1. AEP PRESENTATION TO SPP MULTI-OWNER COMPENSATION TASK FORCE Presented July 8, 2004 Dallas, Texas

2. 2 Purpose of SPP MOCTF What does the MOCTF actually need to do?  FERC’s SPP RTO Orders Feb. 10 and July 2, 2004 only direct SPP to develop a timetable for resolution of the Compensation for Customer Owned Facilities.  “..we note that SPP and stakeholders are currently in the process of developing a single definition of transmission. …this issue will take time”  “We will direct SPP to submit the timetable as prescribed in the February 10 Order.” Source: SPP, 108 FERC ¶ 61,003 at P 65 and P 80 (2004).

3. 3 TDU facilities that are found to be transmission facilities, e.g., are integrated with the regional transmission system, providing benefits in terms capability and reliability to other customers, should qualify for cost recovery, from the customers who use and benefit from them, through the SPP regional OATT. AEP Position Re: Inclusion of TDU Facilities in Rates

4. 4 Introduction of Issues Historically, the fundamental principle in utility rate design has been that customers should bear the costs of facilities that are planned for their benefit, and used to provide them utility service(s). To the extent that other users provide revenue for incidental use, the costs borne by “planned service customers” are reduced. AEP’s rates to “planned service” customers, including ETEC, reflect credits for revenues received from others for incidental service. ETEC facilities were planned by ETEC to serve its REC members, and FERC has found that they provide no capability or reliability benefit to other AEP customers.

5. 5 Review of FERC Orders The Feb 10 SPP RTO Order The Integration Analysis: Although Lafayette criticized the Section 30.9 “integration” standard, the Commission noted that “integration” requirement with approval, and specifically referenced the Initial Decision in Consumers and the recent FP&L “credits” order. Source: SPP, 106 FERC ¶ 61,110 at P 114 (2004). The Seven Factor “Transmission” Test: The Commission pointed to the Wolverine decision, which applied the Seven Factor Test to determine whether facilities of multiple parties should be included in a single MISO transmission rate zone. Source: SPP, 106 FERC ¶ 61,110 at P 115 (2004).

6. 6 In Midwest ISO, the Commission applied the Seven Factor Test to determine whether facilities owned by Wolverine were eligible for consideration in a multiple-owner rate zone: 1. Local distribution facilities are normally in close proximity to retail customers. 2. Local distribution facilities are primarily radial in character. 3. Power flows into local distribution systems; it rarely, if ever, flows out. 4. When power enters a local distribution system, it is not re-consigned or transported on to some other market. 5. Power entering a local distribution system is consumed in a comparatively restricted geographical area. 6. Meters are based at the transmission/local distribution interface to measure flows into the local distribution system. 7. Local distribution systems will be of reduced voltage. Source: Midwest Independent Transmission System Operator, 101 FERC ¶ 61,004 (2002) and 106 FERC ¶ 61,219 (2004); Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,783-84 (1996) (subsequent history omitted). Review of FERC Orders Seven Factor “Transmission” Test

7. 7 Review of FERC Orders The Integration Analysis To receive credits, the customer must demonstrate:  That the facilities at issue are integrated into the plans and operations of the transmission provider to serve its customers.  That the transmission provider can and does use the facilities to provide transmission service to itself or other customers.  The facilities provide additional benefits to the transmission grid in terms of capability and reliability, and are relied upon for coordinated operation of the grid. Source: Consumers Energy Co., 86 FERC ¶ 63,004 at 65,016 (1999), aff’d, 98 FERC ¶ 61,333 (2002).

8. 8 Review of FERC Orders The Integration Analysis (Cont.) Interconnection “alone” is not enough:  The fact that the facilities serve a transmission function on the customer’s side of the interconnection point is not enough to prove integration.  The fact that a facility offers a parallel path and is subject to parallel flows does not require a conclusion that the line operates as part of an integrated network.  Unnecessary redundancy does not qualify facilities for credits. Source: Consumers Energy Co., 86 FERC ¶ 63,004 at 65,016 (1999), aff’d, 98 FERC ¶ 61,333 (2002).

9. 9 Incidental Loop Flow: “ FMPA argues... that the [looped] … line provides an alternate transmission path and increases reliability on the Florida Power system. The fact that the … line constitutes a parallel path and is subject to occasional loop flow does not, in and of itself, compel a conclusion that the line now operates as part of the Florida Power integrated transmission network. ” (FERC Order in FMPA II), emphasis added Review of FERC Orders Integration Analysis (Cont.)

