POOL REGIONAL ORDERNO. 1 TRANSMISSION ORGANIZATION )

IN THE MATTER OF THE EMPIRE DISTRICT ) ELECTRIC COMPANY APPLICATION TO TRANSFER FUNCTIONAL CONTROL OF 1 DOCKET NO. 05-132-U CERTAIN TRANSMISSION ASSETS TO THE ) ORDERNO. 1 SOUTHWEST POWER POOL, INC. )

ORDER

In this Order, the Commission (a) grants the Application of Southwest Power Pool, Inc.

(“SPP”) for a Certificate of Public Convenience and Necessity (“CCN’) to transact the business Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 2 of 40 of a public utility in Arkansas by asserting functional control of certain transmission facilities in

Arkansas; (b) denies SPP’s request for waiver of the applicability of various provisions of state law; and (c) grants, subject to certain conditions, the Applications of Southwestern Electric

Power Company (“SWEPCO”), Oklahoma Gas & Electric (“OG&E”) and Empire District

Electric Company (“Empire”) to transfer functional control of their Arkansas transmission

facilities to SPP.

This Order is organized as follows: Section I is the procedural history of the dockets;

Section I1 reviews the background facts that are applicable to all the applications before the

Commission; Section I11 addresses SPP’s Application for a CCN; Section IV addresses SPP’s

request for the Commission to declare that certain Arkansas statutes are inapplicable; and

Section V addresses the various utility Applications for authority to transfer fwnctional control of

transmission assets to SPP.

1. Procedural History

A. SPP’s Application for CCN and Request for Declaration of Inapplicability of Certain Arkansas Statutes

SPP is a Regional Transmission Organization (“RTO”) approved by the Federal Energy

Regulatory Commission (“FERC”). As an RTO, SPP provides transmission service over

transmission facilities owned by its public utility and non-public utility members.

On October 12, 2004, SPP filed in Docket No. 04-137-U an Application for a Certzjicate

of Public Convenience and Necessity (“Application”). SPP requests a CCN “to transact the

business of an electric public utility in the State of Arkansas only to the extent that it will be

asserting functional control over those transmission assets which will be placed under SPP’s Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 3 of 40 control upon this Commission‘s approval of the applications of the affected jurisdictional utilities that are members of SPP.” Application at 7 13.

SPP also requests “that the Commission declare those regulatory statutes which otherwise would apply to traditional electric utilities to be inapplicable to SPP.” Application at 7 16.

SPP’s Application included Testimony and Exhibits in support of its Application. On

August 4, 2005, SPP filed Supplemental Testimony including a Cost-Benefit Analysis (“Study”) of implementation of a regional Energy Imbalance Service (“EIS”) market within SPP.

B. The Utilities’ Applications to Transfer Control

In separate dockets, four utilities have sought permission to transfer functional control of

their transmission facilities to the SPP RTO. On October 2 1,2004, SWEPCO filed its request in

Docket No. 04-143-U. OG&E filed its request in Docket No. 04-1 1 1-U on August 5, 2004 and

Empire filed its request on November 4,2005 in Docket No. 05- 132-U.

C. Consolidation and Hearing

On September 29, 2005, the Commission issued Orders consolidating Docket Nos.

04-1 11-U, 04-129-U, and 04-143-U with the SPP CCN docket, Docket No. 04-137-U. On

November 22, 2005, Docket No. 05-132-U was consolidated with Docket No. 04-137-U by

Commission Order. The Commission held a public hearing to consider the consolidated

Applications on April 4, 2006. Entering appearances at the hearing were SPP, SWEPCO,

OG&E, Empire, the Attorney General of the State of Arkansas (“AG”), and the General Staff of

the Commission (“Staff ’). Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 4 of 40

11. Background Facts Applicable to All Applications

The Commission has before it four requests: SPP’s request for a CCN, and three utilities’ requests to transfer functional control of their transmission assets to SPP. Although SPP’s request involves a statutory provision different from that applicable to the utilities’ requests, there is a single question common to all four applications: will SPP’s functional control of the utilities’ transmission facilities benefit Arkansas ratepayers and serve the public interest?

Because the facts necessary to answer this question are relevant to all four applications, we will

set them forth here first; then apply them to the four applications.

A. Electric Industry Changes Leading to the SPP RTO

The emergence of RTOs is the consequence of three decades of federal policy efforts to

introduce and foster wholesale electric generation competition. The main events leading to this

point are as follows:

Introduction of qualifying facilities: The Public Utility Regulatory Policies Act of

1978 (“PURPA”) created a new type of nonutility generator designated as a qualifying facility

(“QF”). A QF was a cogenerator, or a small power producer, the latter usually producing

renewable energy. PURPA required each electric utility to buy capacity and energy at the

utility’s avoided cost. This utility obligation to purchase power from cogenerators stimulated the

entry of many new generators into wholesale generation markets, demonstrating the fact that

electric generation was not a natural monopoly, but could in fact be provided in the context of a

competitive wholesale market.

Introduction of exempt wholesale generators: Congress accelerated the market entry

of wholesale generators with the Energy Policy Act of 1992. That Act established another Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 5 of 40 category of electric generator, the exempt wholesale generator (“EWG”), and exempted it from the ownership restrictions of the Public Utility Holding Company Act of 1935 (“PUHCA”). The

effect of the 1992 Act was to remove all limits on the types of entities permitted to own wholesale generation, and where they could own them.’

Utility-by-utility transmission access: Over the next four years, FERC recognized that

wholesale electric generation markets could not grow if generation-owning utilities unilaterally

controlled access to the transmission highways, because they would use that control to favor

their own generation over the generation of their competitors. To address the problem, FERC

issued its Order 888 in April 1996, based on its authority under the Federal Power Act (“FPA”)

of 1935 to prevent undue discrimination in transmission service.2 Order 888 required all

transmission-owning utilities subject to FERC jurisdiction to file a pro forma Open Access

Transmission Tariff (“OATT”). The OATT: (a) obligates the transmission owner to make its

transmission system available to wholesale generation competitors on terms comparable to how

the owner uses its transmission system for its own generation; and (b) requires electric utilities to

take transmission services for all of its wholesale sales and purchases of energy under that same

tariff. Accompanying Order 888 was Order No. 889,3 requiring that all transmission

’ Congress repealed PUHCA in the Energy Policy Act of 2005. Energy Policy Act of 2005, Pub. L. No. 109-58, sec. 1263, 119 Stat. 594, (2005) (EPAct 2005).

Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. & Regs. 31,036 (1996), order on reh‘g, Order No. 888-A, FERC Stats. & Regs. 31,048 (1997), order on reh’g, Order No. 888-B, 81 FERC 7 61,248 (1997), order on reh‘g, Order No. 888-C, 82 FERC 161,046 (1998), afd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), afdsub nom. New York v. FERC, 535 U.S. 1 (2002).

Open Access Same-Time Information System (Formerly Real-Time Information Network) and Dockets No. 04-137-U; 04-1 1l-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 6 of 40 reservations made pursuant to the OATT be scheduled online, using an Open Access Same-Time

Information System (“OASIS”) available to all potential transmission users. The purpose common to Orders 888 and 889 was independence: independence of transmission access and pricing from the influence of market participants, particularly electric utilities that owned both generation and transmission.

