Securities and Exchange Commission

450 Fifth Street NW

Washington, DC 20549

April 14, 2005

RE:American Electric Power Company, Inc., File No. 1-3525

    AEP Generating Company, File No. 0-18135

    AEP Texas Central Company, File No. 0-346

    AEP Texas North Company, File No. 0-340

    Appalachian Power Company, File No. 1-3457

    Columbus Southern Power Company, File No. 1-2680

    Indiana Michigan Power Company, File No. 1-3570

    Kentucky Power Company, File No. 1-6858

    Ohio Power Company, File No. 1-6543

    Public Service Company of Oklahoma, File No. 0-343

    Southwestern Electric Power Company, File No. 1-3146

    Form 10-K for the fiscal year ended December 31, 2004

    Filed March 2, 2005

Responses to the comment letter dated March 30, 2005 from the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) regarding the above-captioned Report are provided herewith, including the text of the Staff’s comments.

Form 10-K for the fiscal year ended December 31, 2004

General

1.Unless otherwise indicated, where a comment below requests additional disclosures or other revisions to be made, these revisions should be included in your future filings, as applicable. Although each comment has been issued only once, the comments below may be applicable to each registrant reviewed.

2.We note references throughout the filing regarding coal reserves; however, you do not disclose reserve quantity estimates or any information about the reserves. We note you sold AEP Coal, Inc. in March 2004. As such, if you do not continue to own any interests in coal reserves, please clarify in future filings. Otherwise, please supplementally tell us the location of any interests in coalmines or properties for each affiliate, including quantities of estimated reserves. Also provide an analysis of the materiality of any mineral property holdings relative to your total assets, revenues and income for the past three years for each registrant. Finally, explain to us how coal sales to affiliates are treated for ratemaking purposes.

RESPONSE:

In response to the Staff’s comment, following are the estimated recoverable coal and lignite reserves as of 12/31/04 by registrant:

Registrant	Location of Reserves (State)	Tons (in thousands)	Recorded Value at 12/31/04 ($ millions)	Total Assets at 12/31/04 ($ billions)	Status at 12/31/04
Appalachian Power Company	IN/WV	229,672	10.1	5.2	Inactive
Indiana Michigan Power Company	IN/UT	208,984	19.7	4.9	Inactive
Ohio Power Company	IN/OH/WV	223,754	11.7	5.6	Inactive
Columbus Southern Power Company	OH	57,158	9.7	3.0	Inactive
Kentucky Power Company	IN	31,078	1.1	1.2	Inactive
Southwestern Electric Power Company	LA, TX Lignite Reserves	37,767	8.0	2.6	Active

The above reserves have not been actively mined for over three years with the exception of SWEPCo’s lignite reserves. SWEPCo’s reserves are mined and used solely for fuel at plants owned by SWEPCo and are included in the appropriate jurisdictional fuel clause. All of the registrants’ reserves are immaterial as there are no associated sales revenues and the net book value is less than 1% of total assets.

As described in our 2004 10-K on page L-86, the only coal fuel stock supplied to a registrant by an affiliate was from AEP Coal Inc. to Columbus Southern Power Company (CSPCo). This affiliate transaction ended during the second quarter of 2004 after the divestiture of AEP Coal Inc. There was no impact on rate making because CSPCo fuel costs were not subject to a rate making process.

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Item 9A. Controls and Procedures

3.Please amend your Form 10-K to incorporate the following changes to your Item 9A., Contro1s and Procedures:

(a)We note your disclosure that your disclosure contro1s and procedures have been designed to ensure that “this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms.” As you have included a portion of the definition of disclosure contro1s and procedures in your disclosure, you must include the entire definition. As such, revise to clarify, if true, that your disclosure contro1s and procedures are also designed to ensure that information required to be disclosed in the reports that you file or submit under the Exchange Act is accumulated and communicated to your management, including your CEO and CFO, to allow timely decisions regarding required disclosure. See Exchange Act Rule 13a-15(e).

