ATTACHMENT A clean copy of the revised tariff sheets (Exhibit No. AEP102A)

Exhibit No. AEP 102A Page 1 of 44 Southwest Power Pool pro forma Third Revised Sheet No. 94 FERC Electric Tariff Superseding Second Revised Sheet No. 94 SCHEDULE 1 Scheduling, System Control And Dispatch Service Scheduling, System Control and Dispatch Service is required to schedule the movement of power through, out of, within or into a Control Area. Charges for such service shall be as follows: 1) For Customers taking Firm or NonFirm PointToPoint Transmission Service, for through and out transactions, the Schedule 1 charge shall be the product of the capacity reserved, expressed in MW and the appropriate rate as follows: OnPeak: Off Peak: Monthly Rate $ 59.2979 per MWMonth Weekly Rate $13.6841 per MWWeek (The Monthly Rate times 12, divided by 52) Daily Rate $2.7368 per MWDay (The Monthly Rate times 12, divided by 260) Hourly Rate $0.1711 per MWHour (The Monthly Rate times 12, divided by 4160) Daily Rate/MW $1.9495 per MWDay (The Monthly Rate times 12, divided by 365) Hourly Rate/MW $0.1711 per MWHour (The Monthly Rate times 12, divided by 8760) OnPeak and OffPeak Periods OffPeak days shall be Saturdays and Sundays and all NERC holidays. All other days shall be OnPeak. All hours during OffPeak days shall be OffPeak. OnPeak hours during OnPeak days shall be all hours from HE 0700 through HE 2200 Central Prevailing Time. All other hours during OnPeak days shall be OffPeak. 2) For Customers taking Firm or NonFirm PointToPoint Transmission Service, for transactions into and within the Transmission System, the Schedule 1 charge shall be the charge computed pursuant to the approved rate schedule of the Zone that is the Point of Delivery. See Addendum 1 to this Schedule 1 for Zone 1 charges. 3) For Customers taking Network Integration Transmission Service, the Schedule 1 charge shall be the charge computed pursuant to the approved rate schedule of the Zone in which the load is located. See Addendum 1 to this Schedule 1 for Zone 1 charges. Issued by: L. Patrick Bourne, Director Issued on: Effective

Exhibit No. AEP 102A Page 2 of 44 Southwest Power Pool pro forma Second Revised Sheet No. 96 FERC Electric Tariff Superseding First Revised Sheet No. 96 ADDENDUM 1 TO SCHEDULE 1 Revenue Requirements for the Allocation of Through And Out Transaction Revenue Revenue associated with the provision of Schedule 1 service for Customers taking Firm or Non Firm PointToPoint Transmission Service for through and out transactions, shall be allocated to Transmission Owners in proportion to the respective scheduling revenue requirement of each such Transmission Owner associated with the provision of this service. Such scheduling revenue requirements are: Transmission Owner CURRENTLY EFFECTIVE Revenue Requirement AEP $3,257,073 Aquila MPS $1,620,559 Aquila WPK $594,828 Empire $260,944 GRDA $686,880 KCPL $0 Midwest $190,804 OG+E $4,759,216 SPA $1,622,827 Springfield $0 SPS $1,674,015 Westar $3,209,760 WFEC $1,824,120 Total $19,355,553 Zone 1 charges for Scheduling, System Control and Dispatch Service: (a) Network Integration Transmission Service: $34.55 per MW of Network Load per month. (b) PointtoPoint Transmission Service per MW reserved per: Month Week Day Hour $34.55 $7.97 $1.14 $0.05 Issued by: L. Patrick Bourne, Manager Issued on: Effective:

Exhibit No. AEP 102A Page 3 of 44 Southwest Power Pool pro forma Ninth Revised Sheet No. 161 FERC Electric Tariff Superseding Eighth Revised Sheet No. 161 ATTACHMENT H Annual Transmission Revenue Requirement For Network Integration Transmission Service 1. The Existing Zonal Annual Transmission Revenue Requirement within each Zone for (1) Zone 1 purposes of determining the charges under Schedule 9, Network Integration Transmission Service, is specified in column 3. The Base Plan Zonal Annual Transmission Revenue Requirement within each Zone for the purposes of determining the zonal charges under Schedule 11, Base Plan Charges, is specified in column 4. (2) (3) Existing Zonal ATRR American Electric Power (Public Service Company of Oklahoma, and Southwestern Electric Power Company, collectively AEP ) See Section 7 below (4) Base Plan Zonal ATRR 1 East Texas Electric Cooperative, Inc. $2,733,879 $0 1 TexLa Electric Cooperative of Texas, Inc. $588,874 $0 1 Deep East Texas Electric Cooperative, Inc. $428,131 $0 2 Cleco Corporation $ 29,328,000 $0 3 City Utilities of Springfield, Missouri $ 8,651,509 $0 4 Empire District Electric Company $ 14,075,000 $0 5 Grand River Dam Authority (Est.) $ 24,589,256 $0 6 Kansas City Power & Light Company $ 35,461,776 $0 7 Oklahoma Gas & Electric Company $ 65,065,032 $0 8 Midwest Energy, Inc. $ 4,197,347 $0 9 Aquila NetworksMPS/L&P $ 20,759,283 $0 9a Aquila NetworksMPS $14,059,183 $0 9b Aquila NetworksL&P $6,700,100 $0 10 Southwestern Power Administration $9,155,900 $0 11 Southwestern Public Service $65,500,000 $0 12 Sunflower Electric Corporation $ 14,484,045 $0 13 Western Farmers Electric Cooperative $ 20,719,639 $0 Westar Energy, Inc. (Kansas Gas & Electric and See section 5 14 $0 Westar Energy) below 15 Aquila NetworksWPK $ 5,947,002 $0 $ Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 4 of 44 pro forma Seventh Revised Sheet No. 161A Superseding Substitute Sixth Revised Sheet No. 161A 2. The Base Plan Regionwide Annual Transmission Revenue Requirement for the purposes of determining the regionwide charges under Schedule 11 shall initially be $0. 3. The amounts in (1) and (2) shall be effective until amended by the Transmission Owner or modified by the Commission or other applicable regulatory authority. 4. The revenue requirements stated in Attachment H shall not be changed absent a filing with the Commission. 5. The Annual Transmission Revenue Requirement for purposes of the Network Integration Transmission Service shall be calculated using the rate formula set forth in Attachment H1 of the Westar Open Access Transmission Tariff (Westar formula rate). The results of the formula calculation shall be posted on the SPP website and in an accessible location on Westar s OASIS website by May 15 of each calendar year and shall be effective on June 1 of such year. The Annual Transmission Revenue Requirement will be as identified on page 1, line 7 of the Westar formula rate, plus the previous calendar year s total firm PointtoPoint transmission revenue allocated to Westar under Attachment L provided such PointtoPoint transmission revenue is deducted from Westar s Annual Transmission Revenue Requirement under Section 34.1. 6. Pursuant to the Offer of Settlement approved by the Federal Energy Regulatory Commission in Xcel Energy Services Inc., 115 FERC 61,011, the Annual Transmission Reveune Requirement for the Southwestern Public Service Company (SPS) rate zone (Zone 11) stated on Sheet 161 shall not be subject to adjustment pursuant to section 34.1 for the previous calendar year s total firm PointtoPoint transmission revenue allocated to SPS under Attachment L when determining the monthly zonal Demand Charge for Zone 11. 7. The AEP Annual Transmission Revenue Requirement for purposes of the Network Integration Transmission Service shall be (i) calculated using the formula rate set forth in Addendum 1 to this Attachment H, (ii) posted on the SPP website by May 25 of each calendar year, and (iii) effective on July 1 of such year. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 5 of 44 pro forma Second Revised Sheet No. 161B Superseding First Revised Sheet No. 161B ADDENDUM 1 TO ATTACHMENT H MONTHLY DEMAND CHARGE CALCULATION FOR ZONE 1 NETWORK INTEGRATION TRANSMISSION SERVICE This Addendum to Attachment H sets forth the monthly Demand Charge for Zone 1 for Network Customers taking Network Integration Transmission Service under Schedule 9 to this Tariff. Charges for Compensation to AEP The monthly Demand Charge to Network Customers for compensation to AEP shall be determined by multiplying one twelfth (1/12) of the Existing Zonal ATRR for AEP, specified in Attachment H, by the Network Customer s monthly Network Load, determined in accordance with the provisions of Section 34.2, expressed in MW, divided by the total monthly Network Load for Zone 1. The total monthly Network Load shall be adjusted as necessary to incorporate the load of Network Integration Transmission Service Customers, and any zonal load served under grandfathered network and longterm firm pointtopoint service agreements. Charges for Compensation to East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. In addition to the charges specified for compensation to AEP above, the Transmission Provider shall calculate a monthly Demand Charge associated with the revenue requirements of East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. which shall be applicable to all customers located in Zone 1 taking Network Service under this tariff, including any Transmission Owner within Zone 1 taking service under Section 39. The monthly charge to each customer for compensation to East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. shall be the product of the customer s load ratio share and one twelfth (1/12) of such Transmission Owner s Existing Zonal Annual Transmission Revenue Requirement. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 6 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.1 FERC Electric Tariff I. Annual Update AEP Formula Rate Implementation Protocols 1. The rate formula template ( Formula ) and these protocols together comprise the filed rate of Public Service Company of Oklahoma and Southwestern Electric Power Company (collectively, AEP ) for transmission service under the SPP OATT. AEP must follow the instructions specified in the Formula to calculate its Annual Transmission Revenue Requirements ( ATRR ) and the rates for its Network Integration Transmission Service and PointtoPoint transmission service ( Formula Rate ). 2. The Formula Rate shall initially be effective for service on and after the date specified by the Federal Energy Regulatory Commission ( FERC ) in an order accepting the Formula Rate, and in subsequent years on and after July 1 of each calendar year through June 30 of the subsequent calendar year ( Rate Year ), subject to review, challenge and refunds or surcharges with interest, to the extent provided herein. 3. On or before May 25 of each calendar year, AEP shall: (a) (b) (c) (d) recalculate the ATRR and the Formula Rate for the new Rate Year in accordance with the Formula Rate ( Annual Update ); provide such Annual Update and supporting information in readonly format to SPP, for posting on the SPP website, such information to include a populated Formula showing the calculation of such Annual Update and documentation supporting such calculation as provided in Section I.4 below (the date of such posting to be the Posting Date ); disclose any changes in AEP accounting policies, practices or procedures that impact the Formula or calculations under the Formula that have occurred since the initial filing of the Formula or posting of the most recent Annual Update, as applicable; and notify its transmission customers and affected regulatory commissions of the Annual Update posting, and provide, upon request, fully functioning spreadsheet files supporting the Annual Update. 4. The Annual Update for the Rate Year shall: (a) (b) be based upon AEP s FERC Forms No. 1 for the most recent calendar year, and, to the extent specified in the Formula, upon the books and records of AEP consistent with the FERC accounting policies and practices ( Prior Year ATRR ); include adjustments reflecting the additional transmission plant in service, and related depreciation, and income taxes that are reasonably projected to be Issued by: Issued on: L. Patrick Bourne, Director Effective:

Exhibit No. AEP 102A Page 7 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.2 FERC Electric Tariff recorded upon the books and records of AEP consistent with the Formula and FERC accounting policies and practices, so as to estimate the ATRR as of the current calendar year end ( Projected ATRR ); (c) (d) (d) as and to the extent specified in the Formula, provide sufficiently detailed supporting documentation for data (and all adjustments thereto or allocations thereof) that are used to develop the Formula Rate and are not otherwise available directly from the FERC Form No. 1; beginning in the second year, compare the latest Prior Year ATRR with the Projected ATRR calculated in the prior year s Annual Update, thereby to determine the amount needed to be surcharged or refunded to customers in the new Rate Year to true up collections for the soon to end Rate Year, including interest at the applicable FERC refund interest rates; and be subject to review only in accordance with the procedures set forth in these Formula Rate Review Protocols ( Protocol ). 5. A change to the Formula inputs related to revised return on equity financing ( ROE ), depreciation rates or PostEmployment Benefits Other than Pensions ( PBOP ) expenses may not be made absent an appropriate filing with the FERC pursuant to Federal Power Act Section 205 or Section 206. 6. If AEP files any corrections to its FERC Forms No. 1 during a Rate Year that would affect the Formula Rate for that Rate Year, such corrections and any resulting refunds or surcharges shall be reflected in the true up adjustment made part of the Annual Update for the next effective Rate Year. II. Review Procedures for Annual Update 1. Each Annual Update shall be subject to the following review procedures ( Annual Review Procedures ): (a) Each year, after the Posting Date and before June 25, AEP will convene a meeting ( Customer Meeting ) to afford interested parties (e.g., Transmission Customers and affected state and federal regulatory authorities) an opportunity to discuss and become better informed regarding the Annual Update; Issued by: Issued on: L. Patrick Bourne, Manager, Effective:

Exhibit No. AEP 102A Page 8 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.3 FERC Electric Tariff (b) (c) (d) (e) Interested parties will have seventyfive (75) days after the Customer Meeting to serve reasonable information requests on AEP for information and workpapers supporting an Annual Update. Such information requests shall be limited to that which is necessary to determine if AEP has properly calculated the Annual Update under review (including any corrections pursuant to Section I.6). Further, such information requests shall not include requests for information related to Annual Updates from prior years except (i) to determine whether a prior year s approach on a given matter was the same or different from the current year s approach, or (ii) in connection with corrections pursuant to Section I.6. AEP shall make a good faith effort to respond to information requests pertaining to an Annual Update within fifteen (15) business days of receipt of such requests. Information requests received after 4 p.m. CPT shall be considered received the next business day. To the extent AEP and any interested party(ies) are unable to resolve disputes related to information requests submitted in accordance with these Annual Review Procedures, AEP or any interested party may petition the FERC to appoint an Administrative Law Judge as a discovery master. The discovery master shall have the power to issue binding orders to resolve discovery disputes and compel the production of discovery, as appropriate, in accordance with the Annual Review Procedures and consistent with the FERC s discovery rules. Any interested party shall have until the later of ninety (90) days after the Customer Meeting or fifteen (15) days after AEP s last response to reasonable information requests submitted pursuant to Section II.1(b) above, to review the calculation of the Annual Update ( Review Period ) and to notify AEP in writing of any specific challenges to the Annual Update ( Issues ). Challenges to the Formula itself shall not be considered Issues for purposes of these Annual Review Procedures. III. Resolution of Challenges For each Annual Update: 1. If AEP and any interested party(ies) have not resolved all Issues identified pursuant to Section II.1(e) above within sixty (60) days after the Review Period for a given Annual Update, the interested party(ies) may file a complaint challenging the Annual Update, with regard to such Issue(s), in a proceeding at the FERC ( Formal Challenge ). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 9 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.4 FERC Electric Tariff (a) A party may file a Formal Challenge for a limited period of up to three (3) months after the sixtyday resolution period has ended. A party may not, thereafter, file a Formal Challenge as to the disputed Issue(s) for the then effective Rate Year. Failure to pursue an Issue or lodge a Formal Challenge regarding an Issue(s) as to a given Annual Update shall not bar pursuit of such Issue or the lodging of a Formal Challenge as to such Issue(s) as relates to a subsequent Annual Update review. (b) All information produced pursuant to these Protocols may be included in any Formal Challenge. 2. In any proceeding ordered by the FERC in response to a Formal Challenge, AEP will bear the burden of proving that it has properly calculated the challenged Annual Update pursuant to the Formula. Challenges to the Formula itself shall not be considered Formal Challenges for purposes of these Annual Review Procedures, and shall be subject to the Commission s Rules and Regulations applicable to filings pursuant to 18 C.F.R. 385.206. 3. Each Annual Update shall become final and shall no longer be subject to challenge on the later to occur of: (i) passage of the time specified in III.1(a) above for a Formal Challenge, if no such Formal Challenge has been filed and the FERC has not itself initiated a proceeding to consider the Annual Update; or (ii) the issuance of a final FERC order in response to a Formal Challenge or a proceeding initiated by the FERC to consider the Annual Update. 4. Any refunds or surcharges resulting from a Formal Challenge shall be calculated, with interest, from the effective date of the challenged Annual Update, and shall be reflected in the Annual Update for the next effective Rate Year. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Issued by: L. Patrick Bourne, Director Issued on: Effective:.. AEP Transmission Formula Rate Template For rates effective July 1, Attachment H & T Support Page 1 of 1 SPP Zone 1 AEP Revenue Requirements AEP Annual PSO Annual SWEPCO Annual Line Revenue Revenue Revenue No. Requirement Requirement Requirement A. Network Service 1 REVENUE REQUIREMENT (w/o incentives) (TCOS Line 1 ) 2 LESS: REVENUE CREDITS (TCOS Line 5 ) 3 CURRENT YEAR ZONE 1 AEP NETWORK SERVICE REVENUE REQUIREMENT (TCOS Line 6 ) 4 LESS: REVENUE REQUIREMENTS INCLUDED IN LINE 1 FOR: 5 BASE PLAN UPGRADES (W/O INCENTIVES) (TCOS Line 7 ) 6 REQUESTED UPGRADES (W/O INCENTIVES) (Worksheet F) 7 ECONOMIC UPGRADES (W/O INCENTIVES) (Worksheet F) 8 SUBTOTAL 9 EXISTING ZONAL ATRR (W/O INCENTIVES) (Line 3 Line 8) 10 INCENTIVE REVENUE REQUIREMENT FOR ZONAL PROJECTS (TCOS ln 16) 11 EXISTING ZONAL ATRR (W/ INCENTIVES) (Line 9 + Line 10) 12 HISTORICAL YEAR (2006) ACTUAL ATRR 13 PROJECTED (2006) ATRR FROM PRIOR YEAR Input from Prior Year 14 PRIOR YEAR TRUEUP (Line 12 Line 13) 15 INTEREST ON PRIOR YEAR TRUE UP 16 EXISTING ZONAL ATRR FOR SPP OATT ATTACHMENT H, SEC. 1, COL. 3 (Ln 11 + Ln 14 + Ln 15) B. PointtoPoint Service 17 2007 Projected AEP West Zone SPP Average 12Mo. Peak Demand (Load WS, ln 11) MW 18 Annual PointtoPoint Rate in $/MW Year (Line 16 / Line 17) 19 Monthly PointtoPoint Rate in $/MW Month (Line 18 / 12) 20 Weekly PointtoPoint Rate in $/MW Weekly (Line 19 / 52) 21 Daily OnPeak PointtoPoint Rate in $/MW Day (Line 20 / 260) 22 Daily OffPeak PointtoPoint Rate in $/MW Day (Line 21 / 365) 23 Hourly OnPeak PointtoPoint Rate in $/MW Hour (Line 22 / 4160) 24 Hourly OffPeak PointtoPoint Rate in $/MW Hour (Line 23 / 8760) C. SPP Regional Service 25 BASE PLAN UPGRADE ATRR W/O INCENTIVES (Line 8) 26 ADDITIONAL ATRR FOR FERCAPPROVED INCENTIVES ON BPU (Worksheet G) 27 BASE PLAN UPGRADE ATRR FOR SPP COLLECTION UNDER SCHEDULE 11 Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.1 Exhibit No. AEP 102A Page 10 of 44

Issued by: L. Patrick Bourne, Director Issued on: Effective: AEP Transmission Formula Rate Template For rates effective July 1, Schedule 1 Support Page 1 of 1 SPP SCHEDULE 1 AEP Revenue Requirements AEP Annual PSO Annual SWEPCO Annual Line Revenue Revenue Revenue No. Requirement Requirement Requirement A. Schedule 1 ARR 1 Total Load Dispatch & Scheduling (Account 561) (TCOS Line 76) 2 Less: Load Disptach Scheduling, System Control and Dispatch Services (321.88.b) 3 Less: Load Disptach Reliability, Planning & Standards Development Services (321.92.6) 4 Total 561 Internally Developed Costs (Line 1Line 2Line 3) 5 Less: PTP Service Credit 6 EXISTING ZONAL ARR (Line 4 Line 5) 7 HISTORICAL YEAR (2006) ACTUAL ARR 8 PROJECTED (2006) ARR FROM PRIOR YEAR 9 PRIOR YEAR TRUEUP 10 INTEREST ON PRIOR YEAR TRUE UP 11 Net Schedule 1 Revenue Requirement for Zone B. Schedule 1 Rate Calculations 12 2007 Projected AEP West Zone SPP Average 12Mo. Peak Demand (LOAD WS, Line 11) MW 13 Annual PointtoPoint Rate in $/MW Year (Line 11 / Line 12) 14 Monthly PointtoPoint Rate (ln 13 / 12) $/MW Month (Line 13 / 12) 15 Weekly PointtoPoint Rate (ln 13 / 52) $/MW Weekly (Line 13 / 52) 16 Daily OffPeak PointtoPoint Rate (ln 13 / 365) $/MW Day (Line 13 / 365) 17 Hourly OffPeak PointtoPoint Rate (ln 13 / 8760) $/MW Hour (Line 13 / 8760) Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.2 Exhibit No. AEP 102A Page 11 of 44

Issued by: L. Patrick Bourne, Director Issued on: Effective: AEP Companies: PSO and SWEPCO Network Load for January Through December, Based on West ZoneSPP Monthly Transmission System Firm Peak Demands (1) for the Twelve Months Ended December 31, Projected Combined Load Worksheet Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Peak Day 12 Month Line Peak Hour *projected *projected *projected *projected *projected *projected *projected *projected Average MW No. SPP Load Responsibility 1 PSO 2 SWEPCO 3 TNCN 4 OMPA 5 NTEC 6 ETEC 7 TEXLA 8 Greenbelt 9 Lighthouse 10 Coffeyville, KS (OATT Firm PTP) (2) 11 Zone 1 System Firm Peak Demands Historical Combined Load Worksheet Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Peak Day 12 Month Line Peak Hour Average MW No. SPP Load Responsibility 12 PSO 13 SWEPCO 14 TNCN 15 OMPA 16 NTEC 17 ETEC 18 TEXLA 19 Greenbelt 20 Lighthouse 21 Coffeyville, KS (OATT Firm PTP) (2) 22 Zone 1 System Firm Peak Demands Supporting Data 23 PSO: PSO Native Load 24 KAMO 25 WFEC 26 PSO Load Responsibility 27 SWEPCO: SWEPCO Native Load 28 Less: NTEC 29 Less: ETEC 30 Less: TEXLA 31 AECC 32 LaGen (Formerly Cajun) 33 Lafayette 34 Dolet Hills Aux. Load (not selfgenerated 35 SWEPCO Load Responsibility 36 TNC TNC North Native Load 37 TNC North Load Responsibility 38 Coffeyville Actual Load (2) Notes: (1) MW, at the time of the AEPSPP Native Peak. At the generator. Transmission losses added to metered values which include appropriate dist.& xfmr losses. (2) Net load from East and West Coffeyville ties, not included in AEP Control Area. Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.3 Exhibit No. AEP 102A Page 12 of 44