Regional transmission service: Order 888 provided wholesale generators with transmission access on a utility-by-utility basis. FERC recognized that the transmission system is a inultistate, multi-utility machine, whose physical operation and planning is most efficiently conducted on a regional basis rather than a utility-by-utility basis. In an effort to promote the regionalization of transmission service, while adhering to the independence objective of Orders

888 and 889, FERC issued Order 2000.4 In that Order, FERC determined that sole reliance on

Order 888: (a) left engineering and economic inefficiencies in the operation and expansion of the transmission grid; and (b) left electric transmission owners able to discriminate in the operation of their transmission systems so as to favor their own or their affiliates’ power generation marketing activities. Order 2000 did not require transmission owners to form and join RTOs; rather, it encouraged voluntary RTO formation, as a means of fostering greater competition

Standards of Conduct, Order No. 889, 61 FR 21,737 (May 10, 1996), FERC Stats. & Regs,, Regulations Preambles 1991-1996 31,035 (Apr. 24, 1996); Order No. 889-A, order on reh’g, 62 FR 12,484 (Mar. 14, 1997), FERC Stats. & Regs., Regulations Preambles 1996-2000 31,049 (Mar. 4, 1997); Order No. 889-B, reh‘g denied, 62 FR 64,715 (Dec. 9, 1997), FERC Stats. & Regs., Regulations Preambles 1996-2000 31,253 (Nov. 25, 1997).

4 Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (January 6, 2000), FERC Stats. & Regs. 31,089 (1999), order on reh’g, Order No. 2000-A, 65 Fed. Reg. 12,088 (March 8, 20001, FERC Stats. & Regs. 31,092 (2000), affd sub nom. Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001). Dockets No. 04-137-U; 04-1 1 l-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 7 of40 among, and access to, a wider array of generation options for all load-serving entities in that region. The requisite criteria for obtaining FERC recognition and certification as an RTO included four minimum characteristics, and eight minimum hnctions, as follows:

0 Minimum characteristics: independence, scope and regional configuration, operational authority, and responsibility for short-term reliability.

Minimum functions: tariff administration, congestion management, parallel path flow, ancillary services, open access same time information system, total transmission capability and available transmission capability, market monitoring, planning and expansion, and interregional coordination.

There are several other FERC-approved RTOs in the U.S., including the IS0 New England,

PJM. Midwest Independent System Operator (“MISO”) and the New York ISO. Dozens of electric utility companies have joined these organizations, such that roughly 2/3 of the United

States population is currently served by an RTO.

B. TheSPPRTO

SPP is an Arkansas nonprofit corporation currently with forty-eight members, including fourteen investor owned utilities, six municipal systems, eight cooperatives, three State authorities, one Federal power marketing agency, three independent power producers, and thirteen power marketers. SPP covers all or parts of Arkansas, Kansas, Louisiana, Mississippi,

Missouri, New Mexico, Oklahoma, and Texas.

SPP was founded in 1941 by eleven utilities to support industrial production for the war effort. In 1968, SPP joined with other regional entities as a regional reliability council making up what became the North American Electric Reliability Council. In 1998, SPP began providing regional transmission service under a regional OATT pursuant to FERC Order NO. 888. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 8 of 40

In October 2003, after several unsuccessful attempts to achieve RTO status at FERC, SPP filed for recognition as an RTO in FERC Docket No. RTO4-1-000. In February 2004, FERC conditionally granted RTO status subject to the fulfillment of six requirements, including the adoption of an independent Board structure; the assurance that SPP would be the sole transmission provider; the possession of clear authority to exercise functional control over transmission; having an independent market monitor in place; the ability to independently and solely determine which projects to include in the regional transmission plan; and filing a seams agreement with the MISO. After making a series of compliance filings, the SPP was granted

RTO status in October 2004.5

On March 20, 2006, the FERC issued an Order on proposed SPP tariff revisions that would have initiated the regional EIS market.6 Energy imbalance occurs when the utility generation resources output does not exactly match its load. In the past, utilities leaned on adjoining utility systems to provide or absorb the imbalance, to be later repaid in kind. Once the

EIS market is implemented by SPP, however, utilities will be able to compare self-supply costs with EIS market options for imbalance energy. SPP had proposed that the market start on May

1, 2006. However, FERC directed a five-month delay and required certain additions to SPP’s proposed tariff language. SPP’s EIS market is now scheduled for implementation on November

1,2006.

Order Granting RTO Status Subject to FulJillment of Requirements, 106 FERC 7 61,110 (2004); Southwest Power Pool, Inc., Order on Compliance Filing, 109 FERC 7 61,009 (2004); Southwest Power Pool, Inc., Order on Proposed Joint Operating Agreement, 109 FERC 7 61,008 (2004); Southwest Power Pool, Inc., Order on Rehearing, 109 FERC 7 61,110 (2004).

6 Southwest Power Pool, Inc., 114 FERC 61,289 (2006). Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 9 of 40

C. The Regional State Committee

In April 2003, FERC issued a White Paper subtitled “Wholesale Power Market

Platform”.’ The White Paper recognized that the regionalization of transmission service stimulated by an RTO should also try to accommodate the retail policy preferences of the affected state commissions, and allow them to protect their native load retail ratepayers to the degree possible, without conflicting with federal jurisdiction. The White Paper thus encouraged the formation of a Regional State Committee (“RSC”) in each RTO region.

As explained by FERC, an RSC would have primary (Le., “decisional”) responsibility for determining the regional proposals on the following subjects:

1. Whether and to what extent participant funding would be used for transmission enhancements within the region;

2. Whether license plate or postage stamp rates will be used for the regional access charge;

3. Whether there would be financial transmission right allocations, where a locational marginal pricing methodology is used;

4. The transition mechanism used to ensure that customers whose utilities have transferred transmission facilities to the RTO receive financial transmission rights equivalent to the firm rights previously guaranteed by their utilities’ control of transmission facilities;

5. The approach to assuring regional resource adequacy; and

6. Regional transmission facilities planning.

7 See Notice of White Paper in Docket No. RMO1-12-000 (issued April 28, 2003), available at http://elibrary.ferc.gov:O/idmws/file~list.asp?document~id=4097493(containing the White Paper as an attachment). Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 10 of 40

Consistent with the White Paper, the SPP RSC organized itself in April 2004, and incorporated in Arkansas. Current members include commissioners from the state commissions of Arkansas, Kansas, Missouri, Oklahoma and Texas. In accordance with the terms outlined in

FERC’s White Paper, SPP drafted its RTO Bylaws, tariffs and accompanying RTO application in a manner that obligated itself to take the RSC’s consensus position in these “decisional” areas and to file them as its Section 205 tariff filing at the FERC. When the FERC approved SPP’s

RTO application in October 2004, it approved these components of the RTO operation as well.

To date, the SPP RSC has taken action on two issues that are relevant here: (1) the methodology for allocating costs associated with transmission upgrades; and (2) a study of the costs and benefits associated with utilities joining, and transacting within, the SPP RTO.

The cost allocation methodology addresses Base Plan projects and non-Base Plan projects.

Base Plan projects: The SPP regional planning staff will produce an annual Base Plan.

Base Plan transmission projects consist of : (a) transmission projects required to maintain compliance with North American Reliability Council (“NERC”) Reliability Standards and SPP criteria, plus; (b) new transmission facilities needed to provide service from any newly

“designated (generation) resources” over a 10-year planning horizon. Designated resources are those generation resources identified by the utility or load serving entity as necessary to provide firm service to its native load customers at their current and projected future usage levels.