(b)Please revise to provide an unqualified conclusion as to whether there were any changes in your internal control over financial reporting during your most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, your internal control over financial reporting. Your current conclusion, which includes qualifying language, is not sufficient in this regard. Further, you state that there were no significant changes in your internal contro1s that have materially affected these contro1s subsequent to the date of your evaluation. However, Item 308(c) of Regulation S-K requires that you disclose any change in your internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during your last fiscal quarter that has materially affected, or is reasonably likely to materially affect, your internal control over financial reporting. Revise your disclosures accordingly. Finally, refer to internal control over financial reporting defined in Exchange Act Rules 13a-15(f) and 15d-15(f), rather than the incorrect location you refer to now. See Item 308 of Regulation S-K.

RESPONSE:

In response to Staff comments 3(a) and (b), we will amend our Form 10-K to restate Item 9A., Controls and Procedures as follows:

During 2004, management, including the principal executive officer and principal financial officer of AEP, AEPGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC (collectively, the “Registrants”), evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Act are recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2004, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

The only change in AEP’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2004 that materially affected, or is reasonably likely to materially affect, AEP’s internal controls over financial reporting, relates to AEP’s and AEP’s East Zone public utility subsidiaries’ integration with PJM on October 1, 2004, which resulted in our implementing and modifying a number of business processes and controls to facilitate participation in, and resultant settlement within, the PJM market.

* * *

2004 Annual Reports

AEP Generating Company

Management’s Narrative Financial Discussion and Analysis

Contractual Cash Obligations

4.Please revise your table of contractual cash obligations to include long-term debt as required by Item 303(a)(5) of Regulation S-K. Further, we note per review of your balance sheet that you have approximately $12.5 million in capital lease obligations as of December 31, 2004. However, your table of contractual cash obligations includes total obligations of $22.9 million. Please supplementally reconcile this difference. Finally, consider revising your table to include the following:

(a) Estimated interest payments on your debt;

(b) Estimated payments under interest rate swap agreements; and

(c) Planned funding of pension and other postretirement benefit obligations. Because the table is aimed at increasing transparency of cash flow, we believe these payments could be included in the table. If you choose not to include these payments, a footnote to the table should clearly identify the excluded items and provide any additional information that is material to an understanding of your cash requirements. See Section IV.A and footnote 46 to the Commission’s MD&A Guidance issued December 19, 2003, available at www.sec.gov.

RESPONSE:

We have reflected long-term debt in the Contractual Cash Obligations table (“Obligations Table”) in our Form 10-K for all registrants except AEP Generating Company (AEPGCo). We inadvertently omitted AEPGCo’s long-term debt from its Obligations Table. AEPGCo’s long-term debt of $44.8 million due 2006 is fully disclosed on the Schedule of Long-Term Debt and the Balance Sheet on pages B-8 and B-6, respectively. Commencing with the 2005 Form 10-K, where the Obligations Table is presented, we will include long-term debt in AEPGCo’s table.

For each registrant, we include notes to the Contractual Obligations Table describing what is included and excluded in the tables and we will continue to review these notes for clarity and inclusion of pertinent information.

Consistent with the presentation on all registrants, the difference between total capital lease obligations presented on the balance sheet versus the Obligations Table relates to the interest component of the capital lease obligations. The interest component is not included on the balance sheet in accordance with Statement of Financial Accounting Standards (SFAS) 13, Accounting for Leases; however, the full lease payment obligation is included in the Obligations Table. The Obligations Table contains a footnote referencing the reader to footnote 15 for registrant subsidiaries and footnote 16 for AEP where the capital lease interest component difference is shown. For AEPGCo, the table on page L-75 reconciles the $22.9 million to the $12.5 million, with the reconciling difference being the interest component.

For each registrant except AEPGCo, we disclosed in footnotes to the Obligations Table that the long-term debt represents principal only and excludes interest. Commencing with the 2005 Form 10-K, for all of our registrants, we will include estimated interest payments associated with our existing fixed-rate debt. Estimated interest payments on our variable rate debt are based on future market conditions and are difficult to project. Therefore, we will provide a footnote to the table that indicates the variable rate debt is excluded and we will disclose the nature and terms of the variable rate debt in the footnote.