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 13 of 44 pro forma Original Sheet No. 161D.4 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 1 of 10 Plus Capital Additions for PROJECTED Company: Line No. 1 REVENUE REQUIREMENT (w/o incentives) (ln 128) Transmission Amount 2 REVENUE CREDITS (Note A) Total Allocator 3 Transmission Credits (Worksheet A) DA 4 Assoc. Business Development (Worksheet A) DA 5 Total Revenue Credits 6 REVENUE REQUIREMENT (w/o incentives) For All AEP Facilities (ln 1 less ln 5) 7 Revenue Requirement for SPP Base Plan Upgrades (w/o incentives) (Worksheet G) DA 8 REVENUE REQUIREMENT EXCLUDING BASE PLAN UPGRADE ATRR (ln 6 less ln 7) 9 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 10 Annual Rate (ln 6 / ln 42 x 100) 11 Monthly Rate (ln 10 / 12) 12 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 13 Annual Rate ( (ln 6 ln 98) / ln 42 x 100) 14 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 15 Annual Rate ( (ln 6 ln 98 ln 122 ln 123) / ln 42 x 100) 16 ADDITIONAL REVENUE REQUIREMENT for projects w/ incentive ROE's (Note C) (Worksheet F) NA 17 PROJECTED YE 2007 TRANSMISSION REVENUE REQUIREMENT (ln 8 + ln 16) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 2 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 102A Page 14 of 44 pro forma Original Sheet No. 161D.5 Company: (1) (2) (3) (4) (5) Data Sources Total RATE BASE CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. GROSS PLANT IN SERVICE 18 Production 205.46.g NA 19 Transmission 207.58.g DA 20 Plus: Transmission PlantinService Additions (Worksheet H) DA 21 Plus: Additional Trans Plant on Transferred Assets (Worksheet H) DA 22 Distribution 207.75.g NA 23 General Plant 207.99.g (Note K) W/S 24 Intangible Plant 205.5.g W/S 25 Common 356 CE 26 TOTAL GROSS PLANT (sum lns 18 to 25) GP(p)= GTD(p)= 27 ACCUMULATED DEPRECIATION AND AMORTIZATION 28 Production 219.2024.c NA 29 Transmission 219.25.c TP1= 30 Plus: Transmission PlantinService Additions (Worksheet H) DA 31 Plus: Additional Projected Deprec on Transferred Assets (Worksheet H) DA 32 Plus: Additional Transmission Depreciation for 2007 (ln 98) TP1 33 Plus: Additional General & Intangible Depreciation for 2007 (ln 100 + ln 101) W/S 34 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) DA 35 Distribution 219.26.c NA 36 General Plant 219.28.c (Note K) W/S 37 Intangible Plant 219 W/S 38 Common 356 CE 39 TOTAL ACCUMULATED DEPRECIATION (sum lns 28 to 38) 40 NET PLANT IN SERVICE 41 Production (ln 18 ln 28) 42 Transmission (ln 19 ln 29) 43 Plus: Transmission PlantinService Additions (ln 20 ln 30) 44 Plus: Additional Trans Plant on Transferred Assets (ln 21 ln 31) 45 Plus: Additional Transmission Depreciation for 2007 (ln 32) 46 Plus: Additional General & Intangible Depreciation for 2007 (ln 33) 47 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) (ln 34) 48 Distribution (ln 22 ln 35) 49 General Plant (ln 23 ln 36) 50 Intangible Plant (ln 24 ln 37) 51 Common (ln 25 ln 38) 52 TOTAL NET PLANT IN SERVICE (sum lns 41 to 51) NP(p)= 53 ADJUSTMENTS TO RATE BASE (Note D) 54 Account No. 281 (enter negative) 273.8.k (Worksheet C) DA 55 Account No. 282 (enter negative) 275.2.k (Worksheet C) DA 56 Account No. 283 (enter negative) 277.9.k (Worksheet C) DA 57 Account No. 190 234.8.c (Worksheet C) DA 58 Account No. 255 (enter negative) 267.8.h (Worksheet C) DA 59 Account 107 for Approved MultiYear Projects 216.43.b (Worksheet K) DA 60 Other Additions/Deductions (Note E) DA 61 TOTAL ADJUSTMENTS (sum lns 54 to 60) 62 PLANT HELD FOR FUTURE USE 214.x.d (Note F) DA 63 WORKING CAPITAL (Note G) 64 Cash Working Capital (1/8 * ln 96) 65 Transmission Materials & Supplies 227.8.c TP 66 A&G Materials & Supplies 227.11.c W/S 67 Undistributed Stores Expense (Acct 163) 227.16.c GP(h) 68 Prepayments (Account 165) Labor Allocated 111.57.c (Worksheet I) W/S 69 Prepayments (Account 165) Direct Allocated 111.57.c (Worksheet I) DA 70 Prepayments (Account 165) Gross Plant 111.57.c (Worksheet I) GP(h) 71 TOTAL WORKING CAPITAL (sum lns 64 to 70) 72 IPP CONTRIBUTIONS FOR CONSTRUCTION #REF! DA 73 RATE BASE (sum lns 52, 61, 62, 71, 72) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 3 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 102A Page 15 of 44 pro forma Original Sheet No. 161D.6 Company: (1) (2) (3) (4) (5) EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. OPERATION & MAINTENANCE EXPENSE 74 Transmission 321.112.b TP 75 Less: expenses 100% assigned to TO billed customers (Worksheet E, ln 14) DA 76 Less: Total Account 561 (Load Dispatch Sch 1) (Note I) 321.8492.b TP 77 Less: Account 565 321.96.b (Note J) TP 78 Plus: Acct 565 native load, zonal or pool (Note J) DA 79 Transmission Subtotal (lns 74757677+78) 80 Administrative and General 323.197.b (Note K) 81 Less: Acc. 928, Reg. Com. Exp. 323.189.b 82 Acct. 930.1, Gen. Advert. Exp. 323.191.b 83 Acc. 924, Property Insurance 323.185.b 84 Acc. 930.2, Misc. Gen. Exp. 323.192.b 85 Acc. 935, Maint. of Gen. Plant 323.196.b W/S 86 Balance of A & G (ln 80 sum ln 81 to ln 85) W/S 87 Plus: Acct. 924, Property Insurance (ln 83) NP(h) 88 Acct. 928 Transmission Specific (Note L) (Worksheet D) TP 89 Acct. 928 Transmission Allocated (Note L) (Worksheet D) GP(h) 90 Acct 930.1 Only safety related ads. (Note L) (Worksheet D) W/S 91 Acct 930.2 Misc Gen. Exp. Trans (Worksheet D) TP 92 Acct 930.2 Misc Gen. Exp. Allocated (Worksheet D) W/S 93 A & G Subtotal (sum lns 84 to 90) 94 Common 356 CE 95 Transmission Lease Payments DA 96 TOTAL O & M EXPENSE (ln 79 + ln 93 + ln 94 + ln 95) 97 DEPRECIATION AND AMORTIZATION EXPENSE 98 Transmission 336.7.f TP 99 Plus: Transmission PlantinService Additions (Worksheet H) DA 100 General 336.10.f W/S 101 Intangible 336.1.f W/S 102 Common 336.11.f CE 103 TOTAL DEPRECIATION AND AMORTIZATIN (sum lns 98 to 102) 104 TAXES OTHER THAN INCOME (Note M) 105 Labor Related 106 Payroll 262.x263.x.i W/S 107 Plant Related 108 Property 262.x263.x.i NP(h) 109 Gross Receipts/Sales & Use 262.x263.x.i NA 110 Other 262.x263.x.i GP(h) 111 Payments in lieu of taxes GP(h) 112 TOTAL OTHER TAXES 114.14.c 113 INCOME TAXES (Note N) 114 T=1 {[(1 SIT) * (1 FIT)] / (1 SIT * FIT * p)} = 115 EIT=(T/(1T)) * (1(WCLTD/WACC)) = 116 where WCLTD=(ln 158) and WACC = (ln 161) 117 and FIT, SIT & p are as given in Note N. 118 GRCF=1 / (1 T) = (from ln 114) 119 Amortized Investment Tax Credit (enter negative) 120 Income Tax Calculation (ln 115 * ln 123) 121 ITC adjustment (ln 118 * ln 119) NP(h) 122 TOTAL INCOME TAXES (sum lns 120 to 121) 123 RETURN ON RATE BASE (Rate Base*WACC) (ln 73 * ln 161) 124 INTEREST ON IPP CONTRIBUTION FOR CONST. (Note H) (Worksheet B, ln 16) DA 125 REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX 126 (sum lns 96, 103, 112, 122, 123, 124) 127 TEXAS GROSS MARGIN TAX (NOTE O) (Worksheet J) DA 128 REVENUE REQUIREMENT INCLUDING GROSS MARGIN TAX Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 4 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 102A Page 16 of 44 pro forma Original Sheet No. 161D.7 Company: SUPPORTING CALCULATIONS ln No. TRANSMISSION PLANT INCLUDED IN SPP TARIFF 129 Total transmission plant (ln 19 + ln 20 + ln 21) 130 Less transmission plant excluded from SPP Tariff (Note P) 131 Less transmission plant included in OATT Ancillary Services (Note Q ) (Worksheet L) 132 Transmission plant included in SPP Tariff (ln 129 ln 130 ln 131) 133 Percent of transmission plant in SPP Tariff (ln 132 / ln 129) TP= 134 WAGES & SALARY ALLOCATOR (W/S) (Note R) Direct Payroll Payroll Billed from AEP Service Corp. 135 Production 354.20,22.b NA 136 Transmission 354.21.b TP 137 Distribution 354.23.b NA 138 Other (Excludes A&E 354.24,25,26.b NA 139 Total (sum lns 135 to 138) 140 Transmission related amount W/S= 141 COMMON PLANT ALLOCATOR (CE) 142 Electric 200.3.c DA 143 Gas 200.3.d NA 144 Other 200.3. e, f, g NA 145 Total (sum lns 142 to 144) 146 Electric related amount 147 W/S Allocator W/S 148 Transmission related amount (ln 146 * ln 147) CE= 149 WEIGHTED AVERAGE COST OF CAPITAL (WACC) $ 150 Long Term Interest (117, sum of 62c 66c) 151 Preferred Dividends (118.29.c) (positive number) 152 Development of Common Stock: 153 Proprietary Capital (112.16.c) 154 Less Preferred Stock (ln 159) 155 Less Account 219.1 (112.15.c) 156 Common Stock (ln 153 ln 154 ln 155) Cost 157 $ % (Note S) Weighted 158 Long Term Debt (112, sum of 18.c 21.c) 159 Preferred Stock (112.3.c) 160 Common Stock (ln 156) 161 Total (sum lns 158 to 160) WACC= Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 5 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 102A Page 17 of 44 pro forma Original Sheet No. 161D.8 Company: Letter A B C D E F Notes General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# b) If transmission owner ("TO") functionalizes its costs to transmission on its books, those costs are shown above and on any supporting workpapers rather than using the allocations above. The revenue credits shall include a) amounts received directly from the SPP for PTP transmission services, b) direct assignment charges for transmission facilities, the cost of which has been included in the TCOS, and c) amounts from customers taking service under grandfathered agreements, where the demand is not included in the rate divisor. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or facilities excluded from the TCOS are not included as revenue credits. Revenue from Transmission Customers whose coincident peak loads are included in the DIVISOR of the loadratio share calculation are not included as revenue credits. See Worksheet A for details. The annual and monthly net plant carrying charges on page 1 are used to compute the revenue requirement for facilities and any upgrades. This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet F shows the calculation of the additional incentive revenue requirement for each project receiving incentive rate treatment, as accepted by FERC. These individual additional revenue requirements shall be summed, for the projected year, and included here. Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, 255 and, if applicable, 107. The balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. An exception to this is pre1971 ITC balances, which are required to be taken as an offset to rate base. Account 281 is not allocated. Transmission allocations are shown on Worksheet C. Include Account 182.3, Other Regulatory Assets, related to Transmission Service under this Tariff, if any. Also include any unamortized balances related to precommercial operation costs when recovery of abandonment costs are granted. Identified as being transmission related or functionally booked to transmission. G Cash Working Capital assigned to transmission is oneeighth of O&M allocated to transmission on line 96. H Consistent with Paragraph 657 of Order 2003A, the amount on line 72 is equal to the balance of IPP System Upgrade Credits owed to transmission customers that made contributions toward the construction of System upgrades, and includes accrued interest and unreturned balance of contributions. The annual interest expense is included on line 124. I Removes the expense booked to transmission accounts included in the development of OATT ancillary services rates, including all of Account No. 561. J K L M Removes cost of transmission service provided by others to the extent such service is not incurred to provide the SPP service at issue. General Plant and Administrative & General expenses may be functionalized based on allocators other then the W/S allocator. Full documentation must be provided. Includes Regulatory Commission expenses itemized in FERC Form1 at page 351, column H. Worksheet D allocates these expense items. FERC Assessment Fees and Annual Charges shall not be allocated to transmission. Only safetyrelated and educational advertising costs in Account 930.1 are included in the TCOS. Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax and taxes related to income are excluded. N The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 119) multiplied by (1/1T). If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= 0.00% (State Income Tax Rate or Composite SIT. Worksheet J)) p = 0.00% (percent of federal income tax deductible for state purposes) O P Effective January 1, 2007, Texas instituted a gross margin tax. This tax is calculated on the Texas allocated revenue of the Company, reduced by 30% to derive a "Gross Margin" for the Company. The tax rate of one percent is assessed on the resulting amount. The jurisdictional allocator is based on transmission demand allocators. Removes plant excluded from the OATT because it does not meet the SPP's definition of Transmission Facilities or is otherwise ineligible to be recovered under the OATT. Q Removes transmission plant (e.g. stepup transformers) included in the development of OATT ancillary service rates and not already removed for reasons indicated in Note P. R Includes functional wages & salaries incurred by parent company service corporation for support of the operating company. S Long Term Debt cost rate = longterm interest (ln 150) / long term debt (ln 158). Preferred Stock cost rate = preferred dividends (ln 151) / preferred outstanding (ln 159). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 18 of 44 pro forma Original Sheet No. 161D.9 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 6 of 10 Historical Transmission Cost of Service HISTORICAL Company: Line No. 162 REVENUE REQUIREMENT (w/o incentives) (ln 286) Transmission Amount 163 REVENUE CREDITS (Note A) Total Allocator 164 Transmission Credits (Worksheet A) DA 165 Assoc. Business Development (Worksheet A) DA 166 Total Revenue Credits 167 REVENUE REQUIREMENT (w/o incentives) For All AEP Facilities (ln 162 less ln 166) 168 Revenue Requirement for SPP Base Plan Upgrades (w/o incentives) (Worksheet G) DA 169 REVENUE REQUIREMENT EXCLUDING BASE PLAN UPGRADE ATRR (ln 167 less ln 168) 170 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 171 Annual Rate (ln 167 / ln 203 x 100) 172 Monthly Rate (ln 171 / 12) 173 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 174 Annual Rate ( (ln 167 ln 259) / ln 203 x 100) 175 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 176 Annual Rate ( (ln 167 ln 259 ln 283 ln 284) / ln 203 x 100) 177 ADDITIONAL REVENUE REQUIREMENT for projects w/ incentive ROE's (Note C) (Worksheet F) NA 178 HISTORICAL YE 2006 TRANSMISSION REVENUE REQUIREMENT (ln 169 + ln 177) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 19 of 44 pro forma Original Sheet No. 161D.10 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 7 of 10 Historical Transmission Cost of Service HISTORICAL Company: (1) (2) (3) (4) (5) Data Sources Total RATE BASE CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. GROSS PLANT IN SERVICE 179 Production 205.46.g NA 180 Transmission 207.58.g DA 181 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 182 Plus: Additional Trans Plant on Transferred Assets (Worksheet H) N/A DA N/A 183 Distribution 207.75.g NA 184 General Plant 207.99.g (Note K) W/S 185 Intangible Plant 205.5.g W/S 186 Common 356 CE 187 TOTAL GROSS PLANT (sum lns 179 to 186) GP(h)= GTD= 188 ACCUMULATED DEPRECIATION AND AMORTIZATION 189 Production 219.2024.c NA 190 Transmission 219.25.c TP1= 191 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 192 Plus: Additional Projected Deprec on Transferred Assets (Worksheet H) N/A DA N/A 193 Plus: Additional Transmission Depreciation for 2007 (ln 259) N/A TP1 N/A 194 Plus: Additional General & Intangible Depreciation for 2007 (ln 261 + ln 262) N/A W/S N/A 195 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) N/A DA N/A 196 Distribution 219.26.c NA 197 General Plant 219.28.c (Note K) W/S 198 Intangible Plant 219 W/S 199 Common 356 CE 200 TOTAL ACCUMULATED DEPRECIATION (sum lns 189 to 199) 201 NET PLANT IN SERVICE 202 Production (ln 179 ln 189) 203 Transmission (ln 180 ln 190) 204 Plus: Transmission PlantinService Additions (ln 181 ln 191) N/A N/A 205 Plus: Additional Trans Plant on Transferred Assets (ln 182 ln 192) N/A N/A 206 Plus: Additional Transmission Depreciation for 2007 (ln 193) N/A N/A 207 Plus: Additional General & Intangible Depreciation for 2007 (ln 194) N/A N/A 208 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) (ln 195) N/A N/A 209 Distribution (ln 183 ln 196) 210 General Plant (ln 184 ln 197) 211 Intangible Plant (ln 185 ln 198) 212 Common (ln 186 ln 199) 213 TOTAL NET PLANT IN SERVICE (sum lns 202 to 212) NP(h)= 214 ADJUSTMENTS TO RATE BASE (Note D) 215 Account No. 281 (enter negative) 273.8.k (Worksheet C) DA 216 Account No. 282 (enter negative) 275.2.k (Worksheet C) DA 217 Account No. 283 (enter negative) 277.9.k (Worksheet C) DA 218 Account No. 190 234.8.c (Worksheet C) DA 219 Account No. 255 (enter negative) 267.8.h (Worksheet C) DA 220 Account 107 for Approved MultiYear Projects 216.43.b (Worksheet K) DA 221 Other Additions/Deductions (Note E) DA 222 TOTAL ADJUSTMENTS (sum lns 215 to 221) 223 PLANT HELD FOR FUTURE USE 214.x.d (Note F) DA 224 WORKING CAPITAL (Note G) 225 Cash Working Capital (1/8 * ln 257) 226 Transmission Materials & Supplies 227.8.c TP 227 A&G Materials & Supplies 227.11.c W/S 228 Undistributed Stores Expense (Acct 163) 227.16.c GP(h) 229 Prepayments (Account 165) Labor Allocated 111.57.c (Worksheet I) W/S 230 Prepayments (Account 165) Direct Allocated 111.57.c (Worksheet I) DA 231 Prepayments (Account 165) Gross Plant 111.57.c (Worksheet I) GP(h) 232 TOTAL WORKING CAPITAL (sum lns 225 to 231) 233 IPP CONTRIBUTIONS FOR CONSTRUCTION #REF! DA 234 RATE BASE (sum lns 213, 222, 223, 232, 233) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 20 of 44 pro forma Original Sheet No. 161D.11 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 8 of 10 Historical Transmission Cost of Service HISTORICAL Company: (1) (2) (3) (4) (5) EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. OPERATION & MAINTENANCE EXPENSE 235 Transmission 321.112.b TP 236 Less: expenses 100% assigned to TO billed customers (Worksheet E, ln 14) DA 237 Less: Total Account 561 (Load Dispatch Sch 1) (Note I) 321.8492.b TP 238 Less: Account 565 321.96.b (Note J) TP 239 Plus: Acct 565 native load, zonal or pool (Note J) DA 240 Transmission Subtotal (lns 235236237238+239) 241 Administrative and General 323.197.b (Note K) 242 Less: Acc. 928, Reg. Com. Exp. 323.189.b 243 Acct. 930.1, Gen. Advert. Exp. 323.191.b 244 Acc. 924, Property Insurance 323.185.b 245 Acc. 930.2, Misc. Gen. Exp. 323.192.b 246 Acc. 935, Maint. of Gen. Plant 323.196.b W/S 247 Balance of A & G (ln 241 sum ln 242 to ln 246) W/S 248 Plus: Acct. 924, Property Insurance (ln 244) NP(h) 249 Acct. 928 Transmission Specific (Note L) (Worksheet D) TP 250 Acct. 928 Transmission Allocated (Note L) (Worksheet D) GP(h) 251 Acct 930.1 Only safety related ads. (Note L) (Worksheet D) W/S 252 Acct 930.2 Misc Gen. Exp. Trans (Worksheet D) TP 253 Acct 930.2 Misc Gen. Exp. Allocated (Worksheet D) W/S 254 A & G Subtotal (sum lns 246 to 253) 255 Common 356 CE 256 Transmission Lease Payments DA 257 TOTAL O & M EXPENSE (ln 240 + ln 254 + ln 255 + ln 256) 258 DEPRECIATION AND AMORTIZATION EXPENSE 259 Transmission 336.7.f TP 260 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 261 General 336.10.f W/S 262 Intangible 336.1.f W/S 263 Common 336.11.f CE 264 TOTAL DEPRECIATION AND AMORTIZATIN (sum lns 259 to 263) 265 TAXES OTHER THAN INCOME (Note M) 266 Labor Related 267 Payroll 262.x263.x.i W/S 268 Plant Related 269 Property 262.x263.x.i NP(h) 270 Gross Receipts/Sales & Use 262.x263.x.i NA 271 Other 262.x263.x.i GP(h) 272 Payments in lieu of taxes GP(h) 273 TOTAL OTHER TAXES 114.14.c 274 INCOME TAXES (Note N) 275 T=1 {[(1 SIT) * (1 FIT)] / (1 SIT * FIT * p)} = 276 EIT=(T/(1T)) * (1(WCLTD/WACC)) = 277 where WCLTD=(ln 319) and WACC = (ln 322) 278 and FIT, SIT & p are as given in Note N. 279 GRCF=1 / (1 T) = (from ln 275) 280 Amortized Investment Tax Credit (enter negative) 281 Income Tax Calculation (ln 276 * ln 284) 282 ITC adjustment (ln 279 * ln 280) NP(h) 283 TOTAL INCOME TAXES (sum lns 281 to 282) 284 RETURN ON RATE BASE (Rate Base*WACC) (ln 234 * ln 322) 285 INTEREST ON IPP CONTRIBUTION FOR CONST. (Note H) (Worksheet B, ln 16) DA 286 REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX 287 (sum lns 257, 264, 273, 283, 284, 285) 288 TEXAS GROSS MARGIN TAX (NOTE O) (Worksheet J) DA 289 REVENUE REQUIREMENT INCLUDING GROSS MARGIN TAX Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 21 of 44 pro forma Original Sheet No. 161D.12 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 9 of 10 Historical Transmission Cost of Service HISTORICAL Company: SUPPORTING CALCULATIONS ln No. TRANSMISSION PLANT INCLUDED IN SPP TARIFF 290 Total transmission plant (ln 180) 291 Less transmission plant excluded from SPP Tariff (Note P) 292 Less transmission plant included in OATT Ancillary Services (Note Q ) (Worksheet L) 293 Transmission plant included in SPP Tariff (ln 290 ln 291 ln 292) 294 Percent of transmission plant in SPP Tariff (ln 293 / ln 290) TP= 295 WAGES & SALARY ALLOCATOR (W/S) (Note R) Direct Payroll Payroll Billed from AEP Service Corp. 296 Production 354.20,22.b NA 297 Transmission 354.21.b TP 298 Distribution 354.23.b NA 299 Other (Excludes A&E 354.24,25,26.b NA 300 Total (sum lns 296 to 299) 301 Transmission related amount W/S= 302 COMMON PLANT ALLOCATOR (CE) 303 Electric 200.3.c DA 304 Gas 200.3.d NA 305 Other 200.3. e, f, g NA 306 Total (sum lns 303 to 305) 307 Electric related amount 308 W/S Allocator W/S 309 Transmission related amount (ln 307 * ln 308) CE= 310 WEIGHTED AVERAGE COST OF CAPITAL (WACC) $ 311 Long Term Interest (117, sum of 62c 66c) 312 Preferred Dividends (118.29.c) (positive number) 313 Development of Common Stock: 314 Proprietary Capital (112.16.c) 315 Less Preferred Stock (ln 320) 316 Less Account 219.1 (112.15.c) 317 Common Stock (ln 314 ln 315 ln 316) Cost 318 $ % (Note S) Weighted 319 Long Term Debt (112, sum of 18.c 21.c) 320 Preferred Stock (112.3.c) 321 Common Stock (ln 317) 322 Total (sum lns 319 to 321) WACC= Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 22 of 44 pro forma Original Sheet No. 161D.13 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 10 of 10 Historical Transmission Cost of Service HISTORICAL Company: Letter A B C D E F Notes General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# b) If transmission owner ("TO") functionalizes its costs to transmission on its books, those costs are shown above and on any supporting workpapers rather than using the allocations above. The revenue credits shall include a) amounts received directly from the SPP for PTP transmission services, b) direct assignment charges for transmission facilities, the cost of which has been included in the TCOS, and c) amounts from customers taking service under grandfathered agreements, where the demand is not included in the rate divisor. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or facilities excluded from the TCOS are not included as revenue credits. Revenue from Transmission Customers whose coincident peak loads are included in the DIVISOR of the loadratio share calculation are not included as revenue credits. See Worksheet A for details. The annual and monthly net plant carrying charges on page 1 are used to compute the revenue requirement for facilities and any upgrades. This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet F shows the calculation of the additional incentive revenue requirement for each project receiving incentive rate treatment, as accepted by FERC. These individual additional revenue requirements shall be summed, for the projected year, and included here. Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, 255 and, if applicable, 107. The balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. An exception to this is pre1971 ITC balances, which are required to be taken as an offset to rate base. Account 281 is not allocated. Transmission allocations are shown on Worksheet C. Include Account 182.3, Other Regulatory Assets, related to Transmission Service under this Tariff, if any. Also include any unamortized balances related to precommercial operation costs when recovery of abandonment costs are granted. Identified as being transmission related or functionally booked to transmission. G Cash Working Capital assigned to transmission is oneeighth of O&M allocated to transmission on line 257. H Consistent with Paragraph 657 of Order 2003A, the amount on line 233 is equal to the balance of IPP System Upgrade Credits owed to transmission customers that made contributions toward the construction of System upgrades, and includes accrued interest and unreturned balance of contributions. The annual interest expense is included on line 285. I Removes the expense booked to transmission accounts included in the development of OATT ancillary services rates, including all of Account No. 561. J K L M Removes cost of transmission service provided by others to the extent such service is not incurred to provide the SPP service at issue. General Plant and Administrative & General expenses may be functionalized based on allocators other then the W/S allocator. Full documentation must be provided. Includes Regulatory Commission expenses itemized in FERC Form1 at page 351, column H. Worksheet D allocates these expense items. FERC Assessment Fees and Annual Charges shall not be allocated to transmission. Only safetyrelated and educational advertising costs in Account 930.1 are included in the TCOS. Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax and taxes related to income are excluded. N The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 280) multiplied by (1/1T). If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= 0.00% (State Income Tax Rate or Composite SIT. Worksheet J)) p = 0.00% (percent of federal income tax deductible for state purposes) O P Effective January 1, 2007, Texas instituted a gross margin tax. This tax is calculated on the Texas allocated revenue of the Company, reduced by 30% to derive a "Gross Margin" for the Company. The tax rate of one percent is assessed on the resulting amount. The jurisdictional allocator is based on transmission demand allocators. Removes plant excluded from the OATT because it does not meet the SPP's definition of Transmission Facilities or is otherwise ineligible to be recovered under the OATT. Q Removes transmission plant (e.g. stepup transformers) included in the development of OATT ancillary service rates and not already removed for reasons indicated in Note P. R Includes functional wages & salaries incurred by parent company service corporation for support of the operating company. S Long Term Debt cost rate = longterm interest (ln 311) / long term debt (ln 319). Preferred Stock cost rate = preferred dividends (ln 312) / preferred outstanding (ln 320). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 23 of 44 pro forma Original Sheet No. 161D.14 Worksheet List: A B C D E F G H I J K L Revenue Credits IPP System Upgrade Credit ADIT & ITC Details A&G Expense Detail Transmission Expense Adjustments ATRR Calculation for NonBase Plan Projects ATRR Calculation for SPP Base Plan Upgrades Transmission PlantinService Additions NonTax Balance Sheet Adjustments Tax CWIP Balances on MultiYear Projects GSU Net Book Values Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet A Revenue Credits Exhibit No. AEP 102A Page 24 of 44 pro forma Original Sheet No. 161D.15 Total Non Company Transmission Transmission I. Account 450, Forfeited Discounts $0 II. Account 451,Miscellaneous Service Revenues $0 III. Account 454, Rent from Electric Property Account 4540001 Rent from Elect PropertyAff Account 4540002 Rent from Elect Property NonAff Account 4540003 Rent from Elect Property ABD Aff Account 4540004 Rent from Elect Property ADB NonAff Total Rents from Electirc Property $0 $0 ( Revenue related to transmission facilities for pole attachments, rentals, etc. Provide data sources and explanations in Section VIII, Notes below ) IV. Account 4560015, Revenues from Associated Business Development Account 4560015, Revenues from Associated Business Development V. Total Other Operating Revenues To Reduce Revenue Requirement $0 VI. Account 456.0, Revenues from Transmission of Electricity of Others ( Provide data sources and any detailed explanations necessary in Section VIII, Notes below ) Less: TO's LSE Direct Assignment Revenue Credits TO's LSE Sponsored Upgrade Revenue Credits TO's LSE Network Upgrades for Generation Interconnection Credits TO's PointToPoint Revenue for GFA's Associated with Load Included in the Divisor Network Service Revenue (Schedule 9) Associated With Load Included in the Divisor TO's Revenue Associated with Transmission Plant Excluded From SPP Tariff Wholesale Distribution charges TO's LSE Revenue from Ancillary Services Provided Base Plan Revenue Received Other (Flow Through of ERCOT Ancillary Charges) Other Net Transmission Credits $0 VII. Total Worksheet A Revenue Credits $0 VIII. Data Sources: Data for this worksheet came from the FERC Form 1 and the Company's General Ledger. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 25 of 44 pro forma Original Sheet No. 161D.16 Worksheet B IPP System Upgrade Credit Line No. Account 2530067 Transmission Owner 1 Funds from IPP Customers 2 Transimission Credits given back over the years: 3 4 5 6 7 8 $0 9 10 Net balance of IPP Funds Received Credited Back $0 11 Interest Accrued over the years: 12 13 14 15 16 17 $0 18 Net Funds from IPP Customers 12/31/2006 (FORM 1, P269, line 7(f)) $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet C ADIT & ITC Details Exhibit No. AEP 102A Page 26 of 44 pro forma Original Sheet No. 161D.17 (A) (B) (C) (D) (E) (F) (G) (H) (I) 100% 100% Transmission Transmission & Transmission Total Included 2006 NonTransmission Transmission Plant Distribution Labor in Ratebase Acc. No. Description YE Balance Related Related Related Plant Related Related (F)+(G)+(H) Account 281 Subtotal Form 1, p273 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 282 Subtotal Form 1, p274 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 283 Subtotal Form 1, p277 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 190 NOTE: Insert Amounts as Negative Numbers Subtotal Form 1, p234 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 255 Subtotal Form 1, p266.8f Less Post 1971 ITC Property Under F2 Option Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 27 of 44 pro forma Original Sheet No. 161D.18 Worksheet D A&G Expense Detail (A) (B) (C) (D) (E) (F) (G) 100% 100% Transmission Transmission Item No. Description Expense NonTransmission Specific Allocated Explanation Account 928 Total Account 930.1 Total Account 930.2 Total $0 $0 $0 $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet E Transmission Expense Adjustments Exhibit No. AEP 102A Page 28 of 44 pro forma Original Sheet No. 161D.19 2006 1 Other Expenses 2 Direct Assignment Charge 3 Sponsored Upgrades Charge 4 Firm and NonFirm PointToPoint Charges 5 Base Plan Charges 6 Schedule 9 Charges 7 SPP Schedule 12 FERC Assessment 8 SPP Schedule 1A 9 SPP Annual Assessment 10 Ancillary Services Expenses 11 Other 12 Other 13 Other 14 Total ( sum of lines 2 through 13 ) $0 Adjustment to charges that are booked to transmission accounts that are the responsibility of the TO's LSE. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 29 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.20 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 1 of 3 I. Calculate Return and Income Taxes with 0 basis point ROE increase. A. Determine 'R' with hypothetical 0 basis point increase in ROE for Identified Projects ROE w/o incentives (Attachment H, ln 160) 0% Project ROE Incentive Adder 0 ROE with additional 0 basis point incentive 0% Determine R ( cost of long term debt, cost of preferred stock and percent is from Attachment H, lns 158 through160) % Cost Weighted cost Long Term Debt Preferred Stock Common Stock WACC = 0.0000 B. Determine Return using 'R' with hypothetical 0 basis point ROE increase for Identified Projects. Rate Base (Attachment H, ln 73) $0 R (fom A. above) 0.0000 Return (Rate Base x R) $0 C. Determine Income Taxes using Return with hypothetical 0 basis point ROE increase for Identified Projects. Return (from B. above) $0 CIT (Attachment H, ln 115) 0.00% Income Tax Calculation (Return x CIT) $0 ITC Adjustment (Attachment H, ln 121) $0 Income Taxes $0 II. Calculate Net Plant Carrying Charge Rate (Fixed Charge Rate or FCR) with hypothetical 0 basis point ROE increase. A. Determine Net Revenue Requirement less return and Income Taxes. Net Revenue Requirement (Attachment H, ln 6) $0 Return (Attachment H, ln 123) $0 Income Taxes (Attachment H, ln 122) $0 Gross Margin Taxes (Attachment H, ln 127) $0 Net Revenue Requirement, Less Return and Taxes $0 B. Determine Net Revenue Requirement with hypothetical 0 basis point increase in ROE. Net Revenue Requirement, Less Return and Taxes $0 Return (from I.B. above) $0 Income Taxes (from I.C. above) $0 Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase Gross Margin Tax with 0 Basis Point ROE Increase (II C. below) $0 Revenue Requirement w/ Gross Margin Taxes $0 Less: Depreciation (Attachment H, ln 98) $0 Net Rev. Req, w/0 Basis Point ROE increase, less Depreciation $0 C. Determine Gross Margin Tax with hypothetical 0 basis point increase in ROE. Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase (II B. above) Addback Revenue Credits for Correct Gross Margin Tax Basis $0 Proper Basis for Caclulating Gross Margin Tax $0 Gross Margin Taxes with 0 Basis Point ROE increase Apportionment Factor to Texas (Worksheet J, ln 12) 0% Apportioned Texas Revenues $0 Taxable Percentage of Revenue (%) 0% Taxable, Apportioned Margin $0 Texas Gross Margin Tax Rate 0% Texas Gross Margin Tax Expense $0 Grossup Required for Gross Margin Tax Expense $0 Total Additional Gross Margin Tax Revenue Requirement $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 30 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.21 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 2 of 3 D. Determine FCR with hypothetical 0 basis point ROE increase. Net Transmission Plant (Attachment H, ln 42) $0 Net Revenue Requirement, with 0 Basis Point ROE increase $0 FCR with 0 Basis Point increase in ROE 0% Net Rev. Req, w / 0 Basis Point ROE increase, less Dep. $0 FCR with 0 Basis Point ROE increase, less Depreciation 0% FCR less Depreciation (Attachment H, ln 13) 0% Incremental FCR with 0 Basis Point ROE increase, less Depreciation 0% III. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) $0 Transmission Plant @ End of Period (P.207, ln 58) $0 $0 Average Balance of Transmission Investment $0 Annual Depreciation Rate (P. 336, ln. 7, col. F) $0 Composite Depreciation Rate 0% Depreciable Life for Composite Depreciation Rate 0 YEARS Round to nearest whole year 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 31 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.22 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 3 of 3 IV. Determine Revenue Requirement & Additional Revenue Requirement for facilities receiving incentives. A. Facilities receiving incentives accepted by FERC in Docket No. (e.g. ER05925000) Project Description: Details Investment $0 Current Year 0 Service Year (yyyy) 0 ROE increase accepted by FERC (Basis Points) 0 Service Month (112) 0 FCR w/o incentives, less depreciation 0% Useful life 0 FCR w/incentives approved for these facilities, less dep. 0% CIAC (Yes or No) Annual Depreciation Expense $0 Investment Beginning Depreciation Ending Revenue Revenue Req't. Additional Rev. Year Balance Expense Balance Requirement with Incentives ** Requirement 1 $ 2 $ 3 $ 4 $ 5 $ 6 $ 7 $ 8 $ 9 $ 10 $ 11 $ 12 $ 13 $ 14 $ 15 $ 16 $ 17 $ 18 $ 19 $ 20 $ 21 $ 22 $ 23 $ 24 $ 25 $ 26 $ 27 $ 28 $ 29 $ 30 $ 31 $ 32 $ 33 $ 34 $ 35 $ 36 $ 37 $ $ ## This is the calculation of additional incentive revenue on projects deemed by the FERC to be eligible for an incentive return. This additional incentive requirement is applicable for the life of this specific project. Each year the revenue requirement calculated for SPP should be incremented by the amount of the incentive revenue calculated for that year on this project. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 32 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.23 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 1 of 3 I. Calculate Return and Income Taxes with 0 basis point ROE increase for Projects Qualified for Incentive. A. Determine 'R' with hypothetical 0 basis point increase in ROE for Identified Projects ROE w/o incentives (Attachment H, ln 160) 0% Project ROE Incentive Adder 0 ROE with additional 0 basis point incentive 0% Determine R ( cost of long term debt, cost of preferred stock and percent is from Attachment H, lns 158 through160) % Cost Weighted cost Long Term Debt Preferred Stock Common Stock WACC = 0.0000 B. Determine Return using 'R' with hypothetical 0 basis point ROE increase for Identified Projects. Rate Base (Attachment H, ln 73) $0 R (fom A. above) 0.0000 Return (Rate Base x R) $0 C. Determine Income Taxes using Return with hypothetical 0 basis point ROE increase for Identified Projects. Return (from B. above) $0 CIT (Attachment H, ln 115) 0.00% Income Tax Calculation (Return x CIT) $0 ITC Adjustment (Attachment H, ln 121) $0 Income Taxes $0 II. Calculate Net Plant Carrying Charge Rate (Fixed Charge Rate or FCR) with hypothetical 0 basis point ROE increase. A. Determine Net Revenue Requirement less return and Income Taxes. Net Revenue Requirement (Attachment H, ln 6) $0 Return (Attachment H, ln 123) $0 Income Taxes (Attachment H, ln 122) $0 Gross Margin Taxes (Attachment H, ln 127) $0 Net Revenue Requirement, Less Return and Taxes $0 B. Determine Net Revenue Requirement with hypothetical 0 basis point increase in ROE. Net Revenue Requirement, Less Return and Taxes $0 Return (from I.B. above) $0 Income Taxes (from I.C. above) $0 Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase Gross Margin Tax with 0 Basis Point ROE Increase (II C. below) $0 Revenue Requirement w/ Gross Margin Taxes $0 Less: Depreciation (Attachment H, ln 98) $0 Net Rev. Req, w/0 Basis Point ROE increase, less Depreciation $0 C. Determine Gross Margin Tax with hypothetical basis point increase in ROE. Net Revenue Requirement before Gross Margin Taxes, with $0 Basis Point ROE increase (II B. above) Addback Revenue Credits for Correct Gross Margin Tax Basis $0 Proper Basis for Caclulating Gross Margin Tax $0 Gross Margin Taxes with Basis Point ROE increase Apportionment Factor to Texas (Worksheet J, ln 12) 0% Apportioned Texas Revenues $0 Taxable Percentage of Revenue (%) 0% Taxable, Apportioned Margin $0 Texas Gross Margin Tax Rate 0% Texas Gross Margin Tax Expense $0 Grossup Required for Gross Margin Tax Expense $0 Total Additional Gross Margin Tax Revenue Requirement $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 33 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.24 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 2 of 3 D. Determine FCR with hypothetical 0 basis point ROE increase. Net Transmission Plant (Attachment H, ln 42) $0 Net Revenue Requirement, with 0 Basis Point ROE increase $0 FCR with 0 Basis Point increase in ROE 0% Net Rev. Req, w / 0 Basis Point ROE increase, less Dep. $0 FCR with 0 Basis Point ROE increase, less Depreciation 0% FCR less Depreciation (Attachment H, ln 13) 0% Incremental FCR with 0 Basis Point ROE increase, less Depreciation 0% III. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) $0 Transmission Plant @ End of Period (P.207, ln 58) $0 $0 Average Balance of Transmission Investment $0 Annual Depreciation Rate (P. 336, ln. 7, col. F) $0 Composite Depreciation Rate 0% Depreciable Life for Composite Depreciation Rate 0 YEARS Round to nearest whole year 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 34 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.25 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 3 of 3 IV. Determine Revenue Requirement & Additional Revenue Requirement for facilities receiving incentives. A. Base Plan Facilities Facilities receiving incentives accepted by FERC in Docket No. (e.g. ER05925000) Project Description: Details Investment $0 Current Year 0 Service Year (yyyy) 0 ROE increase accepted by FERC (Basis Points) 0 Service Month (112) 0 FCR w/o incentives, less depreciation 0% Useful life 0 FCR w/incentives approved for these facilities, less dep. 0% CIAC (Yes or No) Annual Depreciation Expense $0 Investment Beginning Depreciation Ending BPU Rev. Req't. BPU Rev. Req't. Incentive Rev. Year Balance Expense Balance w/o Incentives with Incentives** Requirement## 0 $ 1 $ 2 $ 3 $ 4 $ 5 $ 6 $ 7 $ 8 $ 9 $ 10 $ 11 $ 12 $ 13 $ 14 $ 15 $ 16 $ 17 $ 18 $ 19 $ 20 $ 21 $ 22 $ 23 $ 24 $ 25 $ 26 $ 27 $ 28 $ 29 $ 30 $ 31 $ 32 $ 33 $ 34 $ 35 $ 36 $ Project Totals ** This is the total amount that needs to be reported to SPP for billing to all regions. ## This is the calculation of additional incentive revenue on projects deemed by the FERC to be eligible for an incentive return. This additional incentive requirement is applicable for the life of this specific project. Each year the revenue requirement calculated for SPP should be incremented by the amount of the incentive revenue calculated for that year on this project. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet H Transmission PlantinService Additions Exhibit No. AEP 102A Page 35 of 44 pro forma Original Sheet No. 161D.26 I. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) Transmission Plant @ End of Period (P.207, ln 58) Average Balance of Transmission Investment Annual Depreciation Rate (P. 336, ln. 7, col. F) Composite Depreciation Rate Round to % to Reflect a Composite Life of Years II. Calculation of Property Placed in Service by Month and the Related Depreciation Expense Month in Service Capitalized Balance Composite Annual Depreciation Rate Annual Depreciation Monthly Depreciation No. Months Depreciation First Year Depreciation Expense January 0.00% 11 February 0.00% 10 March 0.00% 9 April 0.00% 8 May 0.00% 7 June 0.00% 6 July 0.00% 5 August 0.00% 4 September 0.00% 3 October 0.00% 2 November 0.00% 1 December 0.00% 0 Investment $ Depreciation Expense $ III. Plant Transferred $ <== This input area is for original cost plant $ <== This input area is for accumulated depreciation that may be associated with capital expenditures. It would have an impact if a company had assets transferred from a subsidiary. $ <== This input area is for additional Depreciation Expense Issued by: L. Patrick Bourne, Director Issued on: Effective:

Issued by: L. Patrick Bourne, Director Issued on: Effective: Worksheet I NonTax Balance Sheet Adjustments Preferrered Stock Preferred Stock DividendsEffective Cost Based on YE Outstanding Shares Shares Outstanding @ 12/31/XX Par Value Book Value Dividend Rate Dividend Form 1 P. 251.e $ Effective Cost of Preferred Stock % Prepayments Account 165 (A) (B) (C) (D) (E) (F) (G) (H) 100% 100% Transmission Transmission Total Included NonTransmission Transmission Plant Labor in Ratebase Acc. No. Description YE Balance Related Related Related Related (E)+(F)+(G) Subtotal Form 1, p 112.57.c 0 0 0 0 0 0 Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.27 Exhibit No. AEP 102A Page 36 of 44

Issued by: L. Patrick Bourne, Director Issued on: Effective: PSO Worksheet J Tax I. DEVELOPMENT OF COMPOSITE STATE INCOME TAX RATES II. Public Service Company of Oklahoma Calculation of Effective State Income Tax Rate For Tax Year 20XX State I Income Tax Rate Apportionment Factor Effective State Income Tax Rate 0.0000% State II Income Tax Rate Apportionment Factor Effective State Income Tax Rate 0.0000% Total Effective State Income Tax Rate 0.0000% CALCULATION OF TEXAS GROSS MARGIN TAX Total Company Trans. Only Total Company Trans. Only Line # REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX (ln 284 of Template) 147,553,686 37,758,675 1 Apportionment Factor to Texas (ln12) 0.00% 0.00% 0.00% 0.00% 2 Apportioned Texas Revenues $0 $0 $0 $0 3 Taxable Percentage of Revenue (70%) 70% 70% 70% 70% 4 Taxable, Apportioned Margin 5 Texas Gross Margin Tax Rate (1%) 1% 1% 1% 1% 6 Texas Gross Margin Tax Expense 7 Grossup Required for Texas Gross Margin Expense ((ln 6 * ln 3 * ln 1)/(1 ln 5) * ln 5) 8 Total Additional Gross Margin Tax Revenue Requirement 9 WHOLESALE LOAD ALLOCATOR (For Use in Gross Margin Tax Allocator) 10 Texas Jurisdictional Load 11 Total Load 12 Allocation Percentage (ln 10 / ln 11) 0.00% Actual Projected Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.28 Exhibit No. AEP 102A Page 37 of 44

Southwest Power Pool FERC Electric Tariff Worksheet K CWIP Balances on MultiYear Projects Exhibit No. AEP 102A Page 38 of 44 pro forma Original Sheet No. 161D.29 (A) (B) (C) Capital Item No. Descrition of Project Expenditure Total Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 102A Page 39 of 44 pro forma Original Sheet No. 161D.30 Worksheet L GSU Net Book Values as of December 31, 20XX company depreciation group utility acct vintage orig cost reserve net book value Total Transmission Investment $0 $0 $0 Less: GSU Investment $0 $0 $0 Transmission w/o GSUs $0 $0 $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 40 of 44 Southwest Power Pool Original Sheet No. 217 FERC Electric Tariff ATTACHMENT T Rate Sheets For PointToPoint Transmission Service Issued by: L. Patrick Bourne, Manager Issued on: February 28, 2005 Effective: May 5, 2005

Exhibit No. AEP 102A Page 41 of 44 Southwest Power Pool pro forma Third Revised Sheet No. 218 FERC Electric Tariff Superseding Second Revised Sheet No. 218 Zone 1 Rate Sheet For PointtoPoint Transmission Service Firm PointtoPoint Transmission Service The Transmission Customer shall compensate the Transmission Provider each month for Reserved Capacity at the sum of the applicable charges set forth below: 1. Monthly delivery: $1528.30/MW of Reserved Capacity per month. 2. Weekly delivery: $ 352.66/MW of Reserved Capacity per week. 3. Daily delivery: OnPeak: OffPeak: $ 70.54/MW of Reserved Capacity per day. $ 50.25/MW of Reserved Capacity per day. The total demand charge in any week, pursuant to a reservation for Daily delivery, shall not exceed the rate specified in Section 2 above times the highest amount in megawatts of Reserved Capacity in any day during such week. For the purpose of the rate specified in Section 3 above, the OffPeak Period shall be Saturdays, Sundays, New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the OnPeak Period shall be all days that are not in the OffPeak Period. NonFirm PointtoPoint Transmission Service The Transmission Customer shall compensate the Transmission Provider for NonFirm PointToPoint Transmission Service up to the sum of the applicable charges set forth below: 1. Monthly delivery: $1528.30/MW of Reserved Capacity per month. 2. Weekly delivery: $ 352.66/MW of Reserved Capacity per week. 3. Daily delivery: OnPeak: OffPeak 4. Hourly delivery: OnPeak: OffPeak $ 70.54/MW of Reserved Capacity per day. $ 50.25/MW of Reserved Capacity per day. $ 4.41/MW of Reserved Capacity per hour. $ 2.10/MW of Reserved Capacity per hour. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 102A Page 42 of 44 Southwest Power Pool pro forma Second Revised Sheet No. 219 FERC Electric Tariff Superseding First Revised Sheet No. 219 The total demand charge in any day, pursuant to a reservation for Hourly delivery, shall not exceed the rate specified in Section 3 above times the highest amount in megawatts of Reserved Capacity in any hour during such day. In addition, the total demand charge in any week, pursuant to a reservation for Hourly or Daily delivery, shall not exceed the rate specified in Section 2 above times the highest amount in megawatts of Reserved Capacity in any hour during such week. For the purpose of the rate specified in Section 3 above, the OffPeak Period shall be Saturdays, Sundays, New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the OnPeak Period shall be all days that are not in the OffPeak Period. For the purpose of the rate specified in Section 4 above, OnPeak is all hours between HE 0700 and HE 2200, inclusive, Central Time Zone, excluding Sundays and holidays. Holidays shall be as defined by NERC, currently New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. OffPeak is all hours not designated as OnPeak. Issued by: L. Patrick Bourne, Manager Issued on: Effective:

Exhibit No. AEP 102A Page 43 of 44 Southwest Power Pool FERC Electric Tariff pro forma First Revised Sheet No. 219A Superseding Original Sheet No. 219A RESERVED Issued by: L. Patrick Bourne, Manager Issued on: Effective:

Exhibit No. AEP 102A Page 44 of 44 Southwest Power Pool pro forma First Revised Sheet No. 220 FERC Electric Tariff Superseding Original Sheet No. 220 RESERVED Issued by: L. Patrick Bourne, Manager Issued on: Effective:

ATTACHMENT B blacklined and highlighted copy of the revised tariff sheets showing the changes required by the August 31 order (Exhibit No. AEP101A)

Exhibit No. AEP 101A Page 1 of 44 Southwest Power Pool pro forma Third Revised Sheet No. 94 FERC Electric Tariff Superseding Second Revised Sheet No. 94 SCHEDULE 1 Scheduling, System Control And Dispatch Service Scheduling, System Control and Dispatch Service is required to schedule the movement of power through, out of, within or into a Control Area. Charges for such service shall be as follows: 1) For Customers taking Firm or NonFirm PointToPoint Transmission Service, for through and out transactions, the Schedule 1 charge shall be the product of the capacity reserved, expressed in MW and the appropriate rate as follows: OnPeak: Off Peak: Monthly Rate $ 59.2979 per MWMonth Weekly Rate $13.6841 per MWWeek (The Monthly Rate times 12, divided by 52) Daily Rate $2.7368 per MWDay (The Monthly Rate times 12, divided by 260) Hourly Rate $0.1711 per MWHour (The Monthly Rate times 12, divided by 4160) Daily Rate/MW $1.9495 per MWDay (The Monthly Rate times 12, divided by 365) Hourly Rate/MW $0.1711 per MWHour (The Monthly Rate times 12, divided by 8760) OnPeak and OffPeak Periods OffPeak days shall be Saturdays and Sundays and all NERC holidays. All other days shall be OnPeak. All hours during OffPeak days shall be OffPeak. OnPeak hours during OnPeak days shall be all hours from HE 0700 through HE 2200 Central Prevailing Time. All other hours during OnPeak days shall be OffPeak. 2) For Customers taking Firm or NonFirm PointToPoint Transmission Service, for transactions into and within the Transmission System, the Schedule 1 charge shall be the charge computed pursuant to the approved rate schedule of the Zone that is the Point of Delivery. See Addendum 1 to this Schedule 1 for Zone 1 charges. 3) For Customers taking Network Integration Transmission Service, the Schedule 1 charge shall be the charge computed pursuant to the approved rate schedule of the Zone in which the load is located. See Addendum 1 to this Schedule 1 for Zone 1 charges. Issued by: L. Patrick Bourne, Director Issued on: Effective

Exhibit No. AEP 101A Page 2 of 44 Southwest Power Pool pro forma Second Revised Sheet No. 96 FERC Electric Tariff Superseding First Revised Sheet No. 96 ADDENDUM 1 TO SCHEDULE 1 Revenue Requirements for the Allocation of Through And Out Transaction Revenue Revenue associated with the provision of Schedule 1 service for Customers taking Firm or Non Firm PointToPoint Transmission Service for through and out transactions, shall be allocated to Transmission Owners in proportion to the respective scheduling revenue requirement of each such Transmission Owner associated with the provision of this service. Such scheduling revenue requirements are: Transmission Owner CURRENTLY EFFECTIVE Revenue Requirement AEP $3,257,073 Aquila MPS $1,620,559 Aquila WPK $594,828 Empire $260,944 GRDA $686,880 KCPL $0 Midwest $190,804 OG+E $4,759,216 SPA $1,622,827 Springfield $0 SPS $1,674,015 Westar $3,209,760 WFEC $1,824,120 Total $19,355,553 Zone 1 charges for Scheduling, System Control and Dispatch Service: (a) Network Integration Transmission Service: $34.55 per MW of Network Load per month. (b) PointtoPoint Transmission Service per MW reserved per: Month Week Day Hour $34.55 $7.97 $1.14 $0.05 Issued by: L. Patrick Bourne, Manager Issued on: Effective:

Exhibit No. AEP 101A Page 3 of 44 Southwest Power Pool pro forma Ninth Revised Sheet No. 161 FERC Electric Tariff Superseding Eighth Revised Sheet No. 161 ATTACHMENT H Annual Transmission Revenue Requirement For Network Integration Transmission Service 1. The Existing Zonal Annual Transmission Revenue Requirement within each Zone for (1) Zone 1 purposes of determining the charges under Schedule 9, Network Integration Transmission Service, is specified in column 3. The Base Plan Zonal Annual Transmission Revenue Requirement within each Zone for the purposes of determining the zonal charges under Schedule 11, Base Plan Charges, is specified in column 4. (2) (3) Existing Zonal ATRR American Electric Power (Public Service Company of Oklahoma, and Southwestern Electric Power Company, collectively AEP ) See Section 7 below (4) Base Plan Zonal ATRR 1 East Texas Electric Cooperative, Inc. $2,733,879 $0 1 TexLa Electric Cooperative of Texas, Inc. $588,874 $0 1 Deep East Texas Electric Cooperative, Inc. $428,131 $0 2 Cleco Corporation $ 29,328,000 $0 3 City Utilities of Springfield, Missouri $ 8,651,509 $0 4 Empire District Electric Company $ 14,075,000 $0 5 Grand River Dam Authority (Est.) $ 24,589,256 $0 6 Kansas City Power & Light Company $ 35,461,776 $0 7 Oklahoma Gas & Electric Company $ 65,065,032 $0 8 Midwest Energy, Inc. $ 4,197,347 $0 9 Aquila NetworksMPS/L&P $ 20,759,283 $0 9a Aquila NetworksMPS $14,059,183 $0 9b Aquila NetworksL&P $6,700,100 $0 10 Southwestern Power Administration $9,155,900 $0 11 Southwestern Public Service $65,500,000 $0 12 Sunflower Electric Corporation $ 14,484,045 $0 13 Western Farmers Electric Cooperative $ 20,719,639 $0 Westar Energy, Inc. (Kansas Gas & Electric and See section 5 14 $0 Westar Energy) below 15 Aquila NetworksWPK $ 5,947,002 $0 $ Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 4 of 44 pro forma Seventh Revised Sheet No. 161A Superseding Substitute Sixth Revised Sheet No. 161A 2. The Base Plan Regionwide Annual Transmission Revenue Requirement for the purposes of determining the regionwide charges under Schedule 11 shall initially be $0. 3. The amounts in (1) and (2) shall be effective until amended by the Transmission Owner or modified by the Commission or other applicable regulatory authority. 4. The revenue requirements stated in Attachment H shall not be changed absent a filing with the Commission. 5. The Annual Transmission Revenue Requirement for purposes of the Network Integration Transmission Service shall be calculated using the rate formula set forth in Attachment H1 of the Westar Open Access Transmission Tariff (Westar formula rate). The results of the formula calculation shall be posted on the SPP website and in an accessible location on Westar s OASIS website by May 15 of each calendar year and shall be effective on June 1 of such year. The Annual Transmission Revenue Requirement will be as identified on page 1, line 7 of the Westar formula rate, plus the previous calendar year s total firm PointtoPoint transmission revenue allocated to Westar under Attachment L provided such PointtoPoint transmission revenue is deducted from Westar s Annual Transmission Revenue Requirement under Section 34.1. 6. Pursuant to the Offer of Settlement approved by the Federal Energy Regulatory Commission in Xcel Energy Services Inc., 115 FERC 61,011, the Annual Transmission Reveune Requirement for the Southwestern Public Service Company (SPS) rate zone (Zone 11) stated on Sheet 161 shall not be subject to adjustment pursuant to section 34.1 for the previous calendar year s total firm PointtoPoint transmission revenue allocated to SPS under Attachment L when determining the monthly zonal Demand Charge for Zone 11. 7. The AEP Annual Transmission Revenue Requirement for purposes of the Network Integration Transmission Service shall be (i) calculated using the formula rate set forth in Addendum 1 to this Attachment H, (ii) posted on the SPP website by May 25 of each calendar year, and (iii) effective on July 1 of such year. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 5 of 44 pro forma Second Revised Sheet No. 161B Superseding First Revised Sheet No. 161B ADDENDUM 1 TO ATTACHMENT H MONTHLY DEMAND CHARGE CALCULATION FOR ZONE 1 NETWORK INTEGRATION TRANSMISSION SERVICE This Addendum to Attachment H sets forth the monthly Demand Charge for Zone 1 for Network Customers taking Network Integration Transmission Service under Schedule 9 to this Tariff. Charges for Compensation to AEP The monthly Demand Charge to Network Customers for compensation to AEP shall be determined by multiplying one twelfth (1/12) of the Existing Zonal ATRR for AEP, specified in Attachment H, by the Network Customer s monthly Network Load, determined in accordance with the provisions of Section 34.2, expressed in MW, divided by the total monthly Network Load for Zone 1. The total monthly Network Load shall be adjusted as necessary to incorporate the load of Network Integration Transmission Service Customers, and any zonal load served under grandfathered network and longterm firm pointtopoint service agreements. Charges for Compensation to East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. In addition to the charges specified for compensation to AEP above, the Transmission Provider shall calculate a monthly Demand Charge associated with the revenue requirements of East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. which shall be applicable to all customers located in Zone 1 taking Network Service under this tariff, including any Transmission Owner within Zone 1 taking service under Section 39. The monthly charge to each customer for compensation to East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. shall be the product of the customer s load ratio share and one twelfth (1/12) of such Transmission Owner s Existing Zonal Annual Transmission Revenue Requirement. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 101A Page 6 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.1 FERC Electric Tariff I. Annual Update AEP Formula Rate Implementation Protocols 1. The rate formula template ( Formula ) and these protocols together comprise the filed rate of Public Service Company of Oklahoma and Southwestern Electric Power Company (collectively, AEP ) for transmission service under the SPP OATT. AEP must follow the instructions specified in the Formula to calculate its Annual Transmission Revenue Requirements ( ATRR ) and the rates for its Network Integration Transmission Service and PointtoPoint transmission service ( Formula Rate ). 2. The Formula Rate shall initially be effective for service on and after the date specified by the Federal Energy Regulatory Commission ( FERC ) in an order accepting the Formula Rate, and in subsequent years on and after July 1 of each calendar year through June 30 of the subsequent calendar year ( Rate Year ), subject to review, challenge and refunds or surcharges with interest, to the extent provided herein. 3. On or before May 25 of each calendar year, AEP shall: (a) (b) (c) (d) recalculate the ATRR and the Formula Rate for the new Rate Year in accordance with the Formula Rate ( Annual Update ); provide such Annual Update and supporting information in readonly format to SPP, for posting on the SPP website, such information to include a populated Formula showing the calculation of such Annual Update and documentation supporting such calculation as provided in Section I.4 below (the date of such posting to be the Posting Date ); disclose any changes in AEP accounting policies, practices or procedures that impact the Formula or calculations under the Formula that have occurred since the initial filing of the Formula or posting of the most recent Annual Update, as applicable; and notify its transmission customers and affected regulatory commissions of the Annual Update posting, and provide, upon request, fully functioning spreadsheet files supporting the Annual Update. 4. The Annual Update for the Rate Year shall: (a) (b) be based upon AEP s FERC Forms No. 1 for the most recent calendar year, and, to the extent specified in the Formula, upon the books and records of AEP consistent with the FERC accounting policies and practices ( Prior Year ATRR ); include adjustments reflecting the additional transmission plant in service, and related depreciation, and income taxes that are reasonably projected to be Issued by: Issued on: L. Patrick Bourne, Director Effective:

Exhibit No. AEP 101A Page 7 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.2 FERC Electric Tariff recorded upon the books and records of AEP consistent with the Formula and FERC accounting policies and practices, so as to estimate the ATRR as of the current calendar year end ( Projected ATRR ); (c) (d) (d) as and to the extent specified in the Formula, provide sufficiently detailed supporting documentation for data (and all adjustments thereto or allocations thereof) that are used to develop the Formula Rate and are not otherwise available directly from the FERC Form No. 1; beginning in the second year, compare the latest Prior Year ATRR with the Projected ATRR calculated in the prior year s Annual Update, thereby to determine the amount needed to be surcharged or refunded to customers in the new Rate Year to true up collections for the soon to end Rate Year, including interest at the applicable FERC refund interest rates; and be subject to review only in accordance with the procedures set forth in these Formula Rate Review Protocols ( Protocol ). 5. A change to the Formula inputs related to revised return on equity financing ( ROE ), or depreciation rates or PostEmployment Benefits Other than Pensions ( PBOP ) expenses may not be made absent an appropriate filing with the FERC pursuant to Federal Power Act Section 205 or Section 206. Additionally, an annual increase in PostEmployment Benefits Other than Pensions ( PBOP ) expenses that results in an increase in the Projected ATRR equivalent to $0.05 per kw per month for Network Integration Transmission Service, as compared to the immediately preceding ATRR Annual Update, may not be included in an Annual Update without such a filing. 6. If AEP files any corrections to its FERC Forms No. 1 during a Rate Year that would affect the Formula Rate for that Rate Year, such corrections and any resulting refunds or surcharges shall be reflected in the true up adjustment made part of the Annual Update for the next effective Rate Year. II. Review Procedures for Annual Update 1. Each Annual Update shall be subject to the following review procedures ( Annual Review Procedures ): (a) Each year, after the Posting Date and before June 25, AEP will convene a meeting ( Customer Meeting ) to afford interested parties (e.g., Transmission Customers and affected state and federal regulatory authorities) an opportunity to discuss and become better informed regarding the Annual Update; Issued by: Issued on: L. Patrick Bourne, Manager, Effective:

Exhibit No. AEP 101A Page 8 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.3 FERC Electric Tariff (b) (c) (d) (e) Interested parties will have seventyfive (75) days after the Customer Meeting to serve reasonable information requests on AEP for information and workpapers supporting an Annual Update. Such information requests shall be limited to that which is necessary to determine if AEP has properly calculated the Annual Update under review (including any corrections pursuant to Section I.6). Further, such information requests shall not include requests for information related to Annual Updates from prior years except (i) to determine whether a prior year s approach on a given matter was the same or different from the current year s approach, or (ii) in connection with corrections pursuant to Section I.6. AEP shall make a good faith effort to respond to information requests pertaining to an Annual Update within fifteen (15) business days of receipt of such requests. Information requests received after 4 p.m. CPT shall be considered received the next business day. To the extent AEP and any interested party(ies) are unable to resolve disputes related to information requests submitted in accordance with these Annual Review Procedures, AEP or any interested party may petition the FERC to appoint an Administrative Law Judge as a discovery master. The discovery master shall have the power to issue binding orders to resolve discovery disputes and compel the production of discovery, as appropriate, in accordance with the Annual Review Procedures and consistent with the FERC s discovery rules. Any interested party shall have until the later of ninety (90) days after the Customer Meeting or fifteen (15) days after AEP s last response to reasonable information requests submitted pursuant to Section II.1(b) above, to review the calculation of the Annual Update ( Review Period ) and to notify AEP in writing of any specific challenges to the Annual Update ( Issues ). Challenges to the Formula itself shall not be considered Issues for purposes of these Annual Review Procedures. III. Resolution of Challenges For each Annual Update: 1. If AEP and any interested party(ies) have not resolved all Issues identified pursuant to Section II.1(e) above within sixty (60) days after the Review Period for a given Annual Update, the interested party(ies) may file a complaint challenging the Annual Update, with regard to such Issue(s), in a proceeding at the FERC ( Formal Challenge ). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 101A Page 9 of 44 Southwest Power Pool pro forma Original Sheet No. 161C.4 FERC Electric Tariff (a) A party may file a Formal Challenge for a limited period of up to three (3) months after the sixtyday resolution period has ended. A party may not, thereafter, file a Formal Challenge as to the disputed Issue(s) for the then effective Rate Year. Failure to pursue an Issue or lodge a Formal Challenge regarding an Issue(s) as to a given Annual Update shall not bar pursuit of such Issue or the lodging of a Formal Challenge as to such Issue(s) as relates to a subsequent Annual Update review. (b) All information produced pursuant to these Protocols may be included in any Formal Challenge. 2. In any proceeding ordered by the FERC in response to a Formal Challenge, AEP will bear the burden of proving that it has properly calculated the challenged Annual Update pursuant to the Formula. Challenges to the Formula itself shall not be considered Formal Challenges for purposes of these Annual Review Procedures, and shall be subject to the Commission s Rules and Regulations applicable to filings pursuant to 18 C.F.R. 385.206. 3. Each Annual Update shall become final and shall no longer be subject to challenge on the later to occur of: (i) passage of the time specified in III.1(a) above for a Formal Challenge, if no such Formal Challenge has been filed and the FERC has not itself initiated a proceeding to consider the Annual Update; or (ii) the issuance of a final FERC order in response to a Formal Challenge or a proceeding initiated by the FERC to consider the Annual Update. 4. Any refunds or surcharges resulting from a Formal Challenge shall be calculated, with interest, from the effective date of the challenged Annual Update, and shall be reflected in the Annual Update for the next effective Rate Year. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Issued by: L. Patrick Bourne, Director Issued on: Effective:.. AEP Transmission Formula Rate Template For rates effective July 1, Attachment H & T Support Page 1 of 1 SPP Zone 1 AEP Revenue Requirements AEP Annual PSO Annual SWEPCO Annual Line Revenue Revenue Revenue No. Requirement Requirement Requirement A. Network Service 1 REVENUE REQUIREMENT (w/o incentives) (TCOS Line 1 ) 2 LESS: REVENUE CREDITS (TCOS Line 5 ) 3 CURRENT YEAR ZONE 1 AEP NETWORK SERVICE REVENUE REQUIREMENT (TCOS Line 6 ) 4 LESS: REVENUE REQUIREMENTS INCLUDED IN LINE 1 FOR: 5 BASE PLAN UPGRADES (W/O INCENTIVES) (TCOS Line 7 ) 6 REQUESTED UPGRADES (W/O INCENTIVES) (Worksheet F) 7 ECONOMIC UPGRADES (W/O INCENTIVES) (Worksheet F) 8 SUBTOTAL 9 EXISTING ZONAL ATRR (W/O INCENTIVES) (Line 3 Line 8) 10 INCENTIVE REVENUE REQUIREMENT FOR ZONAL PROJECTS (TCOS ln 16) 11 EXISTING ZONAL ATRR (W/ INCENTIVES) (Line 9 + Line 10) 12 HISTORICAL YEAR (2006) ACTUAL ATRR 13 PROJECTED (2006) ATRR FROM PRIOR YEAR Input from Prior Year 14 PRIOR YEAR TRUEUP (Line 12 Line 13) 15 INTEREST ON PRIOR YEAR TRUE UP 16 EXISTING ZONAL ATRR FOR SPP OATT ATTACHMENT H, SEC. 1, COL. 3 (Ln 11 + Ln 14 + Ln 15) B. PointtoPoint Service 17 2007 Projected AEP West Zone SPP Average 12Mo. Peak Demand (Load WS, ln 11) MW 18 Annual PointtoPoint Rate in $/MW Year (Line 16 / Line 17) 19 Monthly PointtoPoint Rate in $/MW Month (Line 18 / 12) 20 Weekly PointtoPoint Rate in $/MW Weekly (Line 19 / 52) 21 Daily OnPeak PointtoPoint Rate in $/MW Day (Line 20 / 260) 22 Daily OffPeak PointtoPoint Rate in $/MW Day (Line 21 / 365) 23 Hourly OnPeak PointtoPoint Rate in $/MW Hour (Line 22 / 4160) 24 Hourly OffPeak PointtoPoint Rate in $/MW Hour (Line 23 / 8760) C. SPP Regional Service 25 BASE PLAN UPGRADE ATRR W/O INCENTIVES (Line 8) 26 ADDITIONAL ATRR FOR FERCAPPROVED INCENTIVES ON BPU (Worksheet G) 27 BASE PLAN UPGRADE ATRR FOR SPP COLLECTION UNDER SCHEDULE 11 Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.1 Exhibit No. AEP 101A Page 10 of 44

Issued by: L. Patrick Bourne, Director Issued on: Effective: AEP Transmission Formula Rate Template For rates effective July 1, Schedule 1 Support Page 1 of 1 SPP SCHEDULE 1 AEP Revenue Requirements AEP Annual PSO Annual SWEPCO Annual Line Revenue Revenue Revenue No. Requirement Requirement Requirement A. Schedule 1 ARR 1 Total Load Dispatch & Scheduling (Account 561) (TCOS Line 76) 2 Less: Load Disptach Scheduling, System Control and Dispatch Services (321.88.b) 3 Less: Load Disptach Reliability, Planning & Standards Development Services (321.92.6) 4 Total 561 Internally Developed Costs (Line 1Line 2Line 3) 5 Less: PTP Service Credit 6 EXISTING ZONAL ARR (Line 4 Line 5) 7 HISTORICAL YEAR (2006) ACTUAL ARR 8 PROJECTED (2006) ARR FROM PRIOR YEAR 9 PRIOR YEAR TRUEUP 10 INTEREST ON PRIOR YEAR TRUE UP 11 Net Schedule 1 Revenue Requirement for Zone B. Schedule 1 Rate Calculations 12 2007 Projected AEP West Zone SPP Average 12Mo. Peak Demand (LOAD WS, Line 11) MW 13 Annual PointtoPoint Rate in $/MW Year (Line 11 / Line 12) 14 Monthly PointtoPoint Rate (ln 13 / 12) $/MW Month (Line 13 / 12) 15 Weekly PointtoPoint Rate (ln 13 / 52) $/MW Weekly (Line 13 / 52) 16 Daily OffPeak PointtoPoint Rate (ln 13 / 365) $/MW Day (Line 13 / 365) 17 Hourly OffPeak PointtoPoint Rate (ln 13 / 8760) $/MW Hour (Line 13 / 8760) Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.2 Exhibit No. AEP 101A Page 11 of 44

Issued by: L. Patrick Bourne, Director Issued on: Effective: AEP Companies: PSO and SWEPCO Network Load for January Through December, Based on West ZoneSPP Monthly Transmission System Firm Peak Demands (1) for the Twelve Months Ended December 31, Projected Combined Load Worksheet Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Peak Day 12 Month Line Peak Hour *projected *projected *projected *projected *projected *projected *projected *projected Average MW No. SPP Load Responsibility 1 PSO 2 SWEPCO 3 TNCN 4 OMPA 5 NTEC 6 ETEC 7 TEXLA 8 Greenbelt 9 Lighthouse 10 Coffeyville, KS (OATT Firm PTP) (2) 11 Zone 1 System Firm Peak Demands Historical Combined Load Worksheet Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Peak Day 12 Month Line Peak Hour Average MW No. SPP Load Responsibility 12 PSO 13 SWEPCO 14 TNCN 15 OMPA 16 NTEC 17 ETEC 18 TEXLA 19 Greenbelt 20 Lighthouse 21 Coffeyville, KS (OATT Firm PTP) (2) 22 Zone 1 System Firm Peak Demands Supporting Data 23 PSO: PSO Native Load 24 KAMO 25 WFEC 26 PSO Load Responsibility 27 SWEPCO: SWEPCO Native Load 28 Less: NTEC 29 Less: ETEC 30 Less: TEXLA 31 AECC 32 LaGen (Formerly Cajun) 33 Lafayette 34 Dolet Hills Aux. Load (not selfgenerated 35 SWEPCO Load Responsibility 36 TNC TNC North Native Load 37 TNC North Load Responsibility 38 Coffeyville Actual Load (2) Notes: (1) MW, at the time of the AEPSPP Native Peak. At the generator. Transmission losses added to metered values which include appropriate dist.& xfmr losses. (2) Net load from East and West Coffeyville ties, not included in AEP Control Area. Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.3 Exhibit No. AEP 101A Page 12 of 44