Based on SPP’s flow-based transmission expansion models which can track the beneficiaries of the increased flow capability of proposed new transmission projects, it was determined that Base Plan projects should be funded 113 regionally &e., by all ratepayers in the Dockets No. 04-137-U; 04-1 1I-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 11 of 40

SPP region) and 2/3 by the utilities within the zone(s) that directly benefit from the upgrade. For each Base Plan project, SPP conducts a flow-based MW-mile impact study to assess which zones actually benefit from the upgrade. The revenue requirement is allocated proportionately with the

MW-mile impact.

Non-Base Plan projects: All non-Base Plan transmission projects are classified as

“requested upgrades.” Costs are assigned to the requestor, and then placed in the zonal transmission revenue requirement. Revenue from incremental use of the new facility by others is then credited back to the owner

This proposal was approved by the RSC and the SPP Board, submitted to the FERC as

SPP’s Section 205 filing, and was then approved by FERC through its approval of a February

2005 compliance filing in Docket No. ER05-652.8

The second issue addressed by the RSC was the commissioning of a regional Cost

Benefit Study (“CB Study”) undertaken by CRA International, completed in April 2005, and entered as an exhibit in this Docket, discussed below.

D. The Cost-Benefit Study

On August 4, 2005, SPP submitted a CB Study as part of the Prepared Supplemental

Joint Testimony of SPP witnesses Ralph L. Luciani and Ellen Wolfe, consultants with CRA

International (“CRA”). At SPP’s request, CRA updated the CB Study for the year 2006 to reflect higher fuel costs for coal, fuel oil, and natural gas. The results of the updated CB Study were

8 Southwest Power Pool, Inc., 1 1 1 FERC 7 6 1,118 (2005), order on reh ‘g, 1 12 FERC 7 6 1,3 19 (2005), order on compliancefiling, 114 FERC 61,021 (2006), 115 FERC 61,121 (2006) (letter order on compliance filing). Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 12 of 40 filed as Exhibit 2 of the Second Prepared Supplemental Joint Testimony of SPP witnesses

Lucian1 and Wolf on December 22,2005.

The CB Study addressed four categories of costs and benefits:

1. Trade benefits ;

2. Wheeling charges and revenues;

3. SPP's implementation and operating cost; and

4. Each utility's implementation and operating costs

The CB Study compared these costs and benefits under three scenarios:

1. The Base Case (Le., the status quo);

2. The EIS Case, which assumes (a) membership of SWEPCO, OG&E and Empire in the RTO and (b) implementation by SPP of an Energy Imbalance Service market; and

3. The Stand-alone Case, which assumes all transmission service, will be provided by each individual transmission owner under each owner's individual OATT rather than by SPP.

The assumptions under each case were:

Base Case: SWEPCO, OG&E and Empire are SPP members, taking regional transmission service under the SPP tariff, but no EIS is available. No wheeling charges between SPP members, reduced flowgate capacity; dispatch of non-network generation is suboptimal.

EIS Case: SWEPCO, OG&E and Empire are SPP members, taking regional transmission service under the SPP tariff, with EIS available. No wheeling charges between SPP members, full flowgate capacity; dispatch of non-network generation is optimal.

Stand Alone Case: SWEPCO, OG&E and Empire are not SPP members, and none of these three utilities is taking EIS. Area to area wheeling charges apply, reduced flowgate capacity; dispatch of non-network generation is suboptimal. Dockets No. 04-137-U; 04-1 1l-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 13 of 40

The CB Study concluded that overall and for Arkansas specifically, operation under the

EIS scenario will generate greater benefits than either the base case or the stand-alone case. The following charts, drawn from the CB Study, summarize the results.

Comparing the EIS Case to the Base Case, the CB Study showed that customers were better off under the EIS Case by $373.10 million over the ten years 2006-2015. That is, assuming all SPP utilities, and all generators within the SPP’s boundaries, participate in the EIS market, the additional implementation of the Energy Imbalance Service markets benefits consumers. Drawn from the Prepared Joint Testimony of SPP witnesses Luciani and Wolfe, the following three tables display these results in three ways: by type of benefit or cost, by transmission company, and by state:

EIS Case Compared To Base Case Total Benefit or (Cost) 2006-2015 By Category of Benefit or (Cost) ($ millions)

Trade Benefits 614.30 Transmission Wheeling Charges 24.40 Transmission Wheeling Revenues (53.20) SPP EIS Implementation Costs ( 104. SO) Utilities’ EIS Implementation Costs ( 107.60) Total 373.10 Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 14 of 40

EIS Case Compared To Base Case Total Benefit or (Cost) 2006-2015 By Transmission Owner ($ millions)

Transmission Owner Type Benefit

AEP (SWEPCO and PSO) IOU 58.50 Empire IOU 47.90 KCPL IOU (2.20) OG&E IOU 95.30 SPS IOU 69.40 Westar Energy IOU 27.40 Midwest Energy coop 0.70 Western Farmers coop 75.20 SWPA Fed 1.20 GRDA State (5.00) Springfield, MO. Muni 6.00

Total 373.10

EIS Case Compared To Base Case Benefit or (Cost) for Retail Customers of Investor-Owned Utilities 2006-2015 By State ($ millions)

Arkansas 8.5 Louisiana (3.8) Kansas 26.4 Missouri 41.7 New Mexico 9.2 Oklahoma 141.1 Texas 26.6

The CB Study also compared the Stand-Alone Case to the Base Case: if all transmission owners were to leave SPP (the Stand-Alone Case), there would be a ratepayer loss of $70.5 million over the ten years from 2006-2015. The following three tables, again from SPP Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 15 of 40

Witnesses Luciani and Wolfe, display this result, by category of benefit or cost, by transmission company, and by State:

Stand-Alone Case Compared to Base Case Total Benefit or (Cost) 2006-2015 By Category of Benefit or (Cost) ($ millions)

Trade Benefits (20.9) Transmission Wheeling charges (499.8) Transmission Wheeling Revenues 515.6 Costs to Provide SPP Functions (46.0) FERC charges 27.3 Transmission Construction Costs 0.5 Withdrawal Obligations Total (70.5)

Stand-Alone Case Compared to Base Case Total Benefit or (Cost) 2006-2015 By Transmission Company ($ millions)

Benefits; Exclude Wheeling Total Transmission Owner Type Wheeling Impacts Benefits AEP (SWEPCO and PSO) IOU (19.8) (3.0) (22.8) Empire IOU (5.8) (19.8) (25.6) KCPL IOU (17.8) 68.7 50.9 OG&E IOU (8.2) (10.4) (18.6) SPS IOU (5.0) 49.5 44.5 Westar Energy IOU (1 7.0) 0.2 (16.9) Midwest Energy coop (7.9) 3.9 (3.9) Western Farmers coop 1.3 (52.5) (5 1.2) SWPA FED 1.2 (20.9) (19.7) GRDA State (4.8) (6.0) (10.8) Springfield, MO. Muni (2.5) 6.1 3.5 Total (86.3) 15.8 (70.5) Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 16 of 40

Stand-Alone Case Compared to Base Case Benefit or (Cost) for Retail Customers of Investor-Owned Utilities 2006-2015 By State ($ millions)