10. 10 Review of FERC Orders The Mansfield Integration Test Five Tests for Facility Integration:  Whether the facilities are radial, or loop back into the transmission system  Whether energy flows only in one direction over the facilities, or in both directions  Whether the transmission provider furnishes transmission service to itself or other transmission customers over the facilities  Whether the facilities provide benefits to the transmission grid in terms of capability or reliability, and whether the facilities can be relied upon for the coordinated operation of the grid  Whether an outage of the facility would affect the transmission system Source: Mansfield Municipal Electric Dept. v. New England Power Co., 94 FERC ¶ 63,023 at 65,170, aff’d, 97 FERC ¶ 61,134 at 61,613-14 (2001).

11. 11 In order to determine whether facilities provide additional benefits to the transmission grid in terms of capability and reliability, the proper method is to look at the system as a whole in a base case load flow, and then compare this base case to a change case in which the facilities are not connected to the system. “Entergy performed a base case load flow study of its system under normal situations and contingency conditions. Then Entergy, examined how those same base and contingency case conditions would change if Entergy were not connected to the customer systems in question. The results showed that Entergy’s other wholesale and retail customers would not be negatively affected if the customer- owned facilities were not present.” Source: Entergy Services, Inc., 85 FERC ¶ 61,163 at 61,649 (1998). Emphasis added Review of FERC Orders Re: Capability & Reliability Benefits

12. 12 On October 29, 1999, in East Texas Electric Cooperative, Inc. v. Central and South West Services, Inc., 89 FERC ¶ 63,005 (1999), exceptions pending, a FERC Administrative Law Judge ruled that the facilities of ETEC are not integrated with the facilities of the AEP operating companies under Section 30.9 of the AEP OATT. Because the "integration" of ETEC's facilities has been squarely presented to the Commission, the Multi-Owner Compensation Task Force need not address the "integration" question with regard to ETEC's facilities until after a final order is issued in ETEC v. CSW. Review of FERC Orders The ETEC v. CSW Initial Decision

13. 13 Review of FERC Orders Other Statements on Integration In Docket No. ER99-4392, FERC denied ETEX’s claim that their facilities should constitute an SPP pricing zone because their facilities “are used solely to distribute power to their distribution members, do not provide any benefits to SPP in terms of additional capability and reliability, are not relied upon for the coordinated operation of the grid, and are not integrated with any SPP transmission provider[.]” SPP, 98 FERC ¶ 61,038 (2002) On appeal, the court upheld the use of the “integration” standard, but remanded for further evidence on whether the Texas Cooperatives satisfied this integration standard.

14. 14 FERC explained to the court that the integration standard involves “‘application of a fundamental ratemaking principle: that cost responsibility should match cost and benefit’ and ‘parties should not be required to pay the costs of facilities or services unless they actually receive some benefit from them.’” ETEC v. FERC, 331 F.3d 131, 136 (D.C.Cir. 2003) (quoting FERC Brief at 2). The court concluded that this integration standard was consistent with the SPP OATT’s standard for customer credits found in Section 30.9. ETEC v. FERC, 331 F.3d at 137. This court remand is pending before the FERC. Review of FERC Orders Add’l. Statements on Integration

15. 15 The ETEX RECs are wholesale customers of (not suppliers to) SWEPCO Most ETEX REC lines are radial circuits ETEC’s 138 kV line from Crockett Station tying to Rayburn Country’s Mineola – Overton line at Jacksonville Station, does not provide benefits in terms of capability and reliability to other SWEPCO customers.  There is no generation connected to the line or behind any of the delivery points along the line  No SWEPCO lines connect into Jacksonville Station Function of ETEC’s Lines

16. 16 Function of ETEC Lines ETEC Crockett-Jacksonville Line

17. 17 Transmission Contingency Analysis  NERC [n-1] contingency load flow analysis shows that SWEPCO is not dependent upon the Crocket-Jacksonville 138 kV line to meet transmission reliability criteria for other customers.  The energy that flows from AEP into the ETEC 138 kV line at Crockett Station rarely flows back to SWEPCO, and even then SWEPCO’s other customers would not be harmed if such flow was prevented. Many of ETEC’s lines, are “Economic Upgrades,” as that term is used in SPP Participant Funding discussions, that were built to move their load from ERCOT to SPP to obtain the economic benefit of lower energy costs in SPP. Function of ETEC’s Lines

18. 18 ETEX claims annual revenue requirement (ARR) of $8.9 million for facilities > 60 kV in SPP. Impact on AEP Network Transmission customers sharing the present AEP SPP TCOS by 12 CP load ratios. Cost Shifts with inclusion of ETEX Facilities in AEP Zone ** Cust. AEP TCOS ETEX ARR Cost Shift AEP NTS NTS  % NTS80.68.1 88.710.1 ETEX 8.10.8(8.1) 0.0(100) Total88.78.9----88.7----

19. 19 TDU facilities that are found to be transmission facilities, e.g., are integrated with the regional transmission system, providing benefits in terms capability and reliability to other customers, should qualify for cost recovery, from the customers who use and benefit from them, through the SPP regional OATT. AEP Position Re: Inclusion of TDU Facilities in Rates

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