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 13 of 44 pro forma Original Sheet No. 161D.4 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 1 of 10 Plus Capital Additions for PROJECTED Company: Line No. 1 REVENUE REQUIREMENT (w/o incentives) (ln 128) Transmission Amount 2 REVENUE CREDITS (Note A) Total Allocator 3 Transmission Credits (Worksheet A) DA 4 Assoc. Business Development (Worksheet A) DA 5 Total Revenue Credits 6 REVENUE REQUIREMENT (w/o incentives) For All AEP Facilities (ln 1 less ln 5) 7 Revenue Requirement for SPP Base Plan Upgrades (w/o incentives) (Worksheet G) DA 8 REVENUE REQUIREMENT EXCLUDING BASE PLAN UPGRADE ATRR (ln 6 less ln 7) 9 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 10 Annual Rate (ln 6 / ln 42 x 100) 11 Monthly Rate (ln 10 / 12) 12 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 13 Annual Rate ( (ln 6 ln 98) / ln 42 x 100) 14 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 15 Annual Rate ( (ln 6 ln 98 ln 122 ln 123) / ln 42 x 100) 16 ADDITIONAL REVENUE REQUIREMENT for projects w/ incentive ROE's (Note C) (Worksheet F) NA 17 PROJECTED YE 2007 TRANSMISSION REVENUE REQUIREMENT (ln 8 + ln 16) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 2 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101A Page 14 of 44 pro forma Original Sheet No. 161D.5 Company: (1) (2) (3) (4) (5) Data Sources Total RATE BASE CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. GROSS PLANT IN SERVICE 18 Production 205.46.g NA 19 Transmission 207.58.g DA 20 Plus: Transmission PlantinService Additions (Worksheet H) DA 21 Plus: Additional Trans Plant on Transferred Assets (Worksheet H) DA 22 Distribution 207.75.g NA 23 General Plant 207.99.g (Note K) W/S 24 Intangible Plant 205.5.g W/S 25 Common 356 CE 26 TOTAL GROSS PLANT (sum lns 18 to 25) GP(p)= GTD(p)= 27 ACCUMULATED DEPRECIATION AND AMORTIZATION 28 Production 219.2024.c NA 29 Transmission 219.25.c TP1= 30 Plus: Transmission PlantinService Additions (Worksheet H) DA 31 Plus: Additional Projected Deprec on Transferred Assets (Worksheet H) DA 32 Plus: Additional Transmission Depreciation for 2007 (ln 98) TP1 33 Plus: Additional General & Intangible Depreciation for 2007 (ln 100 + ln 101) W/S 34 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) DA 35 Distribution 219.26.c NA 36 General Plant 219.28.c (Note K) W/S 37 Intangible Plant 219 W/S 38 Common 356 CE 39 TOTAL ACCUMULATED DEPRECIATION (sum lns 28 to 38) 40 NET PLANT IN SERVICE 41 Production (ln 18 ln 28) 42 Transmission (ln 19 ln 29) 43 Plus: Transmission PlantinService Additions (ln 20 ln 30) 44 Plus: Additional Trans Plant on Transferred Assets (ln 21 ln 31) 45 Plus: Additional Transmission Depreciation for 2007 (ln 32) 46 Plus: Additional General & Intangible Depreciation for 2007 (ln 33) 47 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) (ln 34) 48 Distribution (ln 22 ln 35) 49 General Plant (ln 23 ln 36) 50 Intangible Plant (ln 24 ln 37) 51 Common (ln 25 ln 38) 52 TOTAL NET PLANT IN SERVICE (sum lns 41 to 51) NP(p)= 53 ADJUSTMENTS TO RATE BASE (Note D) 54 Account No. 281 (enter negative) 273.8.k (Worksheet C) DA 55 Account No. 282 (enter negative) 275.2.k (Worksheet C) DA 56 Account No. 283 (enter negative) 277.9.k (Worksheet C) DA 57 Account No. 190 234.8.c (Worksheet C) DA 58 Account No. 255 (enter negative) 267.8.h (Worksheet C) DA 59 Account 107 for Approved MultiYear Projects 216.43.b (Worksheet K) DA 60 Other Additions/Deductions (Note E) DA 61 TOTAL ADJUSTMENTS (sum lns 54 to 60) 62 PLANT HELD FOR FUTURE USE 214.x.d (Note F) DA 63 WORKING CAPITAL (Note G) 64 Cash Working Capital (1/8 * ln 96) 65 Transmission Materials & Supplies 227.8.c TP 66 A&G Materials & Supplies 227.11.c W/S 67 Undistributed Stores Expense (Acct 163) 227.16.c GP(h) 68 Prepayments (Account 165) Labor Allocated 111.57.c (Worksheet I) W/S 69 Prepayments (Account 165) Direct Allocated 111.57.c (Worksheet I) DA 70 Prepayments (Account 165) Gross Plant 111.57.c (Worksheet I) GP(h) 71 TOTAL WORKING CAPITAL (sum lns 64 to 70) 72 IPP CONTRIBUTIONS FOR CONSTRUCTION #REF! DA 73 RATE BASE (sum lns 52, 61, 62, 71, 72) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 3 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101A Page 15 of 44 pro forma Original Sheet No. 161D.6 Company: (1) (2) (3) (4) (5) EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. OPERATION & MAINTENANCE EXPENSE 74 Transmission 321.112.b TP 75 Less: expenses 100% assigned to TO billed customers (Worksheet E, ln 14) DA 76 Less: Total Account 561 (Load Dispatch Sch 1) (Note I) 321.8492.b TP 77 Less: Account 565 321.96.b (Note J) TP 78 Plus: Acct 565 native load, zonal or pool (Note J) DA 79 Transmission Subtotal (lns 74757677+78) 80 Administrative and General 323.197.b (Note K) 81 Less: Acc. 928, Reg. Com. Exp. 323.189.b 82 Acct. 930.1, Gen. Advert. Exp. 323.191.b 83 Acc. 924, Property Insurance 323.185.b 84 Acc. 930.2, Misc. Gen. Exp. 323.192.b 85 Acc. 935, Maint. of Gen. Plant 323.196.b W/S 86 Balance of A & G (ln 80 sum ln 81 to ln 85) W/S 87 Plus: Acct. 924, Property Insurance (ln 83) NP(h) 88 Acct. 928 Transmission Specific (Note L) (Worksheet D) TP 89 Acct. 928 Transmission Allocated (Note L) (Worksheet D) GP(h) 90 Acct 930.1 Only safety related ads. (Note L) (Worksheet D) W/S 91 Acct 930.2 Misc Gen. Exp. Trans (Worksheet D) TP 92 Acct 930.2 Misc Gen. Exp. Allocated (Worksheet D) W/S 93 A & G Subtotal (sum lns 84 to 90) 94 Common 356 CE 95 Transmission Lease Payments DA 96 TOTAL O & M EXPENSE (ln 79 + ln 93 + ln 94 + ln 95) 97 DEPRECIATION AND AMORTIZATION EXPENSE 98 Transmission 336.7.f TP 99 Plus: Transmission PlantinService Additions (Worksheet H) DA 100 General 336.10.f W/S 101 Intangible 336.1.f W/S 102 Common 336.11.f CE 103 TOTAL DEPRECIATION AND AMORTIZATIN (sum lns 98 to 102) 104 TAXES OTHER THAN INCOME (Note M) 105 Labor Related 106 Payroll 262.x263.x.i W/S 107 Plant Related 108 Property 262.x263.x.i NP(h) 109 Gross Receipts/Sales & Use 262.x263.x.i NA 110 Other 262.x263.x.i GP(h) 111 Payments in lieu of taxes GP(h) 112 TOTAL OTHER TAXES 114.14.c 113 INCOME TAXES (Note N) 114 T=1 {[(1 SIT) * (1 FIT)] / (1 SIT * FIT * p)} = 115 EIT=(T/(1T)) * (1(WCLTD/WACC)) = 116 where WCLTD=(ln 158) and WACC = (ln 161) 117 and FIT, SIT & p are as given in Note N. 118 GRCF=1 / (1 T) = (from ln 114) 119 Amortized Investment Tax Credit (enter negative) 120 Income Tax Calculation (ln 115 * ln 123) 121 ITC adjustment (ln 118 * ln 119) NP(h) 122 TOTAL INCOME TAXES (sum lns 120 to 121) 123 RETURN ON RATE BASE (Rate Base*WACC) (ln 73 * ln 161) 124 INTEREST ON IPP CONTRIBUTION FOR CONST. (Note H) (Worksheet B, ln 16) DA 125 REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX 126 (sum lns 96, 103, 112, 122, 123, 124) 127 TEXAS GROSS MARGIN TAX (NOTE O) (Worksheet J) DA 128 REVENUE REQUIREMENT INCLUDING GROSS MARGIN TAX Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 4 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101A Page 16 of 44 pro forma Original Sheet No. 161D.7 Company: SUPPORTING CALCULATIONS ln No. TRANSMISSION PLANT INCLUDED IN SPP TARIFF 129 Total transmission plant (ln 19 + ln 20 + ln 21) 130 Less transmission plant excluded from SPP Tariff (Note P) 131 Less transmission plant included in OATT Ancillary Services (Note Q ) (Worksheet L) 132 Transmission plant included in SPP Tariff (ln 129 ln 130 ln 131) 133 Percent of transmission plant in SPP Tariff (ln 132 / ln 129) TP= 134 WAGES & SALARY ALLOCATOR (W/S) (Note R) Direct Payroll Payroll Billed from AEP Service Corp. 135 Production 354.20,22.b NA 136 Transmission 354.21.b TP 137 Distribution 354.23.b NA 138 Other (Excludes A&E 354.24,25,26.b NA 139 Total (sum lns 135 to 138) 140 Transmission related amount W/S= 141 COMMON PLANT ALLOCATOR (CE) 142 Electric 200.3.c DA 143 Gas 200.3.d NA 144 Other 200.3. e, f, g NA 145 Total (sum lns 142 to 144) 146 Electric related amount 147 W/S Allocator W/S 148 Transmission related amount (ln 146 * ln 147) CE= 149 WEIGHTED AVERAGE COST OF CAPITAL (WACC) $ 150 Long Term Interest (117, sum of 62c 66c) 151 Preferred Dividends (118.29.c) (positive number) 152 Development of Common Stock: 153 Proprietary Capital (112.16.c) 154 Less Preferred Stock (ln 159) 155 Less Account 219.1 (112.15.c) 156 Common Stock (ln 153 ln 154 ln 155) Cost 157 $ % (Note S) Weighted 158 Long Term Debt (112, sum of 18.c 21.c) 159 Preferred Stock (112.3.c) 160 Common Stock (ln 156) 161 Total (sum lns 158 to 160) WACC= Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 5 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101A Page 17 of 44 pro forma Original Sheet No. 161D.8 Company: Letter A B C D E F Notes General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# b) If transmission owner ("TO") functionalizes its costs to transmission on its books, those costs are shown above and on any supporting workpapers rather than using the allocations above. The revenue credits shall include a) amounts received directly from the SPP for PTP transmission services, b) direct assignment charges for transmission facilities, the cost of which has been included in the TCOS, and c) amounts from customers taking service under grandfathered agreements, where the demand is not included in the rate divisor. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or facilities excluded from the TCOS are not included as revenue credits. Revenue from Transmission Customers whose coincident peak loads are included in the DIVISOR of the loadratio share calculation are not included as revenue credits. See Worksheet A for details. The annual and monthly net plant carrying charges on page 1 are used to compute the revenue requirement for facilities and any upgrades. This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet F shows the calculation of the additional incentive revenue requirement for each project receiving incentive rate treatment, as accepted by FERC. These individual additional revenue requirements shall be summed, for the projected year, and included here. Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, 255 and, if applicable, 107. The balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. An exception to this is pre1971 ITC balances, which are required to be taken as an offset to rate base. Account 281 is not allocated. Transmission allocations are shown on Worksheet C. Include Account 182.3, Other Regulatory Assets, related to Transmission Service under this Tariff, if any. Also include any unamortized balances related to precommercial operation costs when recovery of abandonment costs are granted. Identified as being transmission related or functionally booked to transmission. G Cash Working Capital assigned to transmission is oneeighth of O&M allocated to transmission on line 96. H Consistent with Paragraph 657 of Order 2003A, the amount on line 72 is equal to the balance of IPP System Upgrade Credits owed to transmission customers that made contributions toward the construction of System upgrades, and includes accrued interest and unreturned balance of contributions. The annual interest expense is included on line 124. I Removes the expense booked to transmission accounts included in the development of OATT ancillary services rates, including all of Account No. 561. J K L M Removes cost of transmission service provided by others to the extent such service is not incurred to provide the SPP service at issue. General Plant and Administrative & General expenses may be functionalized based on allocators other then the W/S allocator. Full documentation must be provided. Includes Regulatory Commission expenses itemized in FERC Form1 at page 351, column H. Worksheet D allocates these expense items. FERC Assessment Fees and Annual Charges shall not be allocated to transmission. Only safetyrelated and educational advertising costs in Account 930.1 are included in the TCOS. Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax and taxes related to income are excluded. N The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 119) multiplied by (1/1T). If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= 0.00% (State Income Tax Rate or Composite SIT. Worksheet J)) p = 0.00% (percent of federal income tax deductible for state purposes) O P Effective January 1, 2007, Texas instituted a gross margin tax. This tax is calculated on the Texas allocated revenue of the Company, reduced by 30% to derive a "Gross Margin" for the Company. The tax rate of one percent is assessed on the resulting amount. The jurisdictional allocator is based on transmission demand allocators. Removes plant excluded from the OATT because it does not meet the SPP's definition of Transmission Facilities or is otherwise ineligible to be recovered under the OATT. Q Removes transmission plant (e.g. stepup transformers) included in the development of OATT ancillary service rates and not already removed for reasons indicated in Note P. R Includes functional wages & salaries incurred by parent company service corporation for support of the operating company. S Long Term Debt cost rate = longterm interest (ln 150) / long term debt (ln 158). Preferred Stock cost rate = preferred dividends (ln 151) / preferred outstanding (ln 159). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 18 of 44 pro forma Original Sheet No. 161D.9 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 6 of 10 Historical Transmission Cost of Service HISTORICAL Company: Line No. 162 REVENUE REQUIREMENT (w/o incentives) (ln 286) Transmission Amount 163 REVENUE CREDITS (Note A) Total Allocator 164 Transmission Credits (Worksheet A) DA 165 Assoc. Business Development (Worksheet A) DA 166 Total Revenue Credits 167 REVENUE REQUIREMENT (w/o incentives) For All AEP Facilities (ln 162 less ln 166) 168 Revenue Requirement for SPP Base Plan Upgrades (w/o incentives) (Worksheet G) DA 169 REVENUE REQUIREMENT EXCLUDING BASE PLAN UPGRADE ATRR (ln 167 less ln 168) 170 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 171 Annual Rate (ln 167 / ln 203 x 100) 172 Monthly Rate (ln 171 / 12) 173 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 174 Annual Rate ( (ln 167 ln 259) / ln 203 x 100) 175 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 176 Annual Rate ( (ln 167 ln 259 ln 283 ln 284) / ln 203 x 100) 177 ADDITIONAL REVENUE REQUIREMENT for projects w/ incentive ROE's (Note C) (Worksheet F) NA 178 HISTORICAL YE 2006 TRANSMISSION REVENUE REQUIREMENT (ln 169 + ln 177) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 19 of 44 pro forma Original Sheet No. 161D.10 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 7 of 10 Historical Transmission Cost of Service HISTORICAL Company: (1) (2) (3) (4) (5) Data Sources Total RATE BASE CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. GROSS PLANT IN SERVICE 179 Production 205.46.g NA 180 Transmission 207.58.g DA 181 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 182 Plus: Additional Trans Plant on Transferred Assets (Worksheet H) N/A DA N/A 183 Distribution 207.75.g NA 184 General Plant 207.99.g (Note K) W/S 185 Intangible Plant 205.5.g W/S 186 Common 356 CE 187 TOTAL GROSS PLANT (sum lns 179 to 186) GP(h)= GTD= 188 ACCUMULATED DEPRECIATION AND AMORTIZATION 189 Production 219.2024.c NA 190 Transmission 219.25.c TP1= 191 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 192 Plus: Additional Projected Deprec on Transferred Assets (Worksheet H) N/A DA N/A 193 Plus: Additional Transmission Depreciation for 2007 (ln 259) N/A TP1 N/A 194 Plus: Additional General & Intangible Depreciation for 2007 (ln 261 + ln 262) N/A W/S N/A 195 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) N/A DA N/A 196 Distribution 219.26.c NA 197 General Plant 219.28.c (Note K) W/S 198 Intangible Plant 219 W/S 199 Common 356 CE 200 TOTAL ACCUMULATED DEPRECIATION (sum lns 189 to 199) 201 NET PLANT IN SERVICE 202 Production (ln 179 ln 189) 203 Transmission (ln 180 ln 190) 204 Plus: Transmission PlantinService Additions (ln 181 ln 191) N/A N/A 205 Plus: Additional Trans Plant on Transferred Assets (ln 182 ln 192) N/A N/A 206 Plus: Additional Transmission Depreciation for 2007 (ln 193) N/A N/A 207 Plus: Additional General & Intangible Depreciation for 2007 (ln 194) N/A N/A 208 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) (ln 195) N/A N/A 209 Distribution (ln 183 ln 196) 210 General Plant (ln 184 ln 197) 211 Intangible Plant (ln 185 ln 198) 212 Common (ln 186 ln 199) 213 TOTAL NET PLANT IN SERVICE (sum lns 202 to 212) NP(h)= 214 ADJUSTMENTS TO RATE BASE (Note D) 215 Account No. 281 (enter negative) 273.8.k (Worksheet C) DA 216 Account No. 282 (enter negative) 275.2.k (Worksheet C) DA 217 Account No. 283 (enter negative) 277.9.k (Worksheet C) DA 218 Account No. 190 234.8.c (Worksheet C) DA 219 Account No. 255 (enter negative) 267.8.h (Worksheet C) DA 220 Account 107 for Approved MultiYear Projects 216.43.b (Worksheet K) DA 221 Other Additions/Deductions (Note E) DA 222 TOTAL ADJUSTMENTS (sum lns 215 to 221) 223 PLANT HELD FOR FUTURE USE 214.x.d (Note F) DA 224 WORKING CAPITAL (Note G) 225 Cash Working Capital (1/8 * ln 257) 226 Transmission Materials & Supplies 227.8.c TP 227 A&G Materials & Supplies 227.11.c W/S 228 Undistributed Stores Expense (Acct 163) 227.16.c GP(h) 229 Prepayments (Account 165) Labor Allocated 111.57.c (Worksheet I) W/S 230 Prepayments (Account 165) Direct Allocated 111.57.c (Worksheet I) DA 231 Prepayments (Account 165) Gross Plant 111.57.c (Worksheet I) GP(h) 232 TOTAL WORKING CAPITAL (sum lns 225 to 231) 233 IPP CONTRIBUTIONS FOR CONSTRUCTION #REF! DA 234 RATE BASE (sum lns 213, 222, 223, 232, 233) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 20 of 44 pro forma Original Sheet No. 161D.11 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 8 of 10 Historical Transmission Cost of Service HISTORICAL Company: (1) (2) (3) (4) (5) EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. OPERATION & MAINTENANCE EXPENSE 235 Transmission 321.112.b TP 236 Less: expenses 100% assigned to TO billed customers (Worksheet E, ln 14) DA 237 Less: Total Account 561 (Load Dispatch Sch 1) (Note I) 321.8492.b TP 238 Less: Account 565 321.96.b (Note J) TP 239 Plus: Acct 565 native load, zonal or pool (Note J) DA 240 Transmission Subtotal (lns 235236237238+239) 241 Administrative and General 323.197.b (Note K) 242 Less: Acc. 928, Reg. Com. Exp. 323.189.b 243 Acct. 930.1, Gen. Advert. Exp. 323.191.b 244 Acc. 924, Property Insurance 323.185.b 245 Acc. 930.2, Misc. Gen. Exp. 323.192.b 246 Acc. 935, Maint. of Gen. Plant 323.196.b W/S 247 Balance of A & G (ln 241 sum ln 242 to ln 246) W/S 248 Plus: Acct. 924, Property Insurance (ln 244) NP(h) 249 Acct. 928 Transmission Specific (Note L) (Worksheet D) TP 250 Acct. 928 Transmission Allocated (Note L) (Worksheet D) GP(h) 251 Acct 930.1 Only safety related ads. (Note L) (Worksheet D) W/S 252 Acct 930.2 Misc Gen. Exp. Trans (Worksheet D) TP 253 Acct 930.2 Misc Gen. Exp. Allocated (Worksheet D) W/S 254 A & G Subtotal (sum lns 246 to 253) 255 Common 356 CE 256 Transmission Lease Payments DA 257 TOTAL O & M EXPENSE (ln 240 + ln 254 + ln 255 + ln 256) 258 DEPRECIATION AND AMORTIZATION EXPENSE 259 Transmission 336.7.f TP 260 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 261 General 336.10.f W/S 262 Intangible 336.1.f W/S 263 Common 336.11.f CE 264 TOTAL DEPRECIATION AND AMORTIZATIN (sum lns 259 to 263) 265 TAXES OTHER THAN INCOME (Note M) 266 Labor Related 267 Payroll 262.x263.x.i W/S 268 Plant Related 269 Property 262.x263.x.i NP(h) 270 Gross Receipts/Sales & Use 262.x263.x.i NA 271 Other 262.x263.x.i GP(h) 272 Payments in lieu of taxes GP(h) 273 TOTAL OTHER TAXES 114.14.c 274 INCOME TAXES (Note N) 275 T=1 {[(1 SIT) * (1 FIT)] / (1 SIT * FIT * p)} = 276 EIT=(T/(1T)) * (1(WCLTD/WACC)) = 277 where WCLTD=(ln 319) and WACC = (ln 322) 278 and FIT, SIT & p are as given in Note N. 279 GRCF=1 / (1 T) = (from ln 275) 280 Amortized Investment Tax Credit (enter negative) 281 Income Tax Calculation (ln 276 * ln 284) 282 ITC adjustment (ln 279 * ln 280) NP(h) 283 TOTAL INCOME TAXES (sum lns 281 to 282) 284 RETURN ON RATE BASE (Rate Base*WACC) (ln 234 * ln 322) 285 INTEREST ON IPP CONTRIBUTION FOR CONST. (Note H) (Worksheet B, ln 16) DA 286 REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX 287 (sum lns 257, 264, 273, 283, 284, 285) 288 TEXAS GROSS MARGIN TAX (NOTE O) (Worksheet J) DA 289 REVENUE REQUIREMENT INCLUDING GROSS MARGIN TAX Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 21 of 44 pro forma Original Sheet No. 161D.12 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 9 of 10 Historical Transmission Cost of Service HISTORICAL Company: SUPPORTING CALCULATIONS ln No. TRANSMISSION PLANT INCLUDED IN SPP TARIFF 290 Total transmission plant (ln 180) 291 Less transmission plant excluded from SPP Tariff (Note P) 292 Less transmission plant included in OATT Ancillary Services (Note Q ) (Worksheet L) 293 Transmission plant included in SPP Tariff (ln 290 ln 291 ln 292) 294 Percent of transmission plant in SPP Tariff (ln 293 / ln 290) TP= 295 WAGES & SALARY ALLOCATOR (W/S) (Note R) Direct Payroll Payroll Billed from AEP Service Corp. 296 Production 354.20,22.b NA 297 Transmission 354.21.b TP 298 Distribution 354.23.b NA 299 Other (Excludes A&E 354.24,25,26.b NA 300 Total (sum lns 296 to 299) 301 Transmission related amount W/S= 302 COMMON PLANT ALLOCATOR (CE) 303 Electric 200.3.c DA 304 Gas 200.3.d NA 305 Other 200.3. e, f, g NA 306 Total (sum lns 303 to 305) 307 Electric related amount 308 W/S Allocator W/S 309 Transmission related amount (ln 307 * ln 308) CE= 310 WEIGHTED AVERAGE COST OF CAPITAL (WACC) $ 311 Long Term Interest (117, sum of 62c 66c) 312 Preferred Dividends (118.29.c) (positive number) 313 Development of Common Stock: 314 Proprietary Capital (112.16.c) 315 Less Preferred Stock (ln 320) 316 Less Account 219.1 (112.15.c) 317 Common Stock (ln 314 ln 315 ln 316) Cost 318 $ % (Note S) Weighted 319 Long Term Debt (112, sum of 18.c 21.c) 320 Preferred Stock (112.3.c) 321 Common Stock (ln 317) 322 Total (sum lns 319 to 321) WACC= Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 22 of 44 pro forma Original Sheet No. 161D.13 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 10 of 10 Historical Transmission Cost of Service HISTORICAL Company: Letter A B C D E F Notes General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# b) If transmission owner ("TO") functionalizes its costs to transmission on its books, those costs are shown above and on any supporting workpapers rather than using the allocations above. The revenue credits shall include a) amounts received directly from the SPP for PTP transmission services, b) direct assignment charges for transmission facilities, the cost of which has been included in the TCOS, and c) amounts from customers taking service under grandfathered agreements, where the demand is not included in the rate divisor. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or facilities excluded from the TCOS are not included as revenue credits. Revenue from Transmission Customers whose coincident peak loads are included in the DIVISOR of the loadratio share calculation are not included as revenue credits. See Worksheet A for details. The annual and monthly net plant carrying charges on page 1 are used to compute the revenue requirement for facilities and any upgrades. This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet F shows the calculation of the additional incentive revenue requirement for each project receiving incentive rate treatment, as accepted by FERC. These individual additional revenue requirements shall be summed, for the projected year, and included here. Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, 255 and, if applicable, 107. The balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. An exception to this is pre1971 ITC balances, which are required to be taken as an offset to rate base. Account 281 is not allocated. Transmission allocations are shown on Worksheet C. Include Account 182.3, Other Regulatory Assets, related to Transmission Service under this Tariff, if any. Also include any unamortized balances related to precommercial operation costs when recovery of abandonment costs are granted. Identified as being transmission related or functionally booked to transmission. G Cash Working Capital assigned to transmission is oneeighth of O&M allocated to transmission on line 257. H Consistent with Paragraph 657 of Order 2003A, the amount on line 233 is equal to the balance of IPP System Upgrade Credits owed to transmission customers that made contributions toward the construction of System upgrades, and includes accrued interest and unreturned balance of contributions. The annual interest expense is included on line 285. I Removes the expense booked to transmission accounts included in the development of OATT ancillary services rates, including all of Account No. 561. J K L M Removes cost of transmission service provided by others to the extent such service is not incurred to provide the SPP service at issue. General Plant and Administrative & General expenses may be functionalized based on allocators other then the W/S allocator. Full documentation must be provided. Includes Regulatory Commission expenses itemized in FERC Form1 at page 351, column H. Worksheet D allocates these expense items. FERC Assessment Fees and Annual Charges shall not be allocated to transmission. Only safetyrelated and educational advertising costs in Account 930.1 are included in the TCOS. Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax and taxes related to income are excluded. N The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 280) multiplied by (1/1T). If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= 0.00% (State Income Tax Rate or Composite SIT. Worksheet J)) p = 0.00% (percent of federal income tax deductible for state purposes) O P Effective January 1, 2007, Texas instituted a gross margin tax. This tax is calculated on the Texas allocated revenue of the Company, reduced by 30% to derive a "Gross Margin" for the Company. The tax rate of one percent is assessed on the resulting amount. The jurisdictional allocator is based on transmission demand allocators. Removes plant excluded from the OATT because it does not meet the SPP's definition of Transmission Facilities or is otherwise ineligible to be recovered under the OATT. Q Removes transmission plant (e.g. stepup transformers) included in the development of OATT ancillary service rates and not already removed for reasons indicated in Note P. R Includes functional wages & salaries incurred by parent company service corporation for support of the operating company. S Long Term Debt cost rate = longterm interest (ln 311) / long term debt (ln 319). Preferred Stock cost rate = preferred dividends (ln 312) / preferred outstanding (ln 320). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101A Page 23 of 44 pro forma Original Sheet No. 161D.14 Worksheet List: A B C D E F G H I J K L Revenue Credits IPP System Upgrade Credit ADIT & ITC Details A&G Expense Detail Transmission Expense Adjustments ATRR Calculation for NonBase Plan Projects ATRR Calculation for SPP Base Plan Upgrades Transmission PlantinService Additions NonTax Balance Sheet Adjustments Tax CWIP Balances on MultiYear Projects GSU Net Book Values Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet A Revenue Credits Added Worksheet Exhibit No. AEP 101A Page 24 of 44 pro forma Original Sheet No. 161D.15 Total Non Company Transmission Transmission I. Account 450, Forfeited Discounts $0 II. Account 451,Miscellaneous Service Revenues $0 III. Account 454, Rent from Electric Property Account 4540001 Rent from Elect PropertyAff Account 4540002 Rent from Elect Property NonAff Account 4540003 Rent from Elect Property ABD Aff Account 4540004 Rent from Elect Property ADB NonAff Total Rents from Electirc Property $0 $0 ( Revenue related to transmission facilities for pole attachments, rentals, etc. Provide data sources and explanations in Section VIII, Notes below ) IV. Account 4560015, Revenues from Associated Business Development Account 4560015, Revenues from Associated Business Development V. Total Other Operating Revenues To Reduce Revenue Requirement $0 VI. Account 456.0, Revenues from Transmission of Electricity of Others ( Provide data sources and any detailed explanations necessary in Section VIII, Notes below ) Less: TO's LSE Direct Assignment Revenue Credits TO's LSE Sponsored Upgrade Revenue Credits TO's LSE Network Upgrades for Generation Interconnection Credits TO's PointToPoint Revenue for GFA's Associated with Load Included in the Divisor Network Service Revenue (Schedule 9) Associated With Load Included in the Divisor TO's Revenue Associated with Transmission Plant Excluded From SPP Tariff Wholesale Distribution charges TO's LSE Revenue from Ancillary Services Provided Base Plan Revenue Received Other (Flow Through of ERCOT Ancillary Charges) Other Net Transmission Credits $0 VII. Total Worksheet A Revenue Credits $0 VIII. Data Sources: Data for this worksheet came from the FERC Form 1 and the Company's General Ledger. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Exhibit No. AEP 101A Page 25 of 44 pro forma Original Sheet No. 161D.16 Worksheet B IPP System Upgrade Credit Line No. Account 2530067 Transmission Owner 1 Funds from IPP Customers 2 Transimission Credits given back over the years: 3 4 5 6 7 8 $0 9 10 Net balance of IPP Funds Received Credited Back $0 11 Interest Accrued over the years: 12 13 14 15 16 17 $0 18 Net Funds from IPP Customers 12/31/2006 (FORM 1, P269, line 7(f)) $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet C ADIT & ITC Details Added Worksheet Exhibit No. AEP 101A Page 26 of 44 pro forma Original Sheet No. 161D.17 (A) (B) (C) (D) (E) (F) (G) (H) (I) 100% 100% Transmission Transmission & Transmission Total Included 2006 NonTransmission Transmission Plant Distribution Labor in Ratebase Acc. No. Description YE Balance Related Related Related Plant Related Related (F)+(G)+(H) Account 281 Subtotal Form 1, p273 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 282 Subtotal Form 1, p274 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 283 Subtotal Form 1, p277 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 190 NOTE: Insert Amounts as Negative Numbers Subtotal Form 1, p234 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 255 Subtotal Form 1, p266.8f Less Post 1971 ITC Property Under F2 Option Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Exhibit No. AEP 101A Page 27 of 44 pro forma Original Sheet No. 161D.18 Worksheet D A&G Expense Detail (A) (B) (C) (D) (E) (F) (G) 100% 100% Transmission Transmission Item No. Description Expense NonTransmission Specific Allocated Explanation Account 928 Total Account 930.1 Total Account 930.2 Total $0 $0 $0 $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Worksheet E Transmission Expense Adjustments Exhibit No. AEP 101A Page 28 of 44 pro forma Original Sheet No. 161D.19 2006 1 Other Expenses 2 Direct Assignment Charge 3 Sponsored Upgrades Charge 4 Firm and NonFirm PointToPoint Charges 5 Base Plan Charges 6 Schedule 9 Charges 7 SPP Schedule 12 FERC Assessment 8 SPP Schedule 1A 9 SPP Annual Assessment 10 Ancillary Services Expenses 11 Other 12 Other 13 Other 14 Total ( sum of lines 2 through 13 ) $0 Adjustment to charges that are booked to transmission accounts that are the responsibility of the TO's LSE. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101A Page 29 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.20 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 1 of 3 I. Calculate Return and Income Taxes with 0 basis point ROE increase. A. Determine 'R' with hypothetical 0 basis point increase in ROE for Identified Projects ROE w/o incentives (Attachment H, ln 160) 0% Project ROE Incentive Adder 0 ROE with additional 0 basis point incentive 0% Determine R ( cost of long term debt, cost of preferred stock and percent is from Attachment H, lns 158 through160) % Cost Weighted cost Long Term Debt Preferred Stock Common Stock WACC = 0.0000 B. Determine Return using 'R' with hypothetical 0 basis point ROE increase for Identified Projects. Rate Base (Attachment H, ln 73) $0 R (fom A. above) 0.0000 Return (Rate Base x R) $0 C. Determine Income Taxes using Return with hypothetical 0 basis point ROE increase for Identified Projects. Return (from B. above) $0 CIT (Attachment H, ln 115) 0.00% Income Tax Calculation (Return x CIT) $0 ITC Adjustment (Attachment H, ln 121) $0 Income Taxes $0 II. Calculate Net Plant Carrying Charge Rate (Fixed Charge Rate or FCR) with hypothetical 0 basis point ROE increase. A. Determine Net Revenue Requirement less return and Income Taxes. Net Revenue Requirement (Attachment H, ln 6) $0 Return (Attachment H, ln 123) $0 Income Taxes (Attachment H, ln 122) $0 Gross Margin Taxes (Attachment H, ln 127) $0 Net Revenue Requirement, Less Return and Taxes $0 B. Determine Net Revenue Requirement with hypothetical 0 basis point increase in ROE. Net Revenue Requirement, Less Return and Taxes $0 Return (from I.B. above) $0 Income Taxes (from I.C. above) $0 Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase Gross Margin Tax with 0 Basis Point ROE Increase (II C. below) $0 Revenue Requirement w/ Gross Margin Taxes $0 Less: Depreciation (Attachment H, ln 98) $0 Net Rev. Req, w/0 Basis Point ROE increase, less Depreciation $0 C. Determine Gross Margin Tax with hypothetical 0 basis point increase in ROE. Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase (II B. above) Addback Revenue Credits for Correct Gross Margin Tax Basis $0 Proper Basis for Caclulating Gross Margin Tax $0 Gross Margin Taxes with 0 Basis Point ROE increase Apportionment Factor to Texas (Worksheet J, ln 12) 0% Apportioned Texas Revenues $0 Taxable Percentage of Revenue (%) 0% Taxable, Apportioned Margin $0 Texas Gross Margin Tax Rate 0% Texas Gross Margin Tax Expense $0 Grossup Required for Gross Margin Tax Expense $0 Total Additional Gross Margin Tax Revenue Requirement $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101A Page 30 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.21 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 2 of 3 D. Determine FCR with hypothetical 0 basis point ROE increase. Net Transmission Plant (Attachment H, ln 42) $0 Net Revenue Requirement, with 0 Basis Point ROE increase $0 FCR with 0 Basis Point increase in ROE 0% Net Rev. Req, w / 0 Basis Point ROE increase, less Dep. $0 FCR with 0 Basis Point ROE increase, less Depreciation 0% FCR less Depreciation (Attachment H, ln 13) 0% Incremental FCR with 0 Basis Point ROE increase, less Depreciation 0% III. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) $0 Transmission Plant @ End of Period (P.207, ln 58) $0 $0 Average Balance of Transmission Investment $0 Annual Depreciation Rate (P. 336, ln. 7, col. F) $0 Composite Depreciation Rate 0% Depreciable Life for Composite Depreciation Rate 0 YEARS Round to nearest whole year 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101A Page 31 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.22 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 3 of 3 IV. Determine Revenue Requirement & Additional Revenue Requirement for facilities receiving incentives. A. Facilities receiving incentives accepted by FERC in Docket No. (e.g. ER05925000) Project Description: Details Investment $0 Current Year 0 Service Year (yyyy) 0 ROE increase accepted by FERC (Basis Points) 0 Service Month (112) 0 FCR w/o incentives, less depreciation 0% Useful life 0 FCR w/incentives approved for these facilities, less dep. 0% CIAC (Yes or No) Annual Depreciation Expense $0 Investment Beginning Depreciation Ending Revenue Revenue Req't. Additional Rev. Year Balance Expense Balance Requirement with Incentives ** Requirement 1 $ 2 $ 3 $ 4 $ 5 $ 6 $ 7 $ 8 $ 9 $ 10 $ 11 $ 12 $ 13 $ 14 $ 15 $ 16 $ 17 $ 18 $ 19 $ 20 $ 21 $ 22 $ 23 $ 24 $ 25 $ 26 $ 27 $ 28 $ 29 $ 30 $ 31 $ 32 $ 33 $ 34 $ 35 $ 36 $ 37 $ $ ## This is the calculation of additional incentive revenue on projects deemed by the FERC to be eligible for an incentive return. This additional incentive requirement is applicable for the life of this specific project. Each year the revenue requirement calculated for SPP should be incremented by the amount of the incentive revenue calculated for that year on this project. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101A Page 32 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.23 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 1 of 3 I. Calculate Return and Income Taxes with 0 basis point ROE increase for Projects Qualified for Incentive. A. Determine 'R' with hypothetical 0 basis point increase in ROE for Identified Projects ROE w/o incentives (Attachment H, ln 160) 0% Project ROE Incentive Adder 0 ROE with additional 0 basis point incentive 0% Determine R ( cost of long term debt, cost of preferred stock and percent is from Attachment H, lns 158 through160) % Cost Weighted cost Long Term Debt Preferred Stock Common Stock WACC = 0.0000 B. Determine Return using 'R' with hypothetical 0 basis point ROE increase for Identified Projects. Rate Base (Attachment H, ln 73) $0 R (fom A. above) 0.0000 Return (Rate Base x R) $0 C. Determine Income Taxes using Return with hypothetical 0 basis point ROE increase for Identified Projects. Return (from B. above) $0 CIT (Attachment H, ln 115) 0.00% Income Tax Calculation (Return x CIT) $0 ITC Adjustment (Attachment H, ln 121) $0 Income Taxes $0 II. Calculate Net Plant Carrying Charge Rate (Fixed Charge Rate or FCR) with hypothetical 0 basis point ROE increase. A. Determine Net Revenue Requirement less return and Income Taxes. Net Revenue Requirement (Attachment H, ln 6) $0 Return (Attachment H, ln 123) $0 Income Taxes (Attachment H, ln 122) $0 Gross Margin Taxes (Attachment H, ln 127) $0 Net Revenue Requirement, Less Return and Taxes $0 B. Determine Net Revenue Requirement with hypothetical 0 basis point increase in ROE. Net Revenue Requirement, Less Return and Taxes $0 Return (from I.B. above) $0 Income Taxes (from I.C. above) $0 Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase Gross Margin Tax with 0 Basis Point ROE Increase (II C. below) $0 Revenue Requirement w/ Gross Margin Taxes $0 Less: Depreciation (Attachment H, ln 98) $0 Net Rev. Req, w/0 Basis Point ROE increase, less Depreciation $0 C. Determine Gross Margin Tax with hypothetical basis point increase in ROE. Net Revenue Requirement before Gross Margin Taxes, with $0 Basis Point ROE increase (II B. above) Addback Revenue Credits for Correct Gross Margin Tax Basis $0 Proper Basis for Caclulating Gross Margin Tax $0 Gross Margin Taxes with Basis Point ROE increase Apportionment Factor to Texas (Worksheet J, ln 12) 0% Apportioned Texas Revenues $0 Taxable Percentage of Revenue (%) 0% Taxable, Apportioned Margin $0 Texas Gross Margin Tax Rate 0% Texas Gross Margin Tax Expense $0 Grossup Required for Gross Margin Tax Expense $0 Total Additional Gross Margin Tax Revenue Requirement $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101A Page 33 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.24 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 2 of 3 D. Determine FCR with hypothetical 0 basis point ROE increase. Net Transmission Plant (Attachment H, ln 42) $0 Net Revenue Requirement, with 0 Basis Point ROE increase $0 FCR with 0 Basis Point increase in ROE 0% Net Rev. Req, w / 0 Basis Point ROE increase, less Dep. $0 FCR with 0 Basis Point ROE increase, less Depreciation 0% FCR less Depreciation (Attachment H, ln 13) 0% Incremental FCR with 0 Basis Point ROE increase, less Depreciation 0% III. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) $0 Transmission Plant @ End of Period (P.207, ln 58) $0 $0 Average Balance of Transmission Investment $0 Annual Depreciation Rate (P. 336, ln. 7, col. F) $0 Composite Depreciation Rate 0% Depreciable Life for Composite Depreciation Rate 0 YEARS Round to nearest whole year 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101A Page 34 of 44 Southwest Power Pool pro forma Original Sheet No. 161D.25 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 3 of 3 IV. Determine Revenue Requirement & Additional Revenue Requirement for facilities receiving incentives. A. Base Plan Facilities Facilities receiving incentives accepted by FERC in Docket No. (e.g. ER05925000) Project Description: Details Investment $0 Current Year 0 Service Year (yyyy) 0 ROE increase accepted by FERC (Basis Points) 0 Service Month (112) 0 FCR w/o incentives, less depreciation 0% Useful life 0 FCR w/incentives approved for these facilities, less dep. 0% CIAC (Yes or No) Annual Depreciation Expense $0 Investment Beginning Depreciation Ending BPU Rev. Req't. BPU Rev. Req't. Incentive Rev. Year Balance Expense Balance w/o Incentives with Incentives** Requirement## 0 $ 1 $ 2 $ 3 $ 4 $ 5 $ 6 $ 7 $ 8 $ 9 $ 10 $ 11 $ 12 $ 13 $ 14 $ 15 $ 16 $ 17 $ 18 $ 19 $ 20 $ 21 $ 22 $ 23 $ 24 $ 25 $ 26 $ 27 $ 28 $ 29 $ 30 $ 31 $ 32 $ 33 $ 34 $ 35 $ 36 $ Project Totals ** This is the total amount that needs to be reported to SPP for billing to all regions. ## This is the calculation of additional incentive revenue on projects deemed by the FERC to be eligible for an incentive return. This additional incentive requirement is applicable for the life of this specific project. Each year the revenue requirement calculated for SPP should be incremented by the amount of the incentive revenue calculated for that year on this project. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet H Transmission PlantinService Additions I. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) Transmission Plant @ End of Period (P.207, ln 58) Average Balance of Transmission Investment Annual Depreciation Rate (P. 336, ln. 7, col. F) Composite Depreciation Rate Round to % to Reflect a Composite Life of Years Added Worksheet Exhibit No. AEP 101A Page 35 of 44 pro forma Original Sheet No. 161D.26 II. Calculation of Property Placed in Service by Month and the Related Depreciation Expense Month in Service Capitalized Balance Composite Annual Depreciation Rate Annual Depreciation Monthly Depreciation No. Months Depreciation First Year Depreciation Expense January 0.00% 11 February 0.00% 10 March 0.00% 9 April 0.00% 8 May 0.00% 7 June 0.00% 6 July 0.00% 5 August 0.00% 4 September 0.00% 3 October 0.00% 2 November 0.00% 1 December 0.00% 0 Investment $ Depreciation Expense $ III. Plant Transferred $ <== This input area is for original cost plant $ <== This input area is for accumulated depreciation that may be associated with capital expenditures. It would have an impact if a company had assets transferred from a subsidiary. $ <== This input area is for additional Depreciation Expense Issued by: L. Patrick Bourne, Director Issued on: Effective:

Issued by: L. Patrick Bourne, Director Issued on: Effective: Worksheet I NonTax Balance Sheet Adjustments Preferrered Stock Preferred Stock DividendsEffective Cost Based on YE Outstanding Shares Shares Outstanding @ 12/31/XX Par Value Book Value Dividend Rate Dividend Form 1 P. 251.e $ Effective Cost of Preferred Stock % Prepayments Account 165 (A) (B) (C) (D) (E) (F) (G) (H) 100% 100% Transmission Transmission Total Included NonTransmission Transmission Plant Labor in Ratebase Acc. No. Description YE Balance Related Related Related Related (E)+(F)+(G) Subtotal Form 1, p 112.57.c 0 0 0 0 0 0 Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.27 Added Worksheet Exhibit No. AEP 101A Page 36 of 44

Issued by: L. Patrick Bourne, Director Issued on: Effective: PSO Worksheet J Tax I. DEVELOPMENT OF COMPOSITE STATE INCOME TAX RATES II. Public Service Company of Oklahoma Calculation of Effective State Income Tax Rate For Tax Year 20XX State I Income Tax Rate Apportionment Factor Effective State Income Tax Rate 0.0000% State II Income Tax Rate Apportionment Factor Effective State Income Tax Rate 0.0000% Total Effective State Income Tax Rate 0.0000% CALCULATION OF TEXAS GROSS MARGIN TAX Total Company Trans. Only Total Company Trans. Only Line # REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX (ln 284 of Template) 147,553,686 37,758,675 1 Apportionment Factor to Texas (ln12) 0.00% 0.00% 0.00% 0.00% 2 Apportioned Texas Revenues $0 $0 $0 $0 3 Taxable Percentage of Revenue (70%) 70% 70% 70% 70% 4 Taxable, Apportioned Margin 5 Texas Gross Margin Tax Rate (1%) 1% 1% 1% 1% 6 Texas Gross Margin Tax Expense 7 Grossup Required for Texas Gross Margin Expense ((ln 6 * ln 3 * ln 1)/(1 ln 5) * ln 5) 8 Total Additional Gross Margin Tax Revenue Requirement 9 WHOLESALE LOAD ALLOCATOR (For Use in Gross Margin Tax Allocator) 10 Texas Jurisdictional Load 11 Total Load 12 Allocation Percentage (ln 10 / ln 11) 0.00% Actual Projected Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.28 Added Worksheet Exhibit No. AEP 101A Page 37 of 44