Benefits; Exclude Total Wheeling Benefits Arkansas (3.0) (5.0) Louisiana (2.6) (3.0) Kansas (22.2) 3.6 Missouri (13.7) 2.7 New Mexico (0.7) 5.9 Oklahoma (16.2) (25.9) Texas (5.5) 16.4

These data indicate that each of the two separate steps - (a) transmission owners joining the SPP (moving from Stand-Alone to Base Case), and (b) SPP implementing Energy Imbalance

Service (moving from Base Case to EIS Case) -benefits the ratepayers over the ten-year period

2006-2015,

On December 22,2005, SPP filed the Second Supplemental Testimony of Mr. Lucian0 and Ms. Wolfe. An update of the original CB Study reflecting higher fuel costs was attached to this Testimony. Using these higher fuel costs for 2006 and extrapolating those higher gas costs for the next ten years, the CB Study showed increased benefits to Arkansas ratepayers associated with the EIS case. The increase in benefits over the original CB Study for 2006 and as expected over the next ten years for Arkansas ratepayers is as follows: Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 17 of 40

EIS Market Trade and Net Wheeling Benefit to Arkansas Ratepayers Using Updated Fuel Costs By Arkansas Transmission Owner EIS Case - 2006 Only ($ thousands)

Total Arkansas SWEPCO Empire OG&E Retail Savings Demonstrated in Original Study 120 249 1,317 1,685 Savings Using Updated Fuel Costs 83 1 348 2,677 3,855 Increase in Benefits Due to Updated Fuel Costs 71 1 99 1,360 2,169

Estimated EIS Benefit to Arkansas Ratepayers if 2006 Fuel Price Increase Applies to Subsequent Years By Arkansas Transmission Owner EIS Case - 2006-2015 ($ thousands)

Total Arkansas SWEPCO Empire OG&E Retail Savings Demonstrated in Original Study (2,942) 1,446 10,046 8,550 Savings Using Updated Fuel Costs 4,996 695 9,557 15,248 Increase in Benefits Due to Updated Fuel Costs 2,054 2,141 19,603 23,798

111. SPP's Application for Certificate of Public Convenience and Necessity

A. Commission Jurisdiction

Ark. Code Ann. 823-3-201 (a) states:

No new construction or operation of any equipment or facilities for supplying a public service or extension thereof shall be undertaken without first obtaining from the Arkansas Public Service Commission a certificate that public convenience and necessity require or will require the construction or operation. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 18 of 40

Transmission facilities in Arkansas “supply a public service.” The jurisdictional question is whether SPP’s relationship to these transmission facilities constitutes “operation” within the meaning of Ark. Code Ann. 523-3-201 (a). The answer is yes.

As a FERC-approved RTO, SPP must have the four “minimum characteristics” and eight

“minimum Eunctions” required by FERC Order 2000. Among the four “minimum characteristics” is “possession of operational authority for all transmission facilities under the

RTO’s control.” In Order 2000, FERC explained:

One necessary aspect of operational authority as used here refers to the authority to control transmission facilities. This includes, but is not limited to, switching transmission elements into and out of operation in the transmission system (e.g., transmission lines and transformers), monitoring and controlling real and reactive power flows, monitoring and controlling voltage levels, and scheduling and operating reactive resources. Functions such as these must be included within the operational authority of an RTO.

SPP proposes to conduct these activities, within the state of Arkansas, with respect to the transmission facilities of SWEPCO, OG&E and Empire. The Commission finds that these activities fall within the meaning of “operate” in Ark. Code Ann. $23-3-201(a). Some may argue that notwithstanding the RTO’s obligatory role, the RTO will be merely giving orders to the utilities, which then will perform the actual physical “operations”. Without necessarily agreeing with this characterization of the SPP-utility relationship, the distinction does not render SPP non-jurisdictional. Under Order 2000, SPP will have the legal obligation to operate transmission facilities. That SPP might contract or delegate the physical task does not place it outside

Commission jurisdiction. Dockets No. 04-137-U; 04-1 1 l-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 19 of 40

B. Applicable Standards

Ark. Code Ann. 523-3-205 empowers the Commission to grant, deny or condition a certificate sought under Ark. Code Ann. 523-3-201:

The commission shall have the power, after hearing, unless waived by the parties, to issue the certificate as prayed for, to refuse to issue the certificate, or to issue it for the construction or operation of a portion only of the contemplated facility or extension thereof, or for the partial exercise only of the right or privilege and may attach to the exercise of the rights granted by the certificate such terms and conditions in harmony with this act as in its judgment the public convenience and necessity may require.

Id. Ark. Code Ann. $23-3-205. In applying this provision to the facilities siting context, the

Commission has considered cost, health and safety, engineering and technical concerns, ecological/environmental disruption, disruption to or interference with existing man-made property uses, disruption to or interference with planned man-made property uses, and aesthetic displeasure. See, e.g., In the matter of the Application of Arkansas Power and Light Co. for a

Cert@cate of Public Convenience and Necessity, Docket No. 89- 164-U; Order No. 12, 1990 Ark.

PUC LEXIS 23 at 29 (1990) (ALJ decision deriving these factors from siting proceedings in

Arkansas and other states).'

Not all these factors apply to a transfer of operational authority over transmission facilities. Here the Commission will focus on the cost-benefit effects, reliability, and the preservation of the Commission's jurisdiction.

0 Under Commission practice, final orders of the designated presiding officer constitute findings and conclusions of the Commission thirty (30) days after issuance absent further action. In this instance, the Commission took no further action. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 20 of 40

C. SPP’s Testimony and Responses

SPP witness Richard A. Wodyka testified that the CB Study was a complete and comprehensive study that used sound modeling tools to quantify the economic value of SPP’s

EIS market. Mr. Wodyka explained that the EIS market will facilitate SPP’s efforts to coordinate generation dispatch across the region in an open, nondiscriminatory manner, while improving coordination with neighboring systems, such as the MISO. The EIS market will reduce risk and provide more choices for participants.

Mr. Wodyka also cited the non-quantitative benefits of an SPP RTO. Those benefits include transparent price signals that better inform wholesale market participants, leading to better business decisions, and more choices for both buyers and sellers. Also, the expanded centralized coordination of the grid should improve the reliability of transmission service on the systems of all affected transmission owners and their respective customers. Finally, SPP’s market monitors will provide a new layer of ratepayer protection and a valuable source of information for the state commissions.

General Staff witness Ralph C. Smith testified that the economic benefits identified in the

CB Study were so small that the Commission should weigh the risk that a change in any assumptions in the study could change the results from positive to negative. He cited the benefits of eliminating pancaked transmission rates within the RTO’s boundaries, as well as price transparency and improved transmission planning, but pointed to the risk of not achieving these benefits. Mr. Smith recommended the Commission receive assurance that a broad number of utilities in the SPP-wide region will participate in the SPP. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 21 of 40

D. Commission Conclusions

SPP’s in-depth CB Study found quantitative benefits to Arkansas ratepayers if the SPP

RTO implements the EIS market and if the applicant utilities participate. The CB Study, as revised, used reasonable assumptions, conservative enough to give the Commission confidence about the benefits. Conversely, the risk to ratepayers of economic losses is greater if Arkansas’s utilities do not transfer functional control of their transmission facilities to the SPP RTO, and do not participate in the EIS market. In addition, no one disputes the qualitative benefits that would be derived from membership in the SPP RTO, such as those discussed by SPP witness Wodyka.