The fair value of AEP’s estimated payments under interest rate swap agreements as of December 31, 2004 was $6.1 million, which includes the following amounts related to the registrant subsidiaries. Because the amounts are not material at the registrant level, these amounts have not been separately disclosed on their obligations tables:

Appalachian Power Company       $ 76,000

Indiana Michigan Power Company           237,000

Kentucky Power Company(614,000) (asset balance at year-end)

Please note that AEPGCo’s pension obligations are zero because it has no employees. As it relates to the remaining registrant subsidiaries, as disclosed immediately following the AEP Obligations Table on page A-25 we refer the reader to footnote 11 (Benefit Plans) and indicated that our minimum pension funding requirements are not included in the table as such amounts are discretionary based on the status of the trust. As it relates to our other registrant subsidiaries, we did not include any disclosure of or reference to pension obligations relating to the Obligations Table, as pension matters are determined at the AEP parent company level. Commencing with the 2005 Form 10-K, we will include a footnote to the Obligations Table of the registrant subsidiaries referring the reader to the benefit plan footnote for further information regarding projected future contributions. The discretionary funding of benefit plans is discussed on page M-10 in the combined MD&A of the registrant subsidiaries.

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Balance Sheets

5.You enumerate the registrant subsidiaries that have cost-based rate regulated operations in Note 1, Revenue Recognition-Regulatory Accounting, and AEPGCo is not included. It is not clear whether AEPGCo has cost-based rate regulated operations based on this disclosure. Your description of the FERC approved agreements suggests recovery of costs including a return. We assume since you present both regulatory assets and liabilities on the balance sheet, AEPGCo applies SFAS 71. Please explain in detail how you meet the scope criteria of paragraph 5 of SFAS 71. Further, using the guidance provided in paragraphs 9 and 11, please explain why you concluded these regulatory assets and liabilities exist. Finally, if AEPGCo is cost-based rate regulated, explain to us why the achieved rate of return appears low. You may want to give us a background along with the actual “FERC approved rate of return” and the achieved rate of return for the past 3 years.

RESPONSE:

AEPGCo is a cost-based rate regulated company. In the Management’s Narrative Financial Discussion and Analysis for AEPGCo on page B-2, we state that AEPGCo’s unit power agreements provide for a FERC approved rate of return on common equity, a return on other capital, and recovery of costs.

We also state that the Registrant Subsidiaries are cost-based rate regulated companies in Footnote 1 under the subheading “Accounting for the Effects of Cost-Based Regulation” on page L-2. The first sentence of that paragraph states: “As cost-based rate-regulated electric public utility companies, the Registrant Subsidiaries’ financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.” Registrant Subsidiaries is a defined term in the Glossary and this definition includes AEPGCo.

Commencing with the 2005 Form 10-K, we will also list AEPGCo as a cost-based rate-regulated company in Footnote 1 under the subheading, Revenue Recognition - Regulatory Accounting.

Paragraph 5 of SFAS 71 requires that three criteria be met to apply SFAS 71. AEPGCo meets those criteria as shown below:

·   Paragraph 5a states that the rates for regulated services be established by an independent, third-party regulator. The Federal Energy Regulatory Commission (FERC) regulates AEPGCo’s wholesale energy sales under the authority of the Federal Power Act. AEPGCo’s tariffs and contracts are approved by the FERC.

·   The regulated rates are designed to recover the costs of providing services as required by paragraph 5b. The approved FERC rate schedules filed by AEPGCo address all costs of AEPGCo for each FERC account. The rate schedules include a rate design and a formula for cost recovery including a return on common equity.

·   Paragraph 5c requires that the rates designed in the rate making process are established and approved in a manner that is reasonably expected to recover costs, plus an approved return, considering demand. AEPGCo’s rate design is consistent with this requirement.