Southwest Power Pool FERC Electric Tariff Added Worksheet Worksheet K CWIP Balances on MultiYear Projects Exhibit No. AEP 101A Page 38 of 44 pro forma Original Sheet No. 161D.29 (A) (B) (C) Capital Item No. Descrition of Project Expenditure Total Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Exhibit No. AEP 101A Page 39 of 44 pro forma Original Sheet No. 161D.30 Worksheet L GSU Net Book Values as of December 31, 20XX company depreciation group utility acct vintage orig cost reserve net book value Total Transmission Investment $0 $0 $0 Less: GSU Investment $0 $0 $0 Transmission w/o GSUs $0 $0 $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 101A Page 40 of 44 Southwest Power Pool Original Sheet No. 217 FERC Electric Tariff ATTACHMENT T Rate Sheets For PointToPoint Transmission Service Issued by: L. Patrick Bourne, Manager Issued on: February 28, 2005 Effective: May 5, 2005

Exhibit No. AEP 101A Page 41 of 44 Southwest Power Pool pro forma Third Revised Sheet No. 218 FERC Electric Tariff Superseding Second Revised Sheet No. 218 Zone 1 Rate Sheet For PointtoPoint Transmission Service Firm PointtoPoint Transmission Service The Transmission Customer shall compensate the Transmission Provider each month for Reserved Capacity at the sum of the applicable charges set forth below: 1. Monthly delivery: $1528.30/MW of Reserved Capacity per month. 2. Weekly delivery: $ 352.66/MW of Reserved Capacity per week. 3. Daily delivery: OnPeak: OffPeak: $ 70.54/MW of Reserved Capacity per day. $ 50.25/MW of Reserved Capacity per day. The total demand charge in any week, pursuant to a reservation for Daily delivery, shall not exceed the rate specified in Section 2 above times the highest amount in megawatts of Reserved Capacity in any day during such week. For the purpose of the rate specified in Section 3 above, the OffPeak Period shall be Saturdays, Sundays, New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the OnPeak Period shall be all days that are not in the OffPeak Period. NonFirm PointtoPoint Transmission Service The Transmission Customer shall compensate the Transmission Provider for NonFirm PointToPoint Transmission Service up to the sum of the applicable charges set forth below: 1. Monthly delivery: $1528.30/MW of Reserved Capacity per month. 2. Weekly delivery: $ 352.66/MW of Reserved Capacity per week. 3. Daily delivery: OnPeak: OffPeak 4. Hourly delivery: OnPeak: OffPeak $ 70.54/MW of Reserved Capacity per day. $ 50.25/MW of Reserved Capacity per day. $ 4.41/MW of Reserved Capacity per hour. $ 2.10/MW of Reserved Capacity per hour. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 101A Page 42 of 44 Southwest Power Pool pro forma Second Revised Sheet No. 219 FERC Electric Tariff Superseding First Revised Sheet No. 219 The total demand charge in any day, pursuant to a reservation for Hourly delivery, shall not exceed the rate specified in Section 3 above times the highest amount in megawatts of Reserved Capacity in any hour during such day. In addition, the total demand charge in any week, pursuant to a reservation for Hourly or Daily delivery, shall not exceed the rate specified in Section 2 above times the highest amount in megawatts of Reserved Capacity in any hour during such week. For the purpose of the rate specified in Section 3 above, the OffPeak Period shall be Saturdays, Sundays, New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the OnPeak Period shall be all days that are not in the OffPeak Period. For the purpose of the rate specified in Section 4 above, OnPeak is all hours between HE 0700 and HE 2200, inclusive, Central Time Zone, excluding Sundays and holidays. Holidays shall be as defined by NERC, currently New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. OffPeak is all hours not designated as OnPeak. Issued by: L. Patrick Bourne, Manager Issued on: Effective:

Exhibit No. AEP 101A Page 43 of 44 Southwest Power Pool FERC Electric Tariff pro forma First Revised Sheet No. 219A Superseding Original Sheet No. 219A RESERVED Issued by: L. Patrick Bourne, Manager Issued on: Effective:

Exhibit No. AEP 101A Page 44 of 44 Southwest Power Pool pro forma First Revised Sheet No. 220 FERC Electric Tariff Superseding Original Sheet No. 220 RESERVED Issued by: L. Patrick Bourne, Manager Issued on: Effective:

ATTACHMENT C blacklined and highlighted copy of the revised tariff sheets showing all changes to AEP s existing transmission rate (Exhibit No. AEP101B)

Exhibit No. AEP 101B Page 1 of 45 Southwest Power Pool pro forma ThirdSecond Revised Sheet No. 94 FERC Electric Tariff Superseding SecondFirst Revised Sheet No. 94 SCHEDULE 1 Scheduling, System Control And Dispatch Service Scheduling, System Control and Dispatch Service is required to schedule the movement of power through, out of, within or into a Control Area. Charges for such service shall be as follows: 1) For Customers taking Firm or NonFirm PointToPoint Transmission Service, for through and out transactions, the Schedule 1 charge shall be the product of the capacity reserved, expressed in MW and the appropriate rate as follows: OnPeak: Monthly Rate $ 59.2979 per MWMonth Weekly Rate $13.6841 per MWWeek (The Monthly Rate times 12, divided by 52) Daily Rate $2.7368 per MWDay (The Monthly Rate times 12, divided by 260) Hourly Rate $0.1711 per MWHour (The Monthly Rate times 12, divided by 4160) Off Peak: Daily Rate/MW $1.9495 per MWDay (The Monthly Rate times 12, divided by 365) Hourly Rate/MW $0.1711 per MWHour (The Monthly Rate times 12, divided by 8760) OnPeak and OffPeak Periods OffPeak days shall be Saturdays and Sundays and all NERC holidays. All other days shall be OnPeak. All hours during OffPeak days shall be OffPeak. OnPeak hours during OnPeak days shall be all hours from HE 0700 through HE 2200 Central Prevailing Time. All other hours during OnPeak days shall be OffPeak. 2) For Customers taking Firm or NonFirm PointToPoint Transmission Service, for transactions into and within the Transmission System, the Schedule 1 charge shall be the charge computed pursuant to the approved rate schedule of the Zone that is the Point of Delivery. See Addendum 1 to this Schedule 1 for Zone 1 charges. 3) For Customers taking Network Integration Transmission Service, the Schedule 1 charge shall be the charge computed pursuant to the approved rate schedule of the Zone in which the load is located. See Addendum 1 to this Schedule 1 for Zone 1 charges. Issued by: L. Patrick Bourne, Director Issued on: August 2, 2005 Effective: October 1, 2005

Exhibit No. AEP 101B Page 2 of 45 Southwest Power Pool pro forma SecondFirst Revised Sheet No. 96 FERC Electric Tariff Superseding First RevisedOriginal Sheet No. 96 ADDENDUM 1 TO SCHEDULE 1 Revenue Requirements for the Allocation of Through And Out Transaction Revenue Revenue associated with the provision of Schedule 1 service for Customers taking Firm or Non Firm PointToPoint Transmission Service for through and out transactions, shall be allocated to Transmission Owners in proportion to the respective scheduling revenue requirement of each such Transmission Owner associated with the provision of this service. Such scheduling revenue requirements are: CURRENTLY EFFECTIVE Transmission Owner Revenue Requirement AEP $3,257,0732,911,599 Aquila MPS $1,620,559 Aquila WPK $594,828 Empire $260,944 GRDA $686,880 KCPL $0 Midwest $190,804 OG+E $4,759,216 SPA $1,622,827 Springfield $0 SPS $1,674,015 Westar $3,209,760 WFEC $1,824,120 Total $19,355,553 Zone 1 charges for Scheduling, System Control and Dispatch Service: (a) Network Integration Transmission Service: $34.55 per MW of Network Load per month. (b) PointtoPoint Transmission Service per MW reserved per: Month Week Day Hour $34.55 $7.97 $1.14 $0.05 Issued by: L. Patrick Bourne, Manager Issued on: March 30, 2004 Effective: April 1, 2004

Exhibit No. AEP 101B Page 3 of 45 Southwest Power Pool pro forma Ninth Eighth Revised Sheet No. 161 FERC Electric Tariff Superseding EighthSubstitute Seventh Revised Sheet No. 161 ATTACHMENT H Annual Transmission Revenue Requirement For Network Integration Transmission Service 1. The Existing Zonal Annual Transmission Revenue Requirement within each Zone for purposes of determining the charges under Schedule 9, Network Integration Transmission Service, is specified in column 3. The Base Plan Zonal Annual Transmission Revenue Requirement within each Zone for the purposes of determining the zonal charges under Schedule 11, Base Plan Charges, is specified in column 4. (1) Zone (2) (3) Existing Zonal ATRR (4) Base Plan Zonal ATRR 1 American Electric Power West $ 92,432,463 $0 1 American Electric Power (Public Service Company of Oklahoma, and Southwestern Electric Power Company, collectively AEP and SPP portion of Texas North Company) 88,681,579 See Section 7 below 1 East Texas Electric Cooperative, Inc. $2,733,879 $0 1 TexLa Electric Cooperative of Texas, Inc. $588,874 $0 1 Deep East Texas Electric Cooperative, Inc. $428,131 $0 2 Cleco Corporation $ 29,328,000 $0 3 City Utilities of Springfield, Missouri $ 8,651,509 $0 4 Empire District Electric Company $ 14,075,000 $0 5 Grand River Dam Authority (Est.) $ 24,589,256 $0 6 Kansas City Power & Light Company $ 35,461,776 $0 7 Oklahoma Gas & Electric Company $ 65,065,032 $0 8 Midwest Energy, Inc. $ 4,197,347 $0 9 Aquila NetworksMPS/L&P $ 20,759,283 $0 9a Aquila NetworksMPS $14,059,183 $0 9b Aquila NetworksL&P $6,700,100 $0 10 Southwestern Power Administration $9,155,900 $0 11 Southwestern Public Service $65,500,000 $0 12 Sunflower Electric Corporation $ 14,484,045 $0 13 Western Farmers Electric Cooperative $ 20,719,639 $0 Westar Energy, Inc. (Kansas Gas & Electric and See section 5 14 $0 Westar Energy) below 15 Aquila NetworksWPK $ 5,947,002 $0 $0 Issued by: L. Patrick Bourne, Director Issued on: December 29, 2006 Effective: January 1, 2007

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 4 of 45 pro forma Seventh Revised Sheet No. 161A Superseding Substitute Sixth Revised Sheet No. 161A 2. The Base Plan Regionwide Annual Transmission Revenue Requirement for the purposes of determining the regionwide charges under Schedule 11 shall initially be $0. 3. The amounts in (1) and (2) shall be effective until amended by the Transmission Owner or modified by the Commission or other applicable regulatory authority. 4. The revenue requirements stated in Attachment H shall not be changed absent a filing with the Commission. 5. The Annual Transmission Revenue Requirement for purposes of the Network Integration Transmission Service shall be calculated using the rate formula set forth in Attachment H1 of the Westar Open Access Transmission Tariff (Westar formula rate). The results of the formula calculation shall be posted on the SPP website and in an accessible location on Westar s OASIS website by May 15 of each calendar year and shall be effective on June 1 of such year. The Annual Transmission Revenue Requirement will be as identified on page 1, line 7 of the Westar formula rate, plus the previous calendar year s total firm PointtoPoint transmission revenue allocated to Westar under Attachment L provided such PointtoPoint transmission revenue is deducted from Westar s Annual Transmission Revenue Requirement under Section 34.1. 6. Pursuant to the Offer of Settlement approved by the Federal Energy Regulatory Commission in Xcel Energy Services Inc., 115 FERC 61,011, the Annual Transmission Reveune Requirement for the Southwestern Public Service Company (SPS) rate zone (Zone 11) stated on Sheet 161 shall not be subject to adjustment pursuant to section 34.1 for the previous calendar year s total firm PointtoPoint transmission revenue allocated to SPS under Attachment L when determining the monthly zonal Demand Charge for Zone 11. 7. The AEP Annual Transmission Revenue Requirement for purposes of the Network Integration Transmission Service shall be (i) calculated using the formula rate set forth in Addendum 1 to this Attachment H, (ii) posted on the SPP website by May 25 of each calendar year, and (iii) effective on July 1 of such year. Issued by: L. Patrick Bourne, Director Issued on: December 29, 2006 Effective: January 1, 2007

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 5 of 45 pro forma SecondFirst Revised Sheet No. 161B Superseding First RevisedOriginal Sheet No. 161B ADDENDUM 1 TO ATTACHMENT H MONTHLY DEMAND CHARGE CALCULATION FOR ZONE 1 NETWORK INTEGRATION TRANSMISSION SERVICE This Addendum to Attachment H sets forth the monthly Demand Charge for Zone 1 for Network Customers taking Network Integration Transmission Service under Schedule 9 to this Tariff. Charges for Compensation to AEP Unless a different rate is approved by the Commission, tthe monthly Demand Charge to Network Customers for compensation to AEP shall be determined by multiplying one twelfth (1/12) of the Existing Zonal ATRR for AEP, specified in Attachment H, by the Network Customer s monthly Network Load, determined in accordance with the provisions of Section 34.2, expressed in MW, divided by the total monthly Network Load for Zone 1. The total monthly Network Load shall be adjusted as necessary to incorporate the load of Network Integration Transmission Service Customers, and any zonal load served under grandfathered network and longterm firm pointtopoint service agreements.times the rate per MWmonth determined by dividing the Existing Zonal Annual Transmission Revenue Requirement of AEP, specified in Attachment H, by the sum of the twelve (12) coincident peak loads during the year 2000. Until a different rate has been approved by the Commission, such rate for each succeeding calendar year, to be effective on and after January 1, of such succeeding year, will be calculated by dividing AEP s Existing Zonal Annual Transmission Revenue Requirement, specified in Attachment H, by the sum of the twelve (12) coincident peak loads during the preceding calendar year. The rate for 2001, pursuant to the above, is $1,013.18 per MWmonth. Charges for Compensation to East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. In addition to the charges specified for compensation to AEP above, the Transmission Provider shall calculate a monthly Demand Charge associated with the revenue requirements of East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. which shall be applicable to all customers located in Zone 1 taking Network Service under this tariff, including any Transmission Owner within Zone 1 taking service under Section 39. The monthly charge to each customer for compensation to East Texas Electric Cooperative, Inc., TexLa Electric Cooperative of Texas, Inc. and Deep East Texas Electric Cooperative, Inc. shall be the product of the customer s load ratio share and one Issued by: L. Patrick Bourne, Director Issued on: December 29, 2006 Effective: January 1, 2007

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 6 of 45 pro forma SecondFirst Revised Sheet No. 161B Superseding First RevisedOriginal Sheet No. 161B twelfth (1/12) of such Transmission Owner s Existing Zonal Annual Transmission Revenue Requirement. Issued by: L. Patrick Bourne, Director Issued on: December 29, 2006 Effective: January 1, 2007

Exhibit No. AEP 101B Page 7 of 45 Southwest Power Pool pro forma Original Sheet No. 161C.1 FERC Electric Tariff I. Annual Update AEP Formula Rate Implementation Protocols 1. The rate formula template ( Formula ) and these protocols together comprise the filed rate of Public Service Company of Oklahoma and Southwestern Electric Power Company (collectively, AEP ) for transmission service under the SPP OATT. AEP must follow the instructions specified in the Formula to calculate its Annual Transmission Revenue Requirements ( ATRR ) and the rates for its Network Integration Transmission Service and PointtoPoint transmission service ( Formula Rate ). 2. The Formula Rate shall initially be effective for service on and after the date specified by the Federal Energy Regulatory Commission ( FERC ) in an order accepting the Formula Rate, and in subsequent years on and after July 1 of each calendar year through June 30 of the subsequent calendar year ( Rate Year ), subject to review, challenge and refunds or surcharges with interest, to the extent provided herein. 3. On or before May 25 of each calendar year, AEP shall: (a) (b) (c) (d) recalculate the ATRR and the Formula Rate for the new Rate Year in accordance with the Formula Rate ( Annual Update ); provide such Annual Update and supporting information in readonly format to SPP, for posting on the SPP website, such information to include a populated Formula showing the calculation of such Annual Update and documentation supporting such calculation as provided in Section I.4 below (the date of such posting to be the Posting Date ); disclose any changes in AEP accounting policies, practices or procedures that impact the Formula or calculations under the Formula that have occurred since the initial filing of the Formula or posting of the most recent Annual Update, as applicable; and notify its transmission customers and affected regulatory commissions of the Annual Update posting, and provide, upon request, fully functioning spreadsheet files supporting the Annual Update. 4. The Annual Update for the Rate Year shall: (a) be based upon AEP s FERC Forms No. 1 for the most recent calendar year, and, to the extent specified in the Formula, upon the books and records of AEP consistent with the FERC accounting policies and practices ( Prior Year ATRR ); Issued by: Issued on: L. Patrick Bourne, Director Effective:

Exhibit No. AEP 101B Page 8 of 45 Southwest Power Pool pro forma Original Sheet No. 161C.2 FERC Electric Tariff (b) (c) (d) (d) include adjustments reflecting the additional transmission plant in service, and related depreciation, and income taxes that are reasonably projected to be recorded upon the books and records of AEP consistent with the Formula and FERC accounting policies and practices, so as to estimate the ATRR as of the current calendar year end ( Projected ATRR ); as and to the extent specified in the Formula, provide sufficiently detailed supporting documentation for data (and all adjustments thereto or allocations thereof) that are used to develop the Formula Rate and are not otherwise available directly from the FERC Form No. 1; beginning in the second year, compare the latest Prior Year ATRR with the Projected ATRR calculated in the prior year s Annual Update, thereby to determine the amount needed to be surcharged or refunded to customers in the new Rate Year to true up collections for the soon to end Rate Year, including interest at the applicable FERC refund interest rates; and be subject to review only in accordance with the procedures set forth in these Formula Rate Review Protocols ( Protocol ). 5. A change to the Formula inputs related to revised return on equity financing ( ROE ), depreciation rates or PostEmployment Benefits Other than Pensions ( PBOP ) expenses may not be made absent an appropriate filing with the FERC pursuant to Federal Power Act Section 205 or Section 206. 6. If AEP files any corrections to its FERC Forms No. 1 during a Rate Year that would affect the Formula Rate for that Rate Year, such corrections and any resulting refunds or surcharges shall be reflected in the true up adjustment made part of the Annual Update for the next effective Rate Year. II. Review Procedures for Annual Update 1. Each Annual Update shall be subject to the following review procedures ( Annual Review Procedures ): (a) Each year, after the Posting Date and before June 25, AEP will convene a meeting ( Customer Meeting ) to afford interested parties (e.g., Transmission Customers and affected state and federal regulatory authorities) an opportunity to discuss and become better informed regarding the Annual Update; Issued by: Issued on: L. Patrick Bourne, Manager, Effective:

Exhibit No. AEP 101B Page 9 of 45 Southwest Power Pool pro forma Original Sheet No. 161C.3 FERC Electric Tariff (b) (c) (d) (e) Interested parties will have seventyfive (75) days after the Customer Meeting to serve reasonable information requests on AEP for information and workpapers supporting an Annual Update. Such information requests shall be limited to that which is necessary to determine if AEP has properly calculated the Annual Update under review (including any corrections pursuant to Section I.6). Further, such information requests shall not include requests for information related to Annual Updates from prior years except (i) to determine whether a prior year s approach on a given matter was the same or different from the current year s approach, or (ii) in connection with corrections pursuant to Section I.6. AEP shall make a good faith effort to respond to information requests pertaining to an Annual Update within fifteen (15) business days of receipt of such requests. Information requests received after 4 p.m. CPT shall be considered received the next business day. To the extent AEP and any interested party(ies) are unable to resolve disputes related to information requests submitted in accordance with these Annual Review Procedures, AEP or any interested party may petition the FERC to appoint an Administrative Law Judge as a discovery master. The discovery master shall have the power to issue binding orders to resolve discovery disputes and compel the production of discovery, as appropriate, in accordance with the Annual Review Procedures and consistent with the FERC s discovery rules. Any interested party shall have until the later of ninety (90) days after the Customer Meeting or fifteen (15) days after AEP s last response to reasonable information requests submitted pursuant to Section II.1(b) above, to review the calculation of the Annual Update ( Review Period ) and to notify AEP in writing of any specific challenges to the Annual Update ( Issues ). Challenges to the Formula itself shall not be considered Issues for purposes of these Annual Review Procedures. III. Resolution of Challenges For each Annual Update: 1. If AEP and any interested party(ies) have not resolved all Issues identified pursuant to Section II.1(e) above within sixty (60) days after the Review Period for a given Annual Update, the interested party(ies) may file a complaint challenging the Annual Update, with regard to such Issue(s), in a proceeding at the FERC ( Formal Challenge ). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 101B Page 10 of 45 Southwest Power Pool pro forma Original Sheet No. 161C.4 FERC Electric Tariff (a) A party may file a Formal Challenge for a limited period of up to three (3) months after the sixtyday resolution period has ended. A party may not, thereafter, file a Formal Challenge as to the disputed Issue(s) for the then effective Rate Year. Failure to pursue an Issue or lodge a Formal Challenge regarding an Issue(s) as to a given Annual Update shall not bar pursuit of such Issue or the lodging of a Formal Challenge as to such Issue(s) as relates to a subsequent Annual Update review. (b) All information produced pursuant to these Protocols may be included in any Formal Challenge. 2. In any proceeding ordered by the FERC in response to a Formal Challenge, AEP will bear the burden of proving that it has properly calculated the challenged Annual Update pursuant to the Formula. Challenges to the Formula itself shall not be considered Formal Challenges for purposes of these Annual Review Procedures, and shall be subject to the Commission s Rules and Regulations applicable to filings pursuant to 18 C.F.R. 385.206. 3. Each Annual Update shall become final and shall no longer be subject to challenge on the later to occur of: (i) passage of the time specified in III.1(a) above for a Formal Challenge, if no such Formal Challenge has been filed and the FERC has not itself initiated a proceeding to consider the Annual Update; or (ii) the issuance of a final FERC order in response to a Formal Challenge or a proceeding initiated by the FERC to consider the Annual Update. 4. Any refunds or surcharges resulting from a Formal Challenge shall be calculated, with interest, from the effective date of the challenged Annual Update, and shall be reflected in the Annual Update for the next effective Rate Year. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Issued by: L. Patrick Bourne, Director Issued on: Effective:.. AEP Transmission Formula Rate Template For rates effective July 1, Attachment H & T Support Page 1 of 1 SPP Zone 1 AEP Revenue Requirements AEP Annual PSO Annual SWEPCO Annual Line Revenue Revenue Revenue No. Requirement Requirement Requirement A. Network Service 1 REVENUE REQUIREMENT (w/o incentives) (TCOS Line 1 ) 2 LESS: REVENUE CREDITS (TCOS Line 5 ) 3 CURRENT YEAR ZONE 1 AEP NETWORK SERVICE REVENUE REQUIREMENT (TCOS Line 6 ) 4 LESS: REVENUE REQUIREMENTS INCLUDED IN LINE 1 FOR: 5 BASE PLAN UPGRADES (W/O INCENTIVES) (TCOS Line 7 ) 6 REQUESTED UPGRADES (W/O INCENTIVES) (Worksheet F) 7 ECONOMIC UPGRADES (W/O INCENTIVES) (Worksheet F) 8 SUBTOTAL 9 EXISTING ZONAL ATRR (W/O INCENTIVES) (Line 3 Line 8) 10 INCENTIVE REVENUE REQUIREMENT FOR ZONAL PROJECTS (TCOS ln 16) 11 EXISTING ZONAL ATRR (W/ INCENTIVES) (Line 9 + Line 10) 12 HISTORICAL YEAR (2006) ACTUAL ATRR 13 PROJECTED (2006) ATRR FROM PRIOR YEAR Input from Prior Year 14 PRIOR YEAR TRUEUP (Line 12 Line 13) 15 INTEREST ON PRIOR YEAR TRUE UP 16 EXISTING ZONAL ATRR FOR SPP OATT ATTACHMENT H, SEC. 1, COL. 3 (Ln 11 + Ln 14 + Ln 15) B. PointtoPoint Service 17 2007 Projected AEP West Zone SPP Average 12Mo. Peak Demand (Load WS, ln 11) MW 18 Annual PointtoPoint Rate in $/MW Year (Line 16 / Line 17) 19 Monthly PointtoPoint Rate in $/MW Month (Line 18 / 12) 20 Weekly PointtoPoint Rate in $/MW Weekly (Line 19 / 52) 21 Daily OnPeak PointtoPoint Rate in $/MW Day (Line 20 / 260) 22 Daily OffPeak PointtoPoint Rate in $/MW Day (Line 21 / 365) 23 Hourly OnPeak PointtoPoint Rate in $/MW Hour (Line 22 / 4160) 24 Hourly OffPeak PointtoPoint Rate in $/MW Hour (Line 23 / 8760) C. SPP Regional Service 25 BASE PLAN UPGRADE ATRR W/O INCENTIVES (Line 8) 26 ADDITIONAL ATRR FOR FERCAPPROVED INCENTIVES ON BPU (Worksheet G) 27 BASE PLAN UPGRADE ATRR FOR SPP COLLECTION UNDER SCHEDULE 11 Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.1 Exhibit No. AEP 101B Page 11 of 45

Issued by: L. Patrick Bourne, Director Issued on: Effective: AEP Transmission Formula Rate Template For rates effective July 1, Schedule 1 Support Page 1 of 1 SPP SCHEDULE 1 AEP Revenue Requirements AEP Annual PSO Annual SWEPCO Annual Line Revenue Revenue Revenue No. Requirement Requirement Requirement A. Schedule 1 ARR 1 Total Load Dispatch & Scheduling (Account 561) (TCOS Line 76) 2 Less: Load Disptach Scheduling, System Control and Dispatch Services (321.88.b) 3 Less: Load Disptach Reliability, Planning & Standards Development Services (321.92.6) 4 Total 561 Internally Developed Costs (Line 1Line 2Line 3) 5 Less: PTP Service Credit 6 EXISTING ZONAL ARR (Line 4 Line 5) 7 HISTORICAL YEAR (2006) ACTUAL ARR 8 PROJECTED (2006) ARR FROM PRIOR YEAR 9 PRIOR YEAR TRUEUP 10 INTEREST ON PRIOR YEAR TRUE UP 11 Net Schedule 1 Revenue Requirement for Zone B. Schedule 1 Rate Calculations 12 2007 Projected AEP West Zone SPP Average 12Mo. Peak Demand (LOAD WS, Line 11) MW 13 Annual PointtoPoint Rate in $/MW Year (Line 11 / Line 12) 14 Monthly PointtoPoint Rate (ln 13 / 12) $/MW Month (Line 13 / 12) 15 Weekly PointtoPoint Rate (ln 13 / 52) $/MW Weekly (Line 13 / 52) 16 Daily OffPeak PointtoPoint Rate (ln 13 / 365) $/MW Day (Line 13 / 365) 17 Hourly OffPeak PointtoPoint Rate (ln 13 / 8760) $/MW Hour (Line 13 / 8760) Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.2 Exhibit No. AEP 101B Page 12 of 45

Issued by: L. Patrick Bourne, Director Issued on: Effective: AEP Companies: PSO and SWEPCO Network Load for January Through December, Based on West ZoneSPP Monthly Transmission System Firm Peak Demands (1) for the Twelve Months Ended December 31, Projected Combined Load Worksheet Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Peak Day 12 Month Line Peak Hour *projected *projected *projected *projected *projected *projected *projected *projected Average MW No. SPP Load Responsibility 1 PSO 2 SWEPCO 3 TNCN 4 OMPA 5 NTEC 6 ETEC 7 TEXLA 8 Greenbelt 9 Lighthouse 10 Coffeyville, KS (OATT Firm PTP) (2) 11 Zone 1 System Firm Peak Demands Historical Combined Load Worksheet Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Peak Day 12 Month Line Peak Hour Average MW No. SPP Load Responsibility 12 PSO 13 SWEPCO 14 TNCN 15 OMPA 16 NTEC 17 ETEC 18 TEXLA 19 Greenbelt 20 Lighthouse 21 Coffeyville, KS (OATT Firm PTP) (2) 22 Zone 1 System Firm Peak Demands Supporting Data 23 PSO: PSO Native Load 24 KAMO 25 WFEC 26 PSO Load Responsibility 27 SWEPCO: SWEPCO Native Load 28 Less: NTEC 29 Less: ETEC 30 Less: TEXLA 31 AECC 32 LaGen (Formerly Cajun) 33 Lafayette 34 Dolet Hills Aux. Load (not selfgenerated 35 SWEPCO Load Responsibility 36 TNC TNC North Native Load 37 TNC North Load Responsibility 38 Coffeyville Actual Load (2) Notes: (1) MW, at the time of the AEPSPP Native Peak. At the generator. Transmission losses added to metered values which include appropriate dist.& xfmr losses. (2) Net load from East and West Coffeyville ties, not included in AEP Control Area. Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.3 Exhibit No. AEP 101B Page 13 of 45