An additional qualitative benefit is the existence of the RSC, an organization firmly established, recognized and respected by FERC, the transmission owners, SPP and all its staff and members. The existence of an RSC, particularly with the “decisional” authority outlined in the SPP’s Bylaws, tariffs and FERC Order granting SPP RTO status, means that Arkansas and the other SPP states are not passive recipients of RTO policy. The RSC has very specific authority to determine the RTO proposals on the key regional transmission and market development issues that will have the greatest effect on the retail consumers over which the state commissions have jurisdictional responsibility and authority. This RSC role already has precedent in the process that was used to determine the cost allocation methodology for incremental transmission investment in the region. The RSC will have further opportunities to determine SPP policy on other issues important to Arkansas, including the allocation of the regional access charge (e.g., license plate vs. postage stamp); preservation and allocation of Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 22 of40 transmission rights; design of regional resource adequacy approaches; and regional transmission facilities planning.''

With a positive benefit-cost relationship and an effective RSC, the RTO concept can help achieve one of the Commission's goals: vigorous wholesale generation competition throughout the region in which all Arkansas utilities can feasibly shop. Wholesale generation competition creates choices for Arkansas utilities. Without a broader portfolio of viable wholesale generation options, made available through a more robust and interconnected regional transmission network, Arkansas ratepayers are vulnerable to having to pay higher generation costs than they otherwise would. Arkansas ratepayers are still paying for high power plant costs incurred under an earlier regime where the only generation options were those built by the incumbent utility or its affiliates. By creating choices, wholesale competition also creates benchmarks, against which this Commission can judge the reasonableness of utility purchase or construction decisions. By creating choices and benchmarks, and having a more robust transmission network, wholesale competition will enable retail customers to have the lowest delivered cost reasonably available within the region.

Wholesale generation competition, to become vigorous throughout the region, requires adequate transmission capacity and nondiscriminatory transmission service across that same region. An RTO, operating transmission independently across the regional market, is an appropriate institution for providing such service and for planning a transmission system that is

'' SPP and the RSC are also currently exploring the use of regional resource planning which has the potential of benefiting those in the SPP region including the Arkansas utility members of SPP. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 23 of 40 interconnected and robust enough to facilitate access to a broader array of regional resource options.

Finally, the Commission’s approval of the four requests will not diminish its ability to ensure just and reasonable rates for Arkansas electricity customers. Each transmission owner remains under the Commission’s jurisdiction with respect to retail electric rates and all related

electricity facility operations, facility siting, financing, reliability, etc.

Accordingly, the Commission grants to the SPP RTO a CCN to operate in Arkansas the

transmission facilities of SWEPCO, OG&E and Empire, subject to one condition to which SPP

committed to in its Application: that SPP shall not exercise the power of eminent domain under

the laws of the State of Arkansas.

IV. SPP’s Request for Declaration of Inapplicability of Certain Arkansas Statutes

Ark. Code Ann. 523-1-101 (9) (A) provides:

“Public Utility” includes persons and corporations, or their lessees, trustees, and receivers, owning or operating in this state equipment or facilities for:

(i) Producing, generating, transmitting, delivering, or furnishing gas, electricity, steam, or another agent for the production of light, heat, or power to or for the public for compensation.

Because SPP will be transmitting electricity to or for the public for compensation, SPP is

a public utility. As such, it is potentially subject to various provisions of the Arkansas utility

statutes.

SPP does not argue that it is not a public utility; but it requests the Commission to waive

applicability of, or declare inapplicable, a long list of statutory provisions normally applicable to

Arkansas public utilities. Application at 9-11. SPP argues that because the Commission retains Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 24 of 40 authority over retail pricing, siting and financing issues for SWEPCO, OG&E and Empire,

application of these provisions to SPP would be duplicative; and that such duplicative regulation

would neither promote administrative efficiency nor serve the public interest. SPP adds that the

Commission’s active involvement in the SPP RSC adequately protects and furthers the public

interest.

These arguments are not persuasive. SPP will be providing public utility services in

Arkansas. So will the members who are Arkansas utilities. SPP activities do not duplicate retail

utility activities; therefore Commission oversight of SPP does not duplicate oversight of the

retail utilities. As for the Commission’s participation in the RSC, the subject matters addressed

by the RSC, summarized in Part 1I.C above, are different from the subjects addressed by the

Arkansas statutes at issue. So there is no duplication there either.

The provisions for which SPP seeks a declaration of inapplicability fall into one of two

categories: (1) provisions that apply because of SPP’s status as a public utility engaged in

activities within this Commission’s jurisdiction; and (2) provisions that do not apply because

they concern activities outside the Commission’s jurisdiction or are subject to FERC’s exclusive

jurisdiction. For those provisions which do apply, the Commission has no authority to declare

inapplicable that which the Arkansas Legislature has made applicable. However, SPP may

propose, when necessary, an efficient means of complying.

A. Statutory Provisions That Apply

1. Commission Powers - Ark. Code Ann. §23-2-304,§23-2-305

SPP asks the Commission to declare inapplicable two statutory provisions that establish

the scope of the Commission’s authority. Ark. Code Ann. 523-2-304 enumerates the Dockets No. 04-137-U;04-lll-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 25 of 40

Commission’s powers, which include setting retail electric rates, (Ark. Code Ann. $23-2-

304(a)( 1)); determining reasonable, safe and reliable service (Ark. Code Ann. §23-2-304(a)(2)); establishing regulations and practices to be observed by any or all public utilities (Ark. Code

Ann. $23-2-304(a)(3)); and ascertaining the value of public utility property insofar as material to the exercise of Commission jurisdiction (Ark. Code Ann. §23-2-304(a)(4)), among others. Ark.

Code Ann. 523-2-305 empowers the Commission to “alter or amend such reasonable rules pertaining to the operation, accounting, service, and rates of public utilities and of the practice and procedure governing all investigations by and hearings and proceedings before the commission as it may deem proper and not inconsistent with this act.”

Ark. Code Ann. $823-2-304 and 23-2-305 do not impose any obligations or duties on

SPP. They define the scope of the Commission’s powers. Declaring these provisions inapplicable would deprive the Commission of any ability to oversee or regulate those SPP activities within the scope of the Commission’s jurisdiction. The Commission will not disable itself from addressing future issues relating to SPP’s operation in Arkansas. We therefore reject

SPP’s request to declare Ark. Code Ann. $523-2-304 and 23-2-305 inapplicable.

2. Accounting and Reporting Requirements - Ark. Code Ann. $23-2- 306,923-2-307, 823-2-308

Ark. Code Ann. 523-2-306 authorizes the Cornmission to prescribe a uniform system of accounts for all public utilities within the Commission’sjurisdiction. Ark. Code Ann. 523-2-307 empowers the Commission to require any public utility to provide an inventory of any or all of its property “as to which the commission should have knowledge in order to enable it to perform its duties under this act.” Ark. Code Ann. 523-2-308 allows the Commission to direct a public Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 26 of 40 utility to file an annual report or a special report “concerning any matter about which the commission is authorized to inquire or to keep itself informed.”

The above provisions give the Commission authority to prescribe a uniform system of accounts or requirements for filing an inventory of property or annual reports for SPP.