As disclosed on page B-2, AEPGCo only sells power to two affiliate companies, Indiana Michigan Power Company and Kentucky Power Company. AEPGCo accumulates all expenses monthly and bills these expenses to the affiliates. The rate schedules have been in effect since December 1984. Additionally, the FERC approved an extension of the unit power agreements with Kentucky Power Company on December 29, 2004, which extends the agreements until December 2022 using the same formula rates as the original agreement.

The criteria under paragraph 9 of SFAS 71 were used to conclude that the regulatory assets are properly reflected on AEPGCo’s books. AEPGCo’s regulatory assets consist of the following items at December 31, 2004:

·   $4.5 million represents costs related to early redemption of long-term debt. These costs were ordered by the FERC to be recorded as regulatory assets, and the FERC additionally specified the amortization schedule for these assets. Paragraph 9a states that amounts can be classified as regulated assets if it is probable that future revenue in an amount equal to the cost will result from inclusion of that cost as allowable costs for ratemaking purposes. Paragraph 9b states that the future revenue will be provided to permit recovery of the previously incurred cost rather than to provide for similar future costs. Since these costs are actual incurred costs and not anticipated future costs, FERC allowed the costs for recovery, and the recovery of costs is reflected in the approved rates. AEPGCo has therefore classified this as a regulated asset.

·   $1.1 million was recorded upon adoption of SFAS 143 in 2003, and relates to the asset retirement obligation related to ash ponds. The characteristics of these costs are similar to other plant assets that were identified as being specifically recoverable in AEPGCo’s current rate tariffs. Paragraph 9a states that amounts can be classified as regulated assets if it is probable that future revenue in an amount equal to the cost will result from inclusion of that cost as allowable costs for ratemaking purposes.

Paragraph 9b also states that the regulator’s intent would clearly be to permit recovery of a previously incurred cost. Since FERC has allowed similar costs, and it is anticipated that these will be recovered in future revenues, AEPGCo has classified this as a regulated asset.

AEPGCo’s regulatory liabilities were measured in accordance with SFAS 71 paragraph 11 and consist of the following items at December 31, 2004:

·   $25.4 million of asset removal costs were reclassified from accumulated depreciation as liabilities in conjunction with the adoption of SFAS 143 in 2003 and reflect the removal costs that were collected through depreciation rates. The FERC approved our depreciation rates including this cost of removal component. This is reported as a liability separately from any asset retirement obligation since there is not a legal requirement to remove the asset. Paragraph 11b of SFAS 71 states that such liabilities should be recorded if a rate is applied that is intended to recover costs that are expected to be incurred in the future with the understanding that those rates may be reduced (representing a return of the funds to the ratepayer) if those costs are not incurred.

·   $46.3 million of Investment Tax Credits are reflected in the rate-making process on a deferral basis for AEPGCo. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment.

·   $12.9 million of SFAS 109 Regulatory Liability. We use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities that will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

In regard to AEPGCo’s achieved rate of return, AEPGCo has an allowed rate of return on common equity of 12.16%, as approved by the FERC. This rate was set in FERC Docket No. ER89-470-000 and No. ER90-26-100, effective December 1, 1989. These proceedings lowered the rate from 13.0% that was stipulated in AEPGCo FERC Rate Schedules No. 1, 2 and 3. The approved return is not applied against rate base like a traditional rate design. This rate is applied to the common equity component used monthly in the calculation to determine billings under the above mentioned rate schedules. Return on common equity is limited in the monthly billings by factors such as the operating ratio, the equity to capitalization ratio, the amount of temporary cash investments and other non-operating items. The 12.16% is being used each month in determining billings to AEPGCo’s customers in accordance with the approved rate design. Over the last three years, the annualized actual rates of return have ranged from 9.5% to 10.5%

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Notes to Financial Statements of Registrant Subsidiaries

General

6.We assume employees of AEP subsidiaries receive stock options from American Electric Power, Inc. We further assume such registrant subsidiaries are applying the guidance in paragraph 14 of FIN 44. If so, tell us why you did not provide all disclosures required by paragraphs 46-48 of SFAS 123. If you agree that such disclosures are necessary, please also provide the disclosures required by paragraph 45 of SFAS 123, as amended by paragraph 2.e of SFAS 148 under “Summary of Significant Accounting Policies” in Note 1. See paragraph 15 of SFAS 123.