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 14 of 45 pro forma Original Sheet No. 161D.4 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 1 of 10 Plus Capital Additions for PROJECTED Company: Line No. 1 REVENUE REQUIREMENT (w/o incentives) (ln 128) Transmission Amount 2 REVENUE CREDITS (Note A) Total Allocator 3 Transmission Credits (Worksheet A) DA 4 Assoc. Business Development (Worksheet A) DA 5 Total Revenue Credits 6 REVENUE REQUIREMENT (w/o incentives) For All AEP Facilities (ln 1 less ln 5) 7 Revenue Requirement for SPP Base Plan Upgrades (w/o incentives) (Worksheet G) DA 8 REVENUE REQUIREMENT EXCLUDING BASE PLAN UPGRADE ATRR (ln 6 less ln 7) 9 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 10 Annual Rate (ln 6 / ln 42 x 100) 11 Monthly Rate (ln 10 / 12) 12 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 13 Annual Rate ( (ln 6 ln 98) / ln 42 x 100) 14 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 15 Annual Rate ( (ln 6 ln 98 ln 122 ln 123) / ln 42 x 100) 16 ADDITIONAL REVENUE REQUIREMENT for projects w/ incentive ROE's (Note C) (Worksheet F) NA 17 PROJECTED YE 2007 TRANSMISSION REVENUE REQUIREMENT (ln 8 + ln 16) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 2 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101B Page 15 of 45 pro forma Original Sheet No. 161D.5 Company: (1) (2) (3) (4) (5) Data Sources Total RATE BASE CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. GROSS PLANT IN SERVICE 18 Production 205.46.g NA 19 Transmission 207.58.g DA 20 Plus: Transmission PlantinService Additions (Worksheet H) DA 21 Plus: Additional Trans Plant on Transferred Assets (Worksheet H) DA 22 Distribution 207.75.g NA 23 General Plant 207.99.g (Note K) W/S 24 Intangible Plant 205.5.g W/S 25 Common 356 CE 26 TOTAL GROSS PLANT (sum lns 18 to 25) GP(p)= GTD(p)= 27 ACCUMULATED DEPRECIATION AND AMORTIZATION 28 Production 219.2024.c NA 29 Transmission 219.25.c TP1= 30 Plus: Transmission PlantinService Additions (Worksheet H) DA 31 Plus: Additional Projected Deprec on Transferred Assets (Worksheet H) DA 32 Plus: Additional Transmission Depreciation for 2007 (ln 98) TP1 33 Plus: Additional General & Intangible Depreciation for 2007 (ln 100 + ln 101) W/S 34 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) DA 35 Distribution 219.26.c NA 36 General Plant 219.28.c (Note K) W/S 37 Intangible Plant 219 W/S 38 Common 356 CE 39 TOTAL ACCUMULATED DEPRECIATION (sum lns 28 to 38) 40 NET PLANT IN SERVICE 41 Production (ln 18 ln 28) 42 Transmission (ln 19 ln 29) 43 Plus: Transmission PlantinService Additions (ln 20 ln 30) 44 Plus: Additional Trans Plant on Transferred Assets (ln 21 ln 31) 45 Plus: Additional Transmission Depreciation for 2007 (ln 32) 46 Plus: Additional General & Intangible Depreciation for 2007 (ln 33) 47 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) (ln 34) 48 Distribution (ln 22 ln 35) 49 General Plant (ln 23 ln 36) 50 Intangible Plant (ln 24 ln 37) 51 Common (ln 25 ln 38) 52 TOTAL NET PLANT IN SERVICE (sum lns 41 to 51) NP(p)= 53 ADJUSTMENTS TO RATE BASE (Note D) 54 Account No. 281 (enter negative) 273.8.k (Worksheet C) DA 55 Account No. 282 (enter negative) 275.2.k (Worksheet C) DA 56 Account No. 283 (enter negative) 277.9.k (Worksheet C) DA 57 Account No. 190 234.8.c (Worksheet C) DA 58 Account No. 255 (enter negative) 267.8.h (Worksheet C) DA 59 Account 107 for Approved MultiYear Projects 216.43.b (Worksheet K) DA 60 Other Additions/Deductions (Note E) DA 61 TOTAL ADJUSTMENTS (sum lns 54 to 60) 62 PLANT HELD FOR FUTURE USE 214.x.d (Note F) DA 63 WORKING CAPITAL (Note G) 64 Cash Working Capital (1/8 * ln 96) 65 Transmission Materials & Supplies 227.8.c TP 66 A&G Materials & Supplies 227.11.c W/S 67 Undistributed Stores Expense (Acct 163) 227.16.c GP(h) 68 Prepayments (Account 165) Labor Allocated 111.57.c (Worksheet I) W/S 69 Prepayments (Account 165) Direct Allocated 111.57.c (Worksheet I) DA 70 Prepayments (Account 165) Gross Plant 111.57.c (Worksheet I) GP(h) 71 TOTAL WORKING CAPITAL (sum lns 64 to 70) 72 IPP CONTRIBUTIONS FOR CONSTRUCTION #REF! DA 73 RATE BASE (sum lns 52, 61, 62, 71, 72) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 3 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101B Page 16 of 45 pro forma Original Sheet No. 161D.6 Company: (1) (2) (3) (4) (5) EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. OPERATION & MAINTENANCE EXPENSE 74 Transmission 321.112.b TP 75 Less: expenses 100% assigned to TO billed customers (Worksheet E, ln 14) DA 76 Less: Total Account 561 (Load Dispatch Sch 1) (Note I) 321.8492.b TP 77 Less: Account 565 321.96.b (Note J) TP 78 Plus: Acct 565 native load, zonal or pool (Note J) DA 79 Transmission Subtotal (lns 74757677+78) 80 Administrative and General 323.197.b (Note K) 81 Less: Acc. 928, Reg. Com. Exp. 323.189.b 82 Acct. 930.1, Gen. Advert. Exp. 323.191.b 83 Acc. 924, Property Insurance 323.185.b 84 Acc. 930.2, Misc. Gen. Exp. 323.192.b 85 Acc. 935, Maint. of Gen. Plant 323.196.b W/S 86 Balance of A & G (ln 80 sum ln 81 to ln 85) W/S 87 Plus: Acct. 924, Property Insurance (ln 83) NP(h) 88 Acct. 928 Transmission Specific (Note L) (Worksheet D) TP 89 Acct. 928 Transmission Allocated (Note L) (Worksheet D) GP(h) 90 Acct 930.1 Only safety related ads. (Note L) (Worksheet D) W/S 91 Acct 930.2 Misc Gen. Exp. Trans (Worksheet D) TP 92 Acct 930.2 Misc Gen. Exp. Allocated (Worksheet D) W/S 93 A & G Subtotal (sum lns 84 to 90) 94 Common 356 CE 95 Transmission Lease Payments DA 96 TOTAL O & M EXPENSE (ln 79 + ln 93 + ln 94 + ln 95) 97 DEPRECIATION AND AMORTIZATION EXPENSE 98 Transmission 336.7.f TP 99 Plus: Transmission PlantinService Additions (Worksheet H) DA 100 General 336.10.f W/S 101 Intangible 336.1.f W/S 102 Common 336.11.f CE 103 TOTAL DEPRECIATION AND AMORTIZATIN (sum lns 98 to 102) 104 TAXES OTHER THAN INCOME (Note M) 105 Labor Related 106 Payroll 262.x263.x.i W/S 107 Plant Related 108 Property 262.x263.x.i NP(h) 109 Gross Receipts/Sales & Use 262.x263.x.i NA 110 Other 262.x263.x.i GP(h) 111 Payments in lieu of taxes GP(h) 112 TOTAL OTHER TAXES 114.14.c 113 INCOME TAXES (Note N) 114 T=1 {[(1 SIT) * (1 FIT)] / (1 SIT * FIT * p)} = 115 EIT=(T/(1T)) * (1(WCLTD/WACC)) = 116 where WCLTD=(ln 158) and WACC = (ln 161) 117 and FIT, SIT & p are as given in Note N. 118 GRCF=1 / (1 T) = (from ln 114) 119 Amortized Investment Tax Credit (enter negative) 120 Income Tax Calculation (ln 115 * ln 123) 121 ITC adjustment (ln 118 * ln 119) NP(h) 122 TOTAL INCOME TAXES (sum lns 120 to 121) 123 RETURN ON RATE BASE (Rate Base*WACC) (ln 73 * ln 161) 124 INTEREST ON IPP CONTRIBUTION FOR CONST. (Note H) (Worksheet B, ln 16) DA 125 REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX 126 (sum lns 96, 103, 112, 122, 123, 124) 127 TEXAS GROSS MARGIN TAX (NOTE O) (Worksheet J) DA 128 REVENUE REQUIREMENT INCLUDING GROSS MARGIN TAX Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 4 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101B Page 17 of 45 pro forma Original Sheet No. 161D.7 Company: SUPPORTING CALCULATIONS ln No. TRANSMISSION PLANT INCLUDED IN SPP TARIFF 129 Total transmission plant (ln 19 + ln 20 + ln 21) 130 Less transmission plant excluded from SPP Tariff (Note P) 131 Less transmission plant included in OATT Ancillary Services (Note Q ) (Worksheet L) 132 Transmission plant included in SPP Tariff (ln 129 ln 130 ln 131) 133 Percent of transmission plant in SPP Tariff (ln 132 / ln 129) TP= 134 WAGES & SALARY ALLOCATOR (W/S) (Note R) Direct Payroll Payroll Billed from AEP Service Corp. 135 Production 354.20,22.b NA 136 Transmission 354.21.b TP 137 Distribution 354.23.b NA 138 Other (Excludes A&E 354.24,25,26.b NA 139 Total (sum lns 135 to 138) 140 Transmission related amount W/S= 141 COMMON PLANT ALLOCATOR (CE) 142 Electric 200.3.c DA 143 Gas 200.3.d NA 144 Other 200.3. e, f, g NA 145 Total (sum lns 142 to 144) 146 Electric related amount 147 W/S Allocator W/S 148 Transmission related amount (ln 146 * ln 147) CE= 149 WEIGHTED AVERAGE COST OF CAPITAL (WACC) $ 150 Long Term Interest (117, sum of 62c 66c) 151 Preferred Dividends (118.29.c) (positive number) 152 Development of Common Stock: 153 Proprietary Capital (112.16.c) 154 Less Preferred Stock (ln 159) 155 Less Account 219.1 (112.15.c) 156 Common Stock (ln 153 ln 154 ln 155) Cost 157 $ % (Note S) Weighted 158 Long Term Debt (112, sum of 18.c 21.c) 159 Preferred Stock (112.3.c) 160 Common Stock (ln 156) 161 Total (sum lns 158 to 160) WACC= Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 5 of 10 Plus Capital Additions for PROJECTED Exhibit No. AEP 101B Page 18 of 45 pro forma Original Sheet No. 161D.8 Company: Letter A B C D E F Notes General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# b) If transmission owner ("TO") functionalizes its costs to transmission on its books, those costs are shown above and on any supporting workpapers rather than using the allocations above. The revenue credits shall include a) amounts received directly from the SPP for PTP transmission services, b) direct assignment charges for transmission facilities, the cost of which has been included in the TCOS, and c) amounts from customers taking service under grandfathered agreements, where the demand is not included in the rate divisor. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or facilities excluded from the TCOS are not included as revenue credits. Revenue from Transmission Customers whose coincident peak loads are included in the DIVISOR of the loadratio share calculation are not included as revenue credits. See Worksheet A for details. The annual and monthly net plant carrying charges on page 1 are used to compute the revenue requirement for facilities and any upgrades. This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet F shows the calculation of the additional incentive revenue requirement for each project receiving incentive rate treatment, as accepted by FERC. These individual additional revenue requirements shall be summed, for the projected year, and included here. Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, 255 and, if applicable, 107. The balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. An exception to this is pre1971 ITC balances, which are required to be taken as an offset to rate base. Account 281 is not allocated. Transmission allocations are shown on Worksheet C. Include Account 182.3, Other Regulatory Assets, related to Transmission Service under this Tariff, if any. Also include any unamortized balances related to precommercial operation costs when recovery of abandonment costs are granted. Identified as being transmission related or functionally booked to transmission. G Cash Working Capital assigned to transmission is oneeighth of O&M allocated to transmission on line 96. H Consistent with Paragraph 657 of Order 2003A, the amount on line 72 is equal to the balance of IPP System Upgrade Credits owed to transmission customers that made contributions toward the construction of System upgrades, and includes accrued interest and unreturned balance of contributions. The annual interest expense is included on line 124. I Removes the expense booked to transmission accounts included in the development of OATT ancillary services rates, including all of Account No. 561. J K L M Removes cost of transmission service provided by others to the extent such service is not incurred to provide the SPP service at issue. General Plant and Administrative & General expenses may be functionalized based on allocators other then the W/S allocator. Full documentation must be provided. Includes Regulatory Commission expenses itemized in FERC Form1 at page 351, column H. Worksheet D allocates these expense items. FERC Assessment Fees and Annual Charges shall not be allocated to transmission. Only safetyrelated and educational advertising costs in Account 930.1 are included in the TCOS. Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax and taxes related to income are excluded. N The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 119) multiplied by (1/1T). If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= 0.00% (State Income Tax Rate or Composite SIT. Worksheet J)) p = 0.00% (percent of federal income tax deductible for state purposes) O P Effective January 1, 2007, Texas instituted a gross margin tax. This tax is calculated on the Texas allocated revenue of the Company, reduced by 30% to derive a "Gross Margin" for the Company. The tax rate of one percent is assessed on the resulting amount. The jurisdictional allocator is based on transmission demand allocators. Removes plant excluded from the OATT because it does not meet the SPP's definition of Transmission Facilities or is otherwise ineligible to be recovered under the OATT. Q Removes transmission plant (e.g. stepup transformers) included in the development of OATT ancillary service rates and not already removed for reasons indicated in Note P. R Includes functional wages & salaries incurred by parent company service corporation for support of the operating company. S Long Term Debt cost rate = longterm interest (ln 150) / long term debt (ln 158). Preferred Stock cost rate = preferred dividends (ln 151) / preferred outstanding (ln 159). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 19 of 45 pro forma Original Sheet No. 161D.9 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 6 of 10 Historical Transmission Cost of Service HISTORICAL Company: Line No. 162 REVENUE REQUIREMENT (w/o incentives) (ln 286) Transmission Amount 163 REVENUE CREDITS (Note A) Total Allocator 164 Transmission Credits (Worksheet A) DA 165 Assoc. Business Development (Worksheet A) DA 166 Total Revenue Credits 167 REVENUE REQUIREMENT (w/o incentives) For All AEP Facilities (ln 162 less ln 166) 168 Revenue Requirement for SPP Base Plan Upgrades (w/o incentives) (Worksheet G) DA 169 REVENUE REQUIREMENT EXCLUDING BASE PLAN UPGRADE ATRR (ln 167 less ln 168) 170 NET PLANT CARRYING CHARGE (w/o incentives) (Note B) 171 Annual Rate (ln 167 / ln 203 x 100) 172 Monthly Rate (ln 171 / 12) 173 NET PLANT CARRYING CHARGE, W/O DEPRECIATION (w/o incentives) (Note B) 174 Annual Rate ( (ln 167 ln 259) / ln 203 x 100) 175 NET PLANT CARRYING CHARGE, W/O DEPRECIATION, INCOME TAXES AND RETURN (Note B) 176 Annual Rate ( (ln 167 ln 259 ln 283 ln 284) / ln 203 x 100) 177 ADDITIONAL REVENUE REQUIREMENT for projects w/ incentive ROE's (Note C) (Worksheet F) NA 178 HISTORICAL YE 2006 TRANSMISSION REVENUE REQUIREMENT (ln 169 + ln 177) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 20 of 45 pro forma Original Sheet No. 161D.10 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 7 of 10 Historical Transmission Cost of Service HISTORICAL Company: (1) (2) (3) (4) (5) Data Sources Total RATE BASE CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. GROSS PLANT IN SERVICE 179 Production 205.46.g NA 180 Transmission 207.58.g DA 181 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 182 Plus: Additional Trans Plant on Transferred Assets (Worksheet H) N/A DA N/A 183 Distribution 207.75.g NA 184 General Plant 207.99.g (Note K) W/S 185 Intangible Plant 205.5.g W/S 186 Common 356 CE 187 TOTAL GROSS PLANT (sum lns 179 to 186) GP(h)= GTD= 188 ACCUMULATED DEPRECIATION AND AMORTIZATION 189 Production 219.2024.c NA 190 Transmission 219.25.c TP1= 191 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 192 Plus: Additional Projected Deprec on Transferred Assets (Worksheet H) N/A DA N/A 193 Plus: Additional Transmission Depreciation for 2007 (ln 259) N/A TP1 N/A 194 Plus: Additional General & Intangible Depreciation for 2007 (ln 261 + ln 262) N/A W/S N/A 195 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) N/A DA N/A 196 Distribution 219.26.c NA 197 General Plant 219.28.c (Note K) W/S 198 Intangible Plant 219 W/S 199 Common 356 CE 200 TOTAL ACCUMULATED DEPRECIATION (sum lns 189 to 199) 201 NET PLANT IN SERVICE 202 Production (ln 179 ln 189) 203 Transmission (ln 180 ln 190) 204 Plus: Transmission PlantinService Additions (ln 181 ln 191) N/A N/A 205 Plus: Additional Trans Plant on Transferred Assets (ln 182 ln 192) N/A N/A 206 Plus: Additional Transmission Depreciation for 2007 (ln 193) N/A N/A 207 Plus: Additional General & Intangible Depreciation for 2007 (ln 194) N/A N/A 208 Plus: Additional Accum Deprec on Transferred Assets (Worksheet H) (ln 195) N/A N/A 209 Distribution (ln 183 ln 196) 210 General Plant (ln 184 ln 197) 211 Intangible Plant (ln 185 ln 198) 212 Common (ln 186 ln 199) 213 TOTAL NET PLANT IN SERVICE (sum lns 202 to 212) NP(h)= 214 ADJUSTMENTS TO RATE BASE (Note D) 215 Account No. 281 (enter negative) 273.8.k (Worksheet C) DA 216 Account No. 282 (enter negative) 275.2.k (Worksheet C) DA 217 Account No. 283 (enter negative) 277.9.k (Worksheet C) DA 218 Account No. 190 234.8.c (Worksheet C) DA 219 Account No. 255 (enter negative) 267.8.h (Worksheet C) DA 220 Account 107 for Approved MultiYear Projects 216.43.b (Worksheet K) DA 221 Other Additions/Deductions (Note E) DA 222 TOTAL ADJUSTMENTS (sum lns 215 to 221) 223 PLANT HELD FOR FUTURE USE 214.x.d (Note F) DA 224 WORKING CAPITAL (Note G) 225 Cash Working Capital (1/8 * ln 257) 226 Transmission Materials & Supplies 227.8.c TP 227 A&G Materials & Supplies 227.11.c W/S 228 Undistributed Stores Expense (Acct 163) 227.16.c GP(h) 229 Prepayments (Account 165) Labor Allocated 111.57.c (Worksheet I) W/S 230 Prepayments (Account 165) Direct Allocated 111.57.c (Worksheet I) DA 231 Prepayments (Account 165) Gross Plant 111.57.c (Worksheet I) GP(h) 232 TOTAL WORKING CAPITAL (sum lns 225 to 231) 233 IPP CONTRIBUTIONS FOR CONSTRUCTION #REF! DA 234 RATE BASE (sum lns 213, 222, 223, 232, 233) Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 21 of 45 pro forma Original Sheet No. 161D.11 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 8 of 10 Historical Transmission Cost of Service HISTORICAL Company: (1) (2) (3) (4) (5) EXPENSE, TAXES, RETURN & REVENUE Data Sources Total REQUIREMENTS CALCULATION (See "General Notes") TO Total Allocator Transmission Line No. OPERATION & MAINTENANCE EXPENSE 235 Transmission 321.112.b TP 236 Less: expenses 100% assigned to TO billed customers (Worksheet E, ln 14) DA 237 Less: Total Account 561 (Load Dispatch Sch 1) (Note I) 321.8492.b TP 238 Less: Account 565 321.96.b (Note J) TP 239 Plus: Acct 565 native load, zonal or pool (Note J) DA 240 Transmission Subtotal (lns 235236237238+239) 241 Administrative and General 323.197.b (Note K) 242 Less: Acc. 928, Reg. Com. Exp. 323.189.b 243 Acct. 930.1, Gen. Advert. Exp. 323.191.b 244 Acc. 924, Property Insurance 323.185.b 245 Acc. 930.2, Misc. Gen. Exp. 323.192.b 246 Acc. 935, Maint. of Gen. Plant 323.196.b W/S 247 Balance of A & G (ln 241 sum ln 242 to ln 246) W/S 248 Plus: Acct. 924, Property Insurance (ln 244) NP(h) 249 Acct. 928 Transmission Specific (Note L) (Worksheet D) TP 250 Acct. 928 Transmission Allocated (Note L) (Worksheet D) GP(h) 251 Acct 930.1 Only safety related ads. (Note L) (Worksheet D) W/S 252 Acct 930.2 Misc Gen. Exp. Trans (Worksheet D) TP 253 Acct 930.2 Misc Gen. Exp. Allocated (Worksheet D) W/S 254 A & G Subtotal (sum lns 246 to 253) 255 Common 356 CE 256 Transmission Lease Payments DA 257 TOTAL O & M EXPENSE (ln 240 + ln 254 + ln 255 + ln 256) 258 DEPRECIATION AND AMORTIZATION EXPENSE 259 Transmission 336.7.f TP 260 Plus: Transmission PlantinService Additions (Worksheet H) N/A DA N/A 261 General 336.10.f W/S 262 Intangible 336.1.f W/S 263 Common 336.11.f CE 264 TOTAL DEPRECIATION AND AMORTIZATIN (sum lns 259 to 263) 265 TAXES OTHER THAN INCOME (Note M) 266 Labor Related 267 Payroll 262.x263.x.i W/S 268 Plant Related 269 Property 262.x263.x.i NP(h) 270 Gross Receipts/Sales & Use 262.x263.x.i NA 271 Other 262.x263.x.i GP(h) 272 Payments in lieu of taxes GP(h) 273 TOTAL OTHER TAXES 114.14.c 274 INCOME TAXES (Note N) 275 T=1 {[(1 SIT) * (1 FIT)] / (1 SIT * FIT * p)} = 276 EIT=(T/(1T)) * (1(WCLTD/WACC)) = 277 where WCLTD=(ln 319) and WACC = (ln 322) 278 and FIT, SIT & p are as given in Note N. 279 GRCF=1 / (1 T) = (from ln 275) 280 Amortized Investment Tax Credit (enter negative) 281 Income Tax Calculation (ln 276 * ln 284) 282 ITC adjustment (ln 279 * ln 280) NP(h) 283 TOTAL INCOME TAXES (sum lns 281 to 282) 284 RETURN ON RATE BASE (Rate Base*WACC) (ln 234 * ln 322) 285 INTEREST ON IPP CONTRIBUTION FOR CONST. (Note H) (Worksheet B, ln 16) DA 286 REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX 287 (sum lns 257, 264, 273, 283, 284, 285) 288 TEXAS GROSS MARGIN TAX (NOTE O) (Worksheet J) DA 289 REVENUE REQUIREMENT INCLUDING GROSS MARGIN TAX Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 22 of 45 pro forma Original Sheet No. 161D.12 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 9 of 10 Historical Transmission Cost of Service HISTORICAL Company: SUPPORTING CALCULATIONS ln No. TRANSMISSION PLANT INCLUDED IN SPP TARIFF 290 Total transmission plant (ln 180) 291 Less transmission plant excluded from SPP Tariff (Note P) 292 Less transmission plant included in OATT Ancillary Services (Note Q ) (Worksheet L) 293 Transmission plant included in SPP Tariff (ln 290 ln 291 ln 292) 294 Percent of transmission plant in SPP Tariff (ln 293 / ln 290) TP= 295 WAGES & SALARY ALLOCATOR (W/S) (Note R) Direct Payroll Payroll Billed from AEP Service Corp. 296 Production 354.20,22.b NA 297 Transmission 354.21.b TP 298 Distribution 354.23.b NA 299 Other (Excludes A&E 354.24,25,26.b NA 300 Total (sum lns 296 to 299) 301 Transmission related amount W/S= 302 COMMON PLANT ALLOCATOR (CE) 303 Electric 200.3.c DA 304 Gas 200.3.d NA 305 Other 200.3. e, f, g NA 306 Total (sum lns 303 to 305) 307 Electric related amount 308 W/S Allocator W/S 309 Transmission related amount (ln 307 * ln 308) CE= 310 WEIGHTED AVERAGE COST OF CAPITAL (WACC) $ 311 Long Term Interest (117, sum of 62c 66c) 312 Preferred Dividends (118.29.c) (positive number) 313 Development of Common Stock: 314 Proprietary Capital (112.16.c) 315 Less Preferred Stock (ln 320) 316 Less Account 219.1 (112.15.c) 317 Common Stock (ln 314 ln 315 ln 316) Cost 318 $ % (Note S) Weighted 319 Long Term Debt (112, sum of 18.c 21.c) 320 Preferred Stock (112.3.c) 321 Common Stock (ln 317) 322 Total (sum lns 319 to 321) WACC= Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 23 of 45 pro forma Original Sheet No. 161D.13 AEP Transmission Formula Rate Template TCOS Utilizing FERC Form 1 Cost Data for Page 10 of 10 Historical Transmission Cost of Service HISTORICAL Company: Letter A B C D E F Notes General Notes: a) References to data from FERC Form 1 are indicated as: page#.line#.col.# b) If transmission owner ("TO") functionalizes its costs to transmission on its books, those costs are shown above and on any supporting workpapers rather than using the allocations above. The revenue credits shall include a) amounts received directly from the SPP for PTP transmission services, b) direct assignment charges for transmission facilities, the cost of which has been included in the TCOS, and c) amounts from customers taking service under grandfathered agreements, where the demand is not included in the rate divisor. Revenues associated with FERC annual charges, gross receipts taxes, ancillary services or facilities excluded from the TCOS are not included as revenue credits. Revenue from Transmission Customers whose coincident peak loads are included in the DIVISOR of the loadratio share calculation are not included as revenue credits. See Worksheet A for details. The annual and monthly net plant carrying charges on page 1 are used to compute the revenue requirement for facilities and any upgrades. This additional revenue requirement is determined using a net plant carrying charge (fixed carrying charge or FCR) approach. Worksheet F shows the calculation of the additional incentive revenue requirement for each project receiving incentive rate treatment, as accepted by FERC. These individual additional revenue requirements shall be summed, for the projected year, and included here. Reflects the transmission related portion of balances in Accounts 281, 282, 283, 190, 255 and, if applicable, 107. The balance of Account 255 is reduced by prior flow throughs and completely excluded if the utility chose to utilize amortization of tax credits against taxable income as discussed in Note M. An exception to this is pre1971 ITC balances, which are required to be taken as an offset to rate base. Account 281 is not allocated. Transmission allocations are shown on Worksheet C. Include Account 182.3, Other Regulatory Assets, related to Transmission Service under this Tariff, if any. Also include any unamortized balances related to precommercial operation costs when recovery of abandonment costs are granted. Identified as being transmission related or functionally booked to transmission. G Cash Working Capital assigned to transmission is oneeighth of O&M allocated to transmission on line 257. H Consistent with Paragraph 657 of Order 2003A, the amount on line 233 is equal to the balance of IPP System Upgrade Credits owed to transmission customers that made contributions toward the construction of System upgrades, and includes accrued interest and unreturned balance of contributions. The annual interest expense is included on line 285. I Removes the expense booked to transmission accounts included in the development of OATT ancillary services rates, including all of Account No. 561. J K L M Removes cost of transmission service provided by others to the extent such service is not incurred to provide the SPP service at issue. General Plant and Administrative & General expenses may be functionalized based on allocators other then the W/S allocator. Full documentation must be provided. Includes Regulatory Commission expenses itemized in FERC Form1 at page 351, column H. Worksheet D allocates these expense items. FERC Assessment Fees and Annual Charges shall not be allocated to transmission. Only safetyrelated and educational advertising costs in Account 930.1 are included in the TCOS. Includes only FICA, unemployment, highway, property and other assessments charged in the current year. Gross receipts tax and taxes related to income are excluded. N The currently effective income tax rate, where FIT is the Federal income tax rate; SIT is the State income tax rate, and p = "the percentage of federal income tax deductible for state income taxes". If the utility is taxed in more than one state it must attach a work paper showing the name of each state and how the blended or composite SIT was developed. Furthermore, a utility that elected to utilize amortization of tax credits against taxable income, rather than book tax credits to Account No. 255 and reduce rate base, must reduce its income tax expense by the amount of the Amortized Investment Tax Credit (Form 1, 266.8.f) (ln 280) multiplied by (1/1T). If the applicable tax rates are zero enter 0. Inputs Required: FIT = 0.00% SIT= 0.00% (State Income Tax Rate or Composite SIT. Worksheet J)) p = 0.00% (percent of federal income tax deductible for state purposes) O P Effective January 1, 2007, Texas instituted a gross margin tax. This tax is calculated on the Texas allocated revenue of the Company, reduced by 30% to derive a "Gross Margin" for the Company. The tax rate of one percent is assessed on the resulting amount. The jurisdictional allocator is based on transmission demand allocators. Removes plant excluded from the OATT because it does not meet the SPP's definition of Transmission Facilities or is otherwise ineligible to be recovered under the OATT. Q Removes transmission plant (e.g. stepup transformers) included in the development of OATT ancillary service rates and not already removed for reasons indicated in Note P. R Includes functional wages & salaries incurred by parent company service corporation for support of the operating company. S Long Term Debt cost rate = longterm interest (ln 311) / long term debt (ln 319). Preferred Stock cost rate = preferred dividends (ln 312) / preferred outstanding (ln 320). Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Exhibit No. AEP 101B Page 24 of 45 pro forma Original Sheet No. 161D.14 Worksheet List: A B C D E F G H I J K L Revenue Credits IPP System Upgrade Credit ADIT & ITC Details A&G Expense Detail Transmission Expense Adjustments ATRR Calculation for NonBase Plan Projects ATRR Calculation for SPP Base Plan Upgrades Transmission PlantinService Additions NonTax Balance Sheet Adjustments Tax CWIP Balances on MultiYear Projects GSU Net Book Values Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet A Revenue Credits Added Worksheet Exhibit No. AEP 101B Page 25 of 45 pro forma Original Sheet No. 161D.15 Total Non Company Transmission Transmission I. Account 450, Forfeited Discounts $0 II. Account 451,Miscellaneous Service Revenues $0 III. Account 454, Rent from Electric Property Account 4540001 Rent from Elect PropertyAff Account 4540002 Rent from Elect Property NonAff Account 4540003 Rent from Elect Property ABD Aff Account 4540004 Rent from Elect Property ADB NonAff Total Rents from Electirc Property $0 $0 ( Revenue related to transmission facilities for pole attachments, rentals, etc. Provide data sources and explanations in Section VIII, Notes below ) IV. Account 4560015, Revenues from Associated Business Development Account 4560015, Revenues from Associated Business Development V. Total Other Operating Revenues To Reduce Revenue Requirement $0 VI. Account 456.0, Revenues from Transmission of Electricity of Others ( Provide data sources and any detailed explanations necessary in Section VIII, Notes below ) Less: TO's LSE Direct Assignment Revenue Credits TO's LSE Sponsored Upgrade Revenue Credits TO's LSE Network Upgrades for Generation Interconnection Credits TO's PointToPoint Revenue for GFA's Associated with Load Included in the Divisor Network Service Revenue (Schedule 9) Associated With Load Included in the Divisor TO's Revenue Associated with Transmission Plant Excluded From SPP Tariff Wholesale Distribution charges TO's LSE Revenue from Ancillary Services Provided Base Plan Revenue Received Other (Flow Through of ERCOT Ancillary Charges) Other Net Transmission Credits $0 VII. Total Worksheet A Revenue Credits $0 VIII. Data Sources: Data for this worksheet came from the FERC Form 1 and the Company's General Ledger. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Exhibit No. AEP 101B Page 26 of 45 pro forma Original Sheet No. 161D.16 Worksheet B IPP System Upgrade Credit Line No. Account 2530067 Transmission Owner 1 Funds from IPP Customers 2 Transimission Credits given back over the years: 3 4 5 6 7 8 $0 9 10 Net balance of IPP Funds Received Credited Back $0 11 Interest Accrued over the years: 12 13 14 15 16 17 $0 18 Net Funds from IPP Customers 12/31/2006 (FORM 1, P269, line 7(f)) $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet C ADIT & ITC Details Added Worksheet Exhibit No. AEP 101B Page 27 of 45 pro forma Original Sheet No. 161D.17 (A) (B) (C) (D) (E) (F) (G) (H) (I) 100% 100% Transmission Transmission & Transmission Total Included 2006 NonTransmission Transmission Plant Distribution Labor in Ratebase Acc. No. Description YE Balance Related Related Related Plant Related Related (F)+(G)+(H) Account 281 Subtotal Form 1, p273 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 282 Subtotal Form 1, p274 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 283 Subtotal Form 1, p277 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 190 NOTE: Insert Amounts as Negative Numbers Subtotal Form 1, p234 Less FASB 109 Above if not separately removed Less FASB 106 Above if not separately removed Less OCI & NonUtility above, if not seperately removed. Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Account 255 Subtotal Form 1, p266.8f Less Post 1971 ITC Property Under F2 Option Total Transmission Allocator [ GP or W/S ] 0.0000% 100.0000% 0.0000% 0.0000% 0.0000% Total 0 0 0 0 0 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Exhibit No. AEP 101B Page 28 of 45 pro forma Original Sheet No. 161D.18 Worksheet D A&G Expense Detail (A) (B) (C) (D) (E) (F) (G) 100% 100% Transmission Transmission Item No. Description Expense NonTransmission Specific Allocated Explanation Account 928 Total Account 930.1 Total Account 930.2 Total $0 $0 $0 $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Worksheet E Transmission Expense Adjustments Exhibit No. AEP 101B Page 29 of 45 pro forma Original Sheet No. 161D.19 2006 1 Other Expenses 2 Direct Assignment Charge 3 Sponsored Upgrades Charge 4 Firm and NonFirm PointToPoint Charges 5 Base Plan Charges 6 Schedule 9 Charges 7 SPP Schedule 12 FERC Assessment 8 SPP Schedule 1A 9 SPP Annual Assessment 10 Ancillary Services Expenses 11 Other 12 Other 13 Other 14 Total ( sum of lines 2 through 13 ) $0 Adjustment to charges that are booked to transmission accounts that are the responsibility of the TO's LSE. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101B Page 30 of 45 Southwest Power Pool pro forma Original Sheet No. 161D.20 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 1 of 3 I. Calculate Return and Income Taxes with 0 basis point ROE increase. A. Determine 'R' with hypothetical 0 basis point increase in ROE for Identified Projects ROE w/o incentives (Attachment H, ln 160) 0% Project ROE Incentive Adder 0 ROE with additional 0 basis point incentive 0% Determine R ( cost of long term debt, cost of preferred stock and percent is from Attachment H, lns 158 through160) % Cost Weighted cost Long Term Debt Preferred Stock Common Stock WACC = 0.0000 B. Determine Return using 'R' with hypothetical 0 basis point ROE increase for Identified Projects. Rate Base (Attachment H, ln 73) $0 R (fom A. above) 0.0000 Return (Rate Base x R) $0 C. Determine Income Taxes using Return with hypothetical 0 basis point ROE increase for Identified Projects. Return (from B. above) $0 CIT (Attachment H, ln 115) 0.00% Income Tax Calculation (Return x CIT) $0 ITC Adjustment (Attachment H, ln 121) $0 Income Taxes $0 II. Calculate Net Plant Carrying Charge Rate (Fixed Charge Rate or FCR) with hypothetical 0 basis point ROE increase. A. Determine Net Revenue Requirement less return and Income Taxes. Net Revenue Requirement (Attachment H, ln 6) $0 Return (Attachment H, ln 123) $0 Income Taxes (Attachment H, ln 122) $0 Gross Margin Taxes (Attachment H, ln 127) $0 Net Revenue Requirement, Less Return and Taxes $0 B. Determine Net Revenue Requirement with hypothetical 0 basis point increase in ROE. Net Revenue Requirement, Less Return and Taxes $0 Return (from I.B. above) $0 Income Taxes (from I.C. above) $0 Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase Gross Margin Tax with 0 Basis Point ROE Increase (II C. below) $0 Revenue Requirement w/ Gross Margin Taxes $0 Less: Depreciation (Attachment H, ln 98) $0 Net Rev. Req, w/0 Basis Point ROE increase, less Depreciation $0 C. Determine Gross Margin Tax with hypothetical 0 basis point increase in ROE. Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase (II B. above) Addback Revenue Credits for Correct Gross Margin Tax Basis $0 Proper Basis for Caclulating Gross Margin Tax $0 Gross Margin Taxes with 0 Basis Point ROE increase Apportionment Factor to Texas (Worksheet J, ln 12) 0% Apportioned Texas Revenues $0 Taxable Percentage of Revenue (%) 0% Taxable, Apportioned Margin $0 Texas Gross Margin Tax Rate 0% Texas Gross Margin Tax Expense $0 Grossup Required for Gross Margin Tax Expense $0 Total Additional Gross Margin Tax Revenue Requirement $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101B Page 31 of 45 Southwest Power Pool pro forma Original Sheet No. 161D.21 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 2 of 3 D. Determine FCR with hypothetical 0 basis point ROE increase. Net Transmission Plant (Attachment H, ln 42) $0 Net Revenue Requirement, with 0 Basis Point ROE increase $0 FCR with 0 Basis Point increase in ROE 0% Net Rev. Req, w / 0 Basis Point ROE increase, less Dep. $0 FCR with 0 Basis Point ROE increase, less Depreciation 0% FCR less Depreciation (Attachment H, ln 13) 0% Incremental FCR with 0 Basis Point ROE increase, less Depreciation 0% III. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) $0 Transmission Plant @ End of Period (P.207, ln 58) $0 $0 Average Balance of Transmission Investment $0 Annual Depreciation Rate (P. 336, ln. 7, col. F) $0 Composite Depreciation Rate 0% Depreciable Life for Composite Depreciation Rate 0 YEARS Round to nearest whole year 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101B Page 32 of 45 Southwest Power Pool pro forma Original Sheet No. 161D.22 FERC Electric Tariff SWEPCO Worksheet F ATRR Calculation for NonBase Plan Projects Page 3 of 3 IV. Determine Revenue Requirement & Additional Revenue Requirement for facilities receiving incentives. A. Facilities receiving incentives accepted by FERC in Docket No. (e.g. ER05925000) Project Description: Details Investment $0 Current Year 0 Service Year (yyyy) 0 ROE increase accepted by FERC (Basis Points) 0 Service Month (112) 0 FCR w/o incentives, less depreciation 0% Useful life 0 FCR w/incentives approved for these facilities, less dep. 0% CIAC (Yes or No) Annual Depreciation Expense $0 Investment Beginning Depreciation Ending Revenue Revenue Req't. Additional Rev. Year Balance Expense Balance Requirement with Incentives ** Requirement 1 $ 2 $ 3 $ 4 $ 5 $ 6 $ 7 $ 8 $ 9 $ 10 $ 11 $ 12 $ 13 $ 14 $ 15 $ 16 $ 17 $ 18 $ 19 $ 20 $ 21 $ 22 $ 23 $ 24 $ 25 $ 26 $ 27 $ 28 $ 29 $ 30 $ 31 $ 32 $ 33 $ 34 $ 35 $ 36 $ 37 $ $ ## This is the calculation of additional incentive revenue on projects deemed by the FERC to be eligible for an incentive return. This additional incentive requirement is applicable for the life of this specific project. Each year the revenue requirement calculated for SPP should be incremented by the amount of the incentive revenue calculated for that year on this project. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101B Page 33 of 45 Southwest Power Pool pro forma Original Sheet No. 161D.23 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 1 of 3 I. Calculate Return and Income Taxes with 0 basis point ROE increase for Projects Qualified for Incentive. A. Determine 'R' with hypothetical 0 basis point increase in ROE for Identified Projects ROE w/o incentives (Attachment H, ln 160) 0% Project ROE Incentive Adder 0 ROE with additional 0 basis point incentive 0% Determine R ( cost of long term debt, cost of preferred stock and percent is from Attachment H, lns 158 through160) % Cost Weighted cost Long Term Debt Preferred Stock Common Stock WACC = 0.0000 B. Determine Return using 'R' with hypothetical 0 basis point ROE increase for Identified Projects. Rate Base (Attachment H, ln 73) $0 R (fom A. above) 0.0000 Return (Rate Base x R) $0 C. Determine Income Taxes using Return with hypothetical 0 basis point ROE increase for Identified Projects. Return (from B. above) $0 CIT (Attachment H, ln 115) 0.00% Income Tax Calculation (Return x CIT) $0 ITC Adjustment (Attachment H, ln 121) $0 Income Taxes $0 II. Calculate Net Plant Carrying Charge Rate (Fixed Charge Rate or FCR) with hypothetical 0 basis point ROE increase. A. Determine Net Revenue Requirement less return and Income Taxes. Net Revenue Requirement (Attachment H, ln 6) $0 Return (Attachment H, ln 123) $0 Income Taxes (Attachment H, ln 122) $0 Gross Margin Taxes (Attachment H, ln 127) $0 Net Revenue Requirement, Less Return and Taxes $0 B. Determine Net Revenue Requirement with hypothetical 0 basis point increase in ROE. Net Revenue Requirement, Less Return and Taxes $0 Return (from I.B. above) $0 Income Taxes (from I.C. above) $0 Net Revenue Requirement before Gross Margin Taxes, with 0 $0 Basis Point ROE increase Gross Margin Tax with 0 Basis Point ROE Increase (II C. below) $0 Revenue Requirement w/ Gross Margin Taxes $0 Less: Depreciation (Attachment H, ln 98) $0 Net Rev. Req, w/0 Basis Point ROE increase, less Depreciation $0 C. Determine Gross Margin Tax with hypothetical basis point increase in ROE. Net Revenue Requirement before Gross Margin Taxes, with $0 Basis Point ROE increase (II B. above) Addback Revenue Credits for Correct Gross Margin Tax Basis $0 Proper Basis for Caclulating Gross Margin Tax $0 Gross Margin Taxes with Basis Point ROE increase Apportionment Factor to Texas (Worksheet J, ln 12) 0% Apportioned Texas Revenues $0 Taxable Percentage of Revenue (%) 0% Taxable, Apportioned Margin $0 Texas Gross Margin Tax Rate 0% Texas Gross Margin Tax Expense $0 Grossup Required for Gross Margin Tax Expense $0 Total Additional Gross Margin Tax Revenue Requirement $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101B Page 34 of 45 Southwest Power Pool pro forma Original Sheet No. 161D.24 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 2 of 3 D. Determine FCR with hypothetical 0 basis point ROE increase. Net Transmission Plant (Attachment H, ln 42) $0 Net Revenue Requirement, with 0 Basis Point ROE increase $0 FCR with 0 Basis Point increase in ROE 0% Net Rev. Req, w / 0 Basis Point ROE increase, less Dep. $0 FCR with 0 Basis Point ROE increase, less Depreciation 0% FCR less Depreciation (Attachment H, ln 13) 0% Incremental FCR with 0 Basis Point ROE increase, less Depreciation 0% III. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) $0 Transmission Plant @ End of Period (P.207, ln 58) $0 $0 Average Balance of Transmission Investment $0 Annual Depreciation Rate (P. 336, ln. 7, col. F) $0 Composite Depreciation Rate 0% Depreciable Life for Composite Depreciation Rate 0 YEARS Round to nearest whole year 0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Added Worksheet Exhibit No. AEP 101B Page 35 of 45 Southwest Power Pool pro forma Original Sheet No. 161D.25 FERC Electric Tariff Worksheet G ATRR Calculation for SPP Base Plan Upgrades Page 3 of 3 IV. Determine Revenue Requirement & Additional Revenue Requirement for facilities receiving incentives. A. Base Plan Facilities Facilities receiving incentives accepted by FERC in Docket No. (e.g. ER05925000) Project Description: Details Investment $0 Current Year 0 Service Year (yyyy) 0 ROE increase accepted by FERC (Basis Points) 0 Service Month (112) 0 FCR w/o incentives, less depreciation 0% Useful life 0 FCR w/incentives approved for these facilities, less dep. 0% CIAC (Yes or No) Annual Depreciation Expense $0 Investment Beginning Depreciation Ending BPU Rev. Req't. BPU Rev. Req't. Incentive Rev. Year Balance Expense Balance w/o Incentives with Incentives** Requirement## 0 $ 1 $ 2 $ 3 $ 4 $ 5 $ 6 $ 7 $ 8 $ 9 $ 10 $ 11 $ 12 $ 13 $ 14 $ 15 $ 16 $ 17 $ 18 $ 19 $ 20 $ 21 $ 22 $ 23 $ 24 $ 25 $ 26 $ 27 $ 28 $ 29 $ 30 $ 31 $ 32 $ 33 $ 34 $ 35 $ 36 $ Project Totals ** This is the total amount that needs to be reported to SPP for billing to all regions. ## This is the calculation of additional incentive revenue on projects deemed by the FERC to be eligible for an incentive return. This additional incentive requirement is applicable for the life of this specific project. Each year the revenue requirement calculated for SPP should be incremented by the amount of the incentive revenue calculated for that year on this project. Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Worksheet H Transmission PlantinService Additions I. Calculation of Composite Depreciation Rate Transmission Plant @ Beginning of Period (P.206, ln 58) Transmission Plant @ End of Period (P.207, ln 58) Average Balance of Transmission Investment Annual Depreciation Rate (P. 336, ln. 7, col. F) Composite Depreciation Rate Round to % to Reflect a Composite Life of Years Added Worksheet Exhibit No. AEP 101B Page 36 of 45 pro forma Original Sheet No. 161D.26 II. Calculation of Property Placed in Service by Month and the Related Depreciation Expense Month in Service Capitalized Balance Composite Annual Depreciation Rate Annual Depreciation Monthly Depreciation No. Months Depreciation First Year Depreciation Expense January 0.00% 11 February 0.00% 10 March 0.00% 9 April 0.00% 8 May 0.00% 7 June 0.00% 6 July 0.00% 5 August 0.00% 4 September 0.00% 3 October 0.00% 2 November 0.00% 1 December 0.00% 0 Investment $ Depreciation Expense $ III. Plant Transferred $ <== This input area is for original cost plant $ <== This input area is for accumulated depreciation that may be associated with capital expenditures. It would have an impact if a company had assets transferred from a subsidiary. $ <== This input area is for additional Depreciation Expense Issued by: L. Patrick Bourne, Director Issued on: Effective:

Issued by: L. Patrick Bourne, Director Issued on: Effective: Worksheet I NonTax Balance Sheet Adjustments Preferrered Stock Preferred Stock DividendsEffective Cost Based on YE Outstanding Shares Shares Outstanding @ 12/31/XX Par Value Book Value Dividend Rate Dividend Form 1 P. 251.e $ Effective Cost of Preferred Stock % Prepayments Account 165 (A) (B) (C) (D) (E) (F) (G) (H) 100% 100% Transmission Transmission Total Included NonTransmission Transmission Plant Labor in Ratebase Acc. No. Description YE Balance Related Related Related Related (E)+(F)+(G) Subtotal Form 1, p 112.57.c 0 0 0 0 0 0 Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.27 Added Worksheet Exhibit No. AEP 101B Page 37 of 45

Issued by: L. Patrick Bourne, Director Issued on: Effective: PSO Worksheet J Tax I. DEVELOPMENT OF COMPOSITE STATE INCOME TAX RATES II. Public Service Company of Oklahoma Calculation of Effective State Income Tax Rate For Tax Year 20XX State I Income Tax Rate Apportionment Factor Effective State Income Tax Rate 0.0000% State II Income Tax Rate Apportionment Factor Effective State Income Tax Rate 0.0000% Total Effective State Income Tax Rate 0.0000% CALCULATION OF TEXAS GROSS MARGIN TAX Total Company Trans. Only Total Company Trans. Only Line # REVENUE REQUIREMENT BEFORE TEXAS GROSS MARGIN TAX (ln 284 of Template) 147,553,686 37,758,675 1 Apportionment Factor to Texas (ln12) 0.00% 0.00% 0.00% 0.00% 2 Apportioned Texas Revenues $0 $0 $0 $0 3 Taxable Percentage of Revenue (70%) 70% 70% 70% 70% 4 Taxable, Apportioned Margin 5 Texas Gross Margin Tax Rate (1%) 1% 1% 1% 1% 6 Texas Gross Margin Tax Expense 7 Grossup Required for Texas Gross Margin Expense ((ln 6 * ln 3 * ln 1)/(1 ln 5) * ln 5) 8 Total Additional Gross Margin Tax Revenue Requirement 9 WHOLESALE LOAD ALLOCATOR (For Use in Gross Margin Tax Allocator) 10 Texas Jurisdictional Load 11 Total Load 12 Allocation Percentage (ln 10 / ln 11) 0.00% Actual Projected Southwest Power Pool FERC Electric Tariff pro forma Original Sheet No. 161D.28 Added Worksheet Exhibit No. AEP 101B Page 38 of 45

Southwest Power Pool FERC Electric Tariff Added Worksheet Worksheet K CWIP Balances on MultiYear Projects Exhibit No. AEP 101B Page 39 of 45 pro forma Original Sheet No. 161D.29 (A) (B) (C) Capital Item No. Descrition of Project Expenditure Total Issued by: L. Patrick Bourne, Director Issued on: Effective:

Southwest Power Pool FERC Electric Tariff Added Worksheet Exhibit No. AEP 101B Page 40 of 45 pro forma Original Sheet No. 161D.30 Worksheet L GSU Net Book Values as of December 31, 20XX company depreciation group utility acct vintage orig cost reserve net book value Total Transmission Investment $0 $0 $0 Less: GSU Investment $0 $0 $0 Transmission w/o GSUs $0 $0 $0 Issued by: L. Patrick Bourne, Director Issued on: Effective:

Exhibit No. AEP 101B Page 41 of 45 Southwest Power Pool Original Sheet No. 217 FERC Electric Tariff ATTACHMENT T Rate Sheets For PointToPoint Transmission Service Issued by: L. Patrick Bourne, Manager Issued on: February 28, 2005 Effective: May 5, 2005

Exhibit No. AEP 101B Page 42 of 45 Southwest Power Pool pro forma ThirdSecond Revised Sheet No. 218 FERC Electric Tariff Superseding First Second Revised Sheet No. 218 American Electric Power WestZone 1 Rate Sheet For PointtoPoint Transmission Service Firm PointtoPoint Transmission Service The Transmission Customer shall compensate the Transmission Provider each month for Reserved Capacity at the sum of the applicable charges set forth below: 1. Monthly delivery: $1528.301090.33/MW of Reserved Capacity per month. 2. Weekly delivery: $ 352.66250.92/MW of Reserved Capacity per week. 3. Daily delivery: OnPeak: $ 70.5450.19/MW of Reserved Capacity per day. OffPeak: $ 50.2535.85/MW of Reserved Capacity per day. The total demand charge in any week, pursuant to a reservation for Daily delivery, shall not exceed the rate specified in Section 2 above times the highest amount in megawatts of Reserved Capacity in any day during such week. For the purpose of the rate specified in Section 3 above, the OffPeak Period shall be Saturdays, Sundays, New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the OnPeak Period shall be all days that are not in the OffPeak Period. NonFirm PointtoPoint Transmission Service The Transmission Customer shall compensate the Transmission Provider for NonFirm PointToPoint Transmission Service up to the sum of the applicable charges set forth below: 1. Monthly delivery: $1528.301090.33/MW of Reserved Capacity per month. 2. Weekly delivery: $ 352.66250.92/MW of Reserved Capacity per week. 3. Daily delivery: OnPeak: $ 70.5450.19/MW of Reserved Capacity per day. OffPeak $ 50.2535.85/MW of Reserved Capacity per day. 4. Hourly delivery: OnPeak: $ 4.413.14/MW of Reserved Capacity per hour. OffPeak $ 2.101.50/MW of Reserved Capacity per hour. Issued by: L. Patrick Bourne, Director Issued on: December 29, 2006 Effective: January 1, 2007

Southwest Power Pool pro forma SecondFirst Revised Sheet No. 219 FERC Electric Tariff Superseding First RevisedOriginal Sheet No. 219 The total demand charge in any day, pursuant to a reservation for Hourly delivery, shall not exceed the rate specified in Section 3 above times the highest amount in megawatts of Reserved Capacity in any hour during such day. In addition, the total demand charge in any week, pursuant to a reservation for Hourly or Daily delivery, shall not exceed the rate specified in Section 2 above times the highest amount in megawatts of Reserved Capacity in any hour during such week. For the purpose of the rate specified in Section 3 above, the OffPeak Period shall be Saturdays, Sundays, New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day and the OnPeak Period shall be all days that are not in the OffPeak Period. For the purpose of the rate specified in Section 4 above, OnPeak is all hours between HE 0700 and HE 2200, inclusive, Central Time Zone, excluding Sundays and holidays. Holidays shall be as defined by NERC, currently New Year s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas Day. OffPeak is all hours not designated as On Peak. Discounts for Certain Through and Out Service Transactions Via American Electric Power (Public Service Company of Oklahoma, Southwestern Electric Power Company, and SPP portion of Texas North Company) Pricing Zone: For the purpose of this Section, the following definitions shall apply: Exhibit No. AEP 101B Page 43 of 45 CPL: AEP: AEP Operating Companies' Tariff: ERCOT: Central Power and Light Company. American Electric Power, Inc. including its operating company affiliates located in the SPP region (Public Service Company of Oklahoma, Southwestern Electric Power Company, and the SPP portion of Texas North Company). The open access transmission service tariff on file with the Commission under which the AEP Operating Companies offer, among other services, ERCOT Regional Transmission Service. The Electric Reliability Council of Texas. Issued by: L. Patrick Bourne, Manager Issued on: March 1, 2005 Effective: May, 1 2005

Exhibit No. AEP 101B Page 44 of 45 Southwest Power Pool FERC Electric Tariff First RevisedOriginal Sheet No. 219A Superseding Original Sheet No. 219A ERCOT Power Supplier:. An electric utility that sells electricity for resale into ERCOT and takes transmission service under Part IV of the AEP Operating Companies' Tariff for such sales. RESERVED Issued by: L. Patrick Bourne, Manager Issued on: March 1, 2005 Effective: May, 1 2005

Exhibit No. AEP 101B Page 45 of 45 Southwest Power Pool pro forma First Revised Original Sheet No. 220 FERC Electric Tariff Superseding Original Sheet No. 220 Load Serving Entity: Native Load Customer: Planned Resource: Unplanned Resource: WTU: Any electric utility operating in ERCOT that serves Native Load Customers within ERCOT. The wholesale and retail power customers of CPL and WTU on whose behalf CPL and WTU, by statute, franchise, regulatory requirement, or contract, have undertaken an obligation to construct and operate the CPL and WTU systems to meet the reliable electric needs of such customers or the wholesale and retail power customers of a Load Serving Entity, by statute, franchise, regulatory requirement, or contract has undertaken an obligation to plan, construct and operate the Load Serving Entity's system to meet the reliable electric needs of such customers. Native Load Customers do not include load served outside of ERCOT. Any generation resource owned, controlled, or purchased by an ERCOT Power Supplier or Load Serving Entity and designated as a Planned Resource for the purpose of serving load located in ERCOT. RESERVED Any generation resource owned or purchased by an ERCOT Power Supplier or Load Serving Entity, used to serve loads within ERCOT and not designated as a Planned Resource. West Texas Utilities Company. Discount Provision: A Load Serving Entity that takes ERCOT Regional Transmission Service under Part IV of the AEP Operating Companies' Tariff and also takes transmission service under Part II of this Tariff to import into ERCOT Planned Resources or Unplanned Resources to serve its Native Load Customers in ERCOT shall have its zonal rates under Schedules 7 and 8 reduced by 45.27% in instances when AEP is the applicable pricing zone under the SPP Tariff. This discount applies only to charges under Schedules 7 and 8 of the SPP Tariff. Issued by: L. Patrick Bourne, Manager Issued on: October 27, 2000 Effective: November 1, 2000