Moreover, under Section 2.4.1 of the SPP Membership Agreement, SPP must comply with the reporting requirements of the state regulatory agencies with jurisdiction over SPP. These provisions are made applicable by the Arkansas Legislature, which did not authorize the

Commission to declare them inapplicable. Because these provisions overlap with FERC requirements (although the FERC requirements are not preemptive of the state requirements), the

Commission invites SPP to propose a means of compliance that minimizes duplication of effort.

3. Utility Consolidations - Ark. Code Ann. 523-3-102

Ark. Code Ann. $23-3- 102 governs activities such as utility consolidations, stock purchases or rental of property and transfer of utility control of assets. For example, Ark, Code

Ann. $23-3-102(c) provides:

No public utility shall sell, lease, rent, or otherwise transfer, in any manner, control of electric transmission facilities in this state without the approval of the commission, provided that the approval is required only to the extent the transaction is not subject to the exclusive jurisdiction of the Federal Energy Regulatory Commission or any other federal agency.

By this provision, the Arkansas Legislature determined that a public utility like SPP may not transfer control of transmission assets without Commission permission. Whether such a transfer, in particular circumstances, would trigger FERC jurisdiction at all, and whether such jurisdiction would be preemptive of or concurrent with this Commission’s jurisdiction, will depend on the facts at the time. This Commission has no power to determine the question now in the abstract. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 27 of 40

4. Stock Issuance Provisions - Ark. Code Ann. §23-3-103,§23-3-104, §23-3-105,§23-3-106

SPP seeks a declaration of inapplicability for the following provisions relating to utility issuance of stocks, bonds and notes: Ark. Code Ann. 523-3-103 (requiring Commission review of stock, bond and note issuances by public utilities incorporated in Arkansas); Ark. Code Ann.

$23-3-104 (authorizing utility issuance of stocks, bonds within 36 months of Commission approval order); Ark. Code Ann. 523-3-105 (limiting amount of bond issuance to the fair value of the properties of the issuer and the reasonable cost of the issuance and sale of the issues) and

Ark. Code Ann. 323-3-106 (authorizing Commission to require utility to account for proceeds of sales of stocks, bonds, among other things.

SPP is a public utility incorporated in Arkansas. As with any other public utility, the

Commission has an obligation under Ark. Code Ann. $23-3-103 to review SPP’s issuances of stocks, bonds and notes under the provisions listed above. The Commission’s obligation to review issuances of stocks and bonds is not preempted by FERC’s authority over SPP under the

FPA. Although Section 204(a) of the FPA gives FERC jurisdiction to review security and bond issuances, FERC review “does not extend to a public utility organized and operating in a State” where securities are regulated by a State commission. See Section 204(f), 16 U.S.C. $ 824c.

5. Adequate Service - Ark. Code Ann. 523-3-113

Ark. Code Ann. 323-3-113 provides that every public utility shall furnish and maintain adequate service “as shall promote the safety, health, comfort, requirements and convenience’’ of its patrons and the public and “shall establish and maintain adequate and suitable facilities, safety appliances, or other suitable devices ... sufficient for the security and convenience of the Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 28 of 40

public. e a” There is no statutory basis for making this provision inapplicable to SPP.

Inapplicability would mean that SPP does not have an obligation under state law to provide

service which “promote[s] the safety, health, comfort, requirements and convenience” in

Arkansas.

6. Complaints - Ark. Code Ann. 523-3-1 19

Ark. Code Ann. $23-3-1 19 authorizes persons to file a complaint against the public utility

for violations of any order, law, or regulation which the commission has jurisdiction to

administer .

Ark. Code Ann. $23-3-119 applies to SPP. As described throughout this section, SPP

remains subject to various statutory provisions concerning activities within the Commission’s

jurisdiction. Where SPP fails to comply with an applicable law or regulation, parties are entitled

to bring these violations to the Commission in the form of a complaint, just as they would with

respect to any other public utility. The Commission can determine on a case-by-case basis

whether it has jurisdiction over the subject matter of a particular complaint at the time the

complaint is filed.

7. Certificates of Convenience and Necessity - Ark. Code Ann. $923-3- 201 through 23-3-206

SPP asks the Commission to declare inapplicable Ark. Code Ann. $523-3-201 through

23-3-206 related to certificates of public convenience and necessity, “in connection with

transmission upgrades.” These provisions include Ark. Code Ann. $23-3-201 (prohibiting new

construction or operation of facilities supplying a public service or extension thereof without first

obtaining a certificate of necessity and convenience); Ark. Code Ann. 523-3-202 (requiring Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 29 of40

CCN for utility to resume service under discontinued franchise); Ark. Code Ann. 523-3-203

(establishing filing requirements for CCN); Ark. Code Ann. $23-3-204 (authorizing Commission

to issue CCN); Ark. Code Ann. $23-3-205 (specifying that Commission can grant, deny or

condition CCN); and Ark. Code Ann. 423-3-206 (allowing filing of complaint for unauthorized

construction).

Because of the possibility that SPP will need to construct upgrades in Arkansas, and

because the Commission has no power to render a provision inapplicable where the Arkansas

Legislature made it applicable, the Commission rejects this SPP request.

8. Organization and reorganization of public utilities - Ark. Code Ann. 523-3-101

Ark. Code Ann. 523-3-101 provides that “organizations or reorganizations of all public

utilities shall be subject to the supervision and control of the Commission” and that “no

organization or reorganization shall be given effect” without written Commission approval. SPP

is a public utility, thus its reorganizations are subject to this statute. While some elements of an

SPP reorganization may relate to transmission in interstate commerce, and thus under certain

circumstances fall within FERC’s exclusive jurisdiction, not all aspects of a reorganization will.

B. Statutory Provisions That Do Not Apply

1. Ratemaking Provisions - Ark. Code Ann. 523-3-114; Ark. Code Ann. $23-4-101; Ark. Code Ann. 3523-4-103 through 23-3-110; Ark. Code Ann. $523-4-201 through 23-4-208; Ark. Code Ann. 5523-4-401 through 23-4-421

SPP asks the Commission to declare inapplicable the following statutory provisions

dealing with ratemaking: Ark. Code Ann. 923-3-1 14 (prohibiting utility from granting

unreasonable preference to corporation or person as to rates or services); Ark. Code Ann. 623-4- Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 30 of 40

101 (empowering Commission to set rates for “public utilities and matters” over which it has jurisdiction); Ark. Code Ann. 523-4-103 (establishing just and reasonable standard for rates);

Ark. Code Ann. 523-4-104 (providing that all charges must be just and reasonable); Ark. Code

Ann. $23-4-105 (requiring utilities to file schedule of jurisdictional rates); Ark. Code Ann. $23-

4- 106 (allowing for public inspection of rate schedules); Ark. Code Ann. 523-4-107 (prohibiting

utility from charging rates other than those on file); Ark. Code Ann. 523-4-108 (authorizing

sliding scale of rates, subject to Commission approval); Ark. Code Ann. 523-4-109 (allowing

utilities to enter into agreements for minimum charges, subject to Commission approval); Ark.

Code Ann. 523-4-110 (requiring 30 days notice of rate changes); Ark. Code Ann. 523-4-201

(granting Commission exclusive jurisdiction to determine rates for utility service in Arkansas);

Ark. Code Ann. 523-4-202 (requiring utility bills to comply with rate schedule); Ark. Code Ann.