RESPONSE:

Stock-based compensation awards granted by AEP include restricted stock units, restricted shares, performance share units, phantom stock units and stock options. Of these, only performance share units, phantom stock units and stock options have been granted to employees of AEP registrant subsidiaries.

AEP’s stock-based compensation expense included in net income in 2004 was $15 million, net of related tax effects, as disclosed in AEP’s footnote 1. Stock-based compensation expense determined under the fair value based method including the effect of stock options was $18 million, net of related tax effects, with approximately 4% related to the registrant subsidiaries and 96% related to AEP and non-registrant subsidiaries, primarily American Electric Power Service Corporation (AEPSC).

No such stock-based compensation amounts were material to any of the registrants and accordingly, no disclosure was made at the individual registrant level. The portion of the $18 million Estimated 2004 Stock-Based Compensation Expense Under Fair Value Based Method disclosed on page A-85 of our Form 10-K related to the registrant subsidiaries is as follows:

AEP Generating Company (AEPGCo)	$	-
AEP Texas Central Company (TCC)		20,000
AEP Texas North Company (TNC)		1,000
Appalachian Power Company (APCo)		55,000
Columbus Southern Power Company (CSPCo)		33,000
Indiana Michigan Power Company (I&M)		385,000
Kentucky Power Company (KPCo)		28,000
Ohio Power Company (OPCo)		58,000
Public Service Company of Oklahoma (PSO)		14,000
Southwestern Electric Power Company (SWEPCo)		25,000
	$	619,000

We will continue to review the distribution of stock-based compensation awards and will provide disclosure by registrant if the amounts become material.

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Note 1. Organization and Summary of Significant Accounting Policies

Property, Plant and Equipment and Equity Investments

7.Please disclose accumulated depreciation associated with your regulated and unregulated assets separately. You may do this parenthetically. If you believe your existing disclosures meet this requirement, please explain. Additionally, please disclose the service life and balance for each material category of unregulated assets. See Rule 5-02.13 of Regulation S-X.

RESPONSE:

Rule 5-02.13 of Regulation S-X concerns the disclosure of the original cost and any related adjustments for tangible and intangible utility plant of a regulated public utility company and is not applicable to non-regulated companies; Rule 5-02.14 of Regulation S-X relates to presentation in the balance sheet or in a note thereto, of accumulated depreciation, depletion and amortization of property, plant and equipment. AEP believes it meets the requirements of both of these rules as noted below.

Nine of AEP’s registrant subsidiaries own regulated electric distribution facilities. The other registrant subsidiary, AEPGCo, only owns and operates generation plants and, as stated earlier in our response to comment 5, sells its output to two of the AEP registrant subsidiaries under FERC regulation. In certain states where state restructuring legislation was adopted (Ohio, Virginia and Texas), generation is no longer under SFAS 71. However, those subsidiaries have not legally separated their generation assets from their regulated distribution/transmission assets. These “unregulated” generation assets are not operated as a separate merchant generation fleet but are coordinated and dispatched with the remaining generation assets owned and operated by the other registrant subsidiaries. The costs and benefits of the generation assets are shared among all of our registrant subsidiaries. As discussed on page 20 of our Form 10-K, APCo, CSPCo, I&M, KPCo and OPCo are parties to an Interconnection Agreement (“Interconnection Agreement”), which has been approved by FERC. It defines how these companies share the costs and benefits associated with their generating assets. PSO, SWEPCo, TCC and TNC are parties to an Operating Agreement (“Operating Agreement”), which has also been approved by FERC. Any of these utilities that has excess capacity must make it available for sale to the other companies. Power generated by or allocated or provided under the Interconnection Agreement or the Operating Agreement to any public utility subsidiary is primarily sold to customers by such public utility subsidiary at rates approved (other than in The Electric Reliability Council of Texas (ERCOT) region of Texas) by the public utility commission in the jurisdiction of sale. In Ohio and Virginia such rates are currently based on statutory formulas. Under both the Interconnection Agreement and Operating Agreement, power that is not needed to serve the native load of our public utility subsidiaries is sold in the wholesale market by AEPSC on behalf and for the benefit of those subsidiaries.