$23-4-203 (requiring utility bills to show units charged); Ark. Code Ann. 523-4-204 (prohibiting

utility from charging for disconnection); Ark. Code Ann. 523-4-205 (authorizing Commission to

order utilities to make refunds); Ark. Code Ann. 523-4-206 (requiring utility to provide interest

on consumer deposits); Ark. Code Ann. 523-4-207 (prohibiting utility from recovering

promotional and political advertising charges in rates); Ark. Code Ann. 523-4-208 (governing

utility service to military installations); Ark. Code Ann. 523-4-401 (requiring notice of change of

rates on file); Ark. Code Ann. 523-4-402 (requiring utility to give thirty days notice of change in

filed rates); Ark. Code Ann. 523-4-403 (allowing changes in filed rates without thirty days notice

for good cause shown); Ark. Code Ann. 523-4-404 (requiring proposed changes to be reflected

in rate schedule); Ark. Code Ann. $23-4-405 (authorizing Commission to investigate rates on

file); Ark. Code Ann. 923-4-406 (requiring use of test periods to justify new rates); Ark. Code Dockets No. 04-137-U; 04-1 1 l-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 3 1 of 40

Ann. $23-4-407 (authorizing Commission to suspend proposed rates); Ark. Code Ann. $23-4-

408 (allowing interim implementation of suspended rates); Ark. Code Ann. $23-4-409

(providing that rate increase not effective until final order); Ark. Code Ann. 523-4-410

(authorizing Commission to fix rates where utility rates found unjust and unreasonable); Ark.

Code Ann. $23-4-4 1 1 (authorizing conditional implementation of suspended rates); Ark. Code

Ann. 923-4-412 (providing for utility collection of rates set in Commission order); Ark. Code

Ann. 523-4-413 (authorizing surcharge to recover rates increased by courts); Ark. Code Ann.

$23-4-414 (allowing refund of excessive rate collections under bond); Ark. Code Ann. $23-4-

41 5 (providing that refunds of excessive bonded collections not stayed during rehearing); Ark.

Code Ann. 523-4-416 (authorizing utility to impose surcharge to collect excessive refunds);

Ark. Code Ann. $23-4-417 (allowing utility to file petition for mandamus for Commission rate

order); Ark. Code Ann. 523-4-418 (authorizing utility to bring suit against utility to compel

refunds); Ark. Code Ann. 523-4-419 (governing utility application for additional increases); Ark.

Code Ann. 523-4-420 (requiring Commission to report to Legislative Counsel on status of rate

applications); and Ark. Code Ann. 523-4-42 1 (prohibiting Commission from reducing any

collective bargaining benefits as part of rate case).

These ratemaking provisions do not apply to SPP. The Commission does not have

jurisdiction over SPP’s wholesale rates for unbundled transmission service, which are governed

instead by the terms of its OATT filed at FERC. See, e.g., Ark. Code Ann. $ 23-4-101

(providing that Commission only has authority to set rates for “matters” over which it has

jurisdiction). Because SPP is not required to file rates for transmission service at the

Commission, none of the statutory provisions concerning retail ratemaking are applicable to SPP. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 32 of40

2. Annual Statement of Earnings and Fees - Ark. Code Ann. $23-3-109 et se4 Ark. Code Ann.. 523-3-109 provides that “each utility subject by law to the payment of fees or charges under the jurisdiction of... the . . . Commission . . . shall prepare and transmit to the commission . . . a certified statement of the gross earnings from its properties in Arkansas for the preceding calendar year.. ..“ Ark. Code Ann.. 523-3-1 10 (a)(l) provides that “there shall be collected annually from each utility subject by law to the payment of fees or charges under the jurisdiction of the . . . Commission . . . a fee in an amount which shall be equivalent to that proportion of the total utilities costs that the gross earnings of each of the utilities bear to the total gross earnings of all utilities.”

As a public utility subject to the jurisdiction of this Commission, the SPP will be required to submit an annual gross revenue report pursuant to the provisions of Ark. Code Ann.. $23-3-

109 et seq and pay to the Commission an appropriately assessed annual fee pursuant to the provisions of Ark. Code Ann.. $23-3-1 lO(1) et seq.

However, the Commission recognizes that Ark. Code Ann.. 523-3-1 lO(3) provides that:

“In determining the amount of any fee for any individual utility pursuant to this subsection, the amount of gross earnings subject to the levy shall be reduced by any amounts derived from the sale of electricity to any other utility, an electric cooperative corporation or any other entity at wholesale rates regulated by the Arkansas Public Service Commission or the Federal Energy

Regulatory Commission.” (Emphasis added ) The Commission’s practice has been and will continue to be to interpret this provision of the law to allow the exclusion from the gross revenue calculation, the wholesale revenues derived from wholesale rates regulated by the FERC. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 33 of 40

V. The Utilities’ Applications for Authority to Transfer Transmission Control to SPP RTO

A. Commission Jurisdiction

SWEPCO, OG&E, and Empire seek permission to transfer operational control of their

transmission facilities to the SPP RTO.”

Ark. Code Ann. §23-3-102(c) provides:

The jurisdictional question is whether the three utilities will “transfer, in any manner,

control of electric transmission facilities.” The Commission finds that a transfer of control will

occur.

As explained in Empire’s Application (at pp.6-7), SPP will conduct the following

activities with respect to the utilities’ transmission facilities:

1. Scheduling authority over tariff facilities as defined in Section 1.17 of SPP Membership Agreement;

2. Determining the Available Transmission Capacity under the SPP OATT;

3. Coordinating transmission service with other regions;

4. Directing transmission construction under the coordinated planning criteria or under the SPP OATT;

5. Acting as a reliability coordinator;

I1 AECC is a jurisdictional transmission-dependent utility member of the SPP RTO. As such, it has no transmission and so no need to seek to transfer control. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 34 of 40

6. Directing control areas to maintain adequate reserves;

7. Directing the emergency response of any of SPP’s members, including the shedding of firm load;

8. Monitoring and coordinating voltage schedules;

9. Directing redispatch of generation in accordance with the SPP OATT;

10. Monitoring and coordinating transmission and generation maintenance schedules; and

11. Redirecting maintenance outage schedules for reliability reasons and providing compensation.

The Commission finds that many of these activities constitute “control” for purposes of Ark.

Code Ann. $23-3-102(c).

B. Summary of Utility Positions

On November 30, 2005, SWEPCO filed the Direct Testimonies of Michael Desselle and

C. Richard Ross. Mr. Desselle testified that the transfer of SWEPCO’s transmission facilities to the SPP RTO is in the public interest, given FERC’s finding that an RTO will limit opportunities for undue discrimination in transmission network access and improve the efficiency and reliability of the regional transmission network. Further, Mr. Desselle testified that the CRA

Study predicted a breakeven cost-benefit result for SWEPCO. Mr. Desselle also stated that

SWEPCO will continue to own, operate and maintain its transmission system with its existing employees; these employees will be responsible for the daily operation of the system; and they will continue to have the responsibility for planning, design, and construction of the lines.

SWEPCO Witness Ross addressed SWEPCO’s participation in SPP’s Energy Imbalance

Services Market. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 35 of 40

OG&E seeks approval to transfer to SPP RTO the authority to direct the day-to-day operations of facilities with high side voltage of 60 KV. OG&E further asserts that approving

OG&E’s participation in the SPP RTO is in the public interest because: (1) there will be greater cost benefits as an SPP RTO member rather than as a stand-alone transmission company; (2) membership in the SPP RTO will eliminate duplicative functions; and (3) FERC imposes greater burdens on transmission systems which are not members of an RTO. In support of its

Application, OG&E filed the Direct Testimony of Melvin H. Perkins on November 30,2005.

Empire’s Application states that the transfer of functional control is consistent with the

public interest because: (a) Empire does not anticipate any substantial change in the provisions of

retail electric service, including reliability; (b) the transfer will increase transmission system

reliability; and (c) the transfer will increase wholesale competition in generation. Empire also

points to the Cost Benefit Study. In support of its Application, Empire filed the testimony of its

witness Mr. Michael E. Palmer on November 30, 2005. Mr. Palmer testified, among other

things, that the approval it seeks is necessarily conditioned on the approval of all states in which

Empire operates. If any state commission disapproves the transfer, Empire will reevaluate its

continued participation in the SPP RTO.

C. Approval Subject to Conditions

The analysis of costs and benefits set forth in the section addressing SPP’s CCN applies

equally here. Since net benefits to Arkansas ratepayers will be realized by virtue of SWEPCO’s,

OG&E’s, and Empire’s participation in the SPP RTO, including the SPP EIS market, the

Commission will grant the applications filed in this consolidated docket, subject to the conditions

set forth below. These conditions are necessary to ensure that the favorable benefit-cost Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 36 of 40 relationship which is the factual foundation of our approval continues throughout the period of

SPP control of these utilities’ transmission assets.

1. Each utility shall track cost and revenue data related to its participation in the SPP

RTO and the SPP EIS market for three years, and keep corresponding data on the costs and

revenues it estimates it would have incurred and received had it continued to operate as a stand-

alone utility.

2. The approval granted by this Order lasts until revoked by the Commission.

Within 60 days after the third anniversary of the beginning of the EIS market, each utility shall

file an application with this Commission seeking continued participation as a member of the SPP

RTO. Based on the data collected under Condition #1 and other information, the Commission

will determine whether to: (a) permit the utility to continue its participation in SPP and its EIS

market, and, if so, under what conditions; or (b) require the utility to seek permission from FERC

to withdraw from the RTO, the EIS market, or both.

3. Each utility must report in a filing with the Commission whenever: (a) any

material variances in expected costs or benefits of participation in the SPP RTO and/or SPP EIS

market have occurred or are likely to occur (“material” meaning 10% variance from the levels

predicted in the CRA Study); or (b) any significant changes develop in FERC’s RTO policies,

FERC rules or regulations, SPP requirements, EIS market conditions, or other regulatory or

market structure component. This condition applies whenever the utility is aware of such

circumstances, regardless of whether a market monitor reports them.

4. All native load customers of each utility must retain their physical transmission

capacity rights. No utility may substitute LMP-based financial transmission rights for existing Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 37 of 40 physical transmission capacity, and all incremental transmission capacity must likewise be dedicated to native load customers in the same manner as the current physical capacity rights

allocation system.

5. Utilities must seek Commission approval to participate in any additional markets

beyond the EIS.

6. If a utility’s participation as a member of the SPP RTO is denied by any other

State, the utility shall notify this Commission within 30 days of the denial. Within 60 days after

the denial, the utility shall file with the Commission a study demonstrating the effect of that

denial on the costs and benefits to that utility’s Arkansas ratepayers. The Commission will

specify the format for this filing. Based on this submission, and any other information available,

the Commission will determine whether to terminate or modify the permission granted by this

Order.

7. Each utility must seek Commission approval before it files a request at FERC to

exit the SPP RTO.

8. Each transmission owner remains under the Commission’s jurisdiction with

respect to retail electric rates and all related electricity facility operations, facility siting,

financing, reliability, etc.

The Commission recognizes that decisions affecting some of these conditions fall within

the exclusive jurisdiction of FERC. In listing such conditions here, the Commission is not

intending to enter FERC’s exclusive domain. Acting within its own jurisdiction, however, this

Commission will consider whether to revoke or modify the permission granted by this Order,

should FERC exercise its jurisdiction in a manner which this Commission determines Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1, 2, 1, & 1 respectively Page 38 of 40 detrimental to the favorable benefit-cost relationship which is the factual foundation of the instant approval.

D. Utility Cost Recovery

Part 1I.C discussed the SPP policy of allocating 1/3 of transmission reliability (“Base

Plan”) upgrades on a regional basis, and 2/3 on a zonal basis, in correlation with the zones that benefit from the increased flows. Because some of these costs may not necessarily be for

Arkansas-sited facilities, several of the utilities cited uncertainty about whether this Commission will allow recovery of the costs allocated by SPP. OG&E suggested a generic docket to establish an accounting framework for these costs. Staff recommended against determining cost recovery methodologies in this docket. The Attorney General said a generic docket would be acceptable, but that cost recovery decisions were appropriate only in a rate case.

The Commission recognizes that the utilities are concerned about cost recovery.

However, the statutory provisions governing the instant dockets address the requirements for the

issuance of a CCN and the transfer of operational control of transmission facilities by the utilities

to the SPP. They do not require or address cost recovery issues. Cost recovery issues are

normally considered and ruled upon within the context of an application by a utility for a general

rate increase. Such decisions are based upon a number of considerations including, but not

limited to, whether specific expenditures are in the public interest and were otherwise prudently

incurred. Clearly, by this order the Commission has determined that it is in the public interest to

grant to the SPP a CCN and to authorize the utilities to transfer operational control of their

transmission facilities to the SPP. Further, the Commission acknowledges that upgrading

existing transmission facilities and/or the construction and operation of new transmission Dockets No. 04-137-U; 04-111-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 39 of 40 facilities is an integral function of the SPP in its reliability responsibility, its operational control over the transmission facilities of its member utilities, and its regional transmission planning responsibilities. The Commission also acknowledges that certain transmission upgrades and/or new construction within the service territories of utilities not subject to this Commission’s jurisdictional authority may serve the public interest of the ratepayers of this Commission’s jurisdictional utilities, particularly with respect to the enhanced access to more economic generation resource options. Accordingly, cost recovery of investments in such facilities by this

Commission’s jurisdictional utilities would be appropriate for consideration within the context of

utility-specific general rate increase applications before this Commission.

Also, as requested by some parties to the instant dockets, the Commission is willing to explore and consider other cost recovery options within the context of a generic proceeding.

However, such proceeding should only be initiated after all parties have engaged in a

comprehensive informal collaborative process in an effort to achieve common understanding and

agreement on how cost recovery might otherwise be addressed outside the context of a general rate case. The Commission will leave the initiation and conduct of such an informal collaborative process up to the parties to the instant dockets.

Therefore, having considered the applications pending in the instant dockets and the testimony offered in response thereto, the Commission directs and orders as follows:

1. SPP’s Application for a CCN is in the public interest and is hereby granted subject to

the conditions set forth hereinabove. Dockets No. 04-137-U; 04-1 11-U; 04-129-U; 04-143-U; 05-132-U Orders No. 6, 1,2, 1, & 1 respectively Page 40 of 40

2. The separate Applications of the utilities to transfer operational control of their

respective transmission facilities to the SPP are granted subject to the conditions set

forth hereinabove.

BY ORDER OF THE COMMISSION.

This 10th day of August, 2006.

L.izLLdSandra L. Hochstetter, Chairman

Daryl E. Bassett, Commissioner

GU+--yRandy Bynum, Comm sioner

Gcretary of the Commission