AEP’s System Integration Agreement (“System Integration Agreement”), which has been approved by FERC, provides for the integration and coordination of AEP’s east and west zone operating subsidiaries. This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the Operating Agreement, each of which controls the distribution of costs and benefits within each zone.

All generation owned by the registrant subsidiaries (excluding AEPGCo’s) is governed by the Interconnection Agreement, the Operating Agreement and/or the System Integration Agreement (collectively, the “Power Pool Agreements”), and is included in the AEP Utility Operations Segment. The AEP Utility Operations Segment includes the operations of the ten registrant subsidiaries and two non-registrant utility subsidiaries. The output of the formerly regulated generation plants in Virginia and Ohio is available to fulfill the continuing native load obligations of those respective jurisdictions through the Power Pool Agreements. We have lost virtually no customers in Ohio and Virginia and the respective registrant subsidiaries (APCo, CSPCo and OPCo) continue to have an obligation to serve those customers as a Provider of Last Resort (“POLR”).

Merchant generation (Dow, windfarms and Independent Power Producers - IPPs) is not owned by the registrant subsidiaries. It is owned through non-regulated subsidiaries of AEP. These generation assets are not under the Power Pool Agreements and are not coordinated or dispatched with the generation assets of the registrant subsidiaries. These generation assets are only reflected in the AEP financial statements under Investments - Other Segment and are managed by senior executive personnel including a Senior Vice President of Non-Utility Operations who reports to the CEO.

With respect to property of AEP and registrant subsidiaries, utility assets are principally grouped in the Balance Sheets in separate categories accustomed to a utility presentation of Electric Property, Plant and Equipment: Production, Transmission, Distribution, and Construction Work in Progress. The Production category includes both the currently regulated and formerly regulated generation assets of its operating utilities (such as the Ohio jurisdiction of CSPCo and OPCo), which are based on original cost and managed under one operating segment (also refer to our response to SEC comment 12 below). AEP has determined that a combined presentation of such assets (although some generation assets are “deregulated”) is consistent with how it manages the utility business. Note that for the registrant subsidiaries, there is an additional category, General.

For consolidated AEP, there is also an additional “Other” category of Electric Property, Plant and Equipment presented in the Consolidated Balance Sheets which includes primarily nuclear fuel, coal mining assets, general utility plant (a part of the utility segment), and other non-utility owned assets such as wind farms, Houston Pipeline Company (HPL) (98% interest sold in 2005), DOW Plant, MEMCO (a barging company) and various IPPs.

With respect to Accumulated Depreciation and Amortization, AEP separately presents the balance in the respective Balance Sheets.

The service life of AEP’s utility production assets that are currently deregulated does not differ from the comparable service life of such production assets that continue to be regulated.

Commencing with the 2005 first quarter Form 10-Q, with respect to consolidated AEP, we will disclose the total property, plant, and equipment and associated accumulated depreciation by segment within the Business Segments footnote.

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Note 6. Customer Choice and Industry Restructuring

Texas Restructuring

8.As a result of their failure to sell 15% of their generating capacity at state-mandated auctions, we note that Centerpoint was required to adjust their net true-up regulatory assets. However, you state that due to different facts and circumstances, you have not recorded any provisions to reflect a similar adverse adjustment. Please supplementally explain in detail the specific facts and circumstances that led you to conclude that an adjustment is not required. In doing so, please provide us with some quantification of the adjustment should the PUCT determine that you did not meet the requirement to auction 15% of your generating capacity.

RESPONSE:

Management discloses in Footnote 6 on page A-105 that it believes, with the adjustments it recorded to TCC’s net stranded generation plant costs in the fourth quarter of 2004, it has complied with the portions of the Public Utility Commission of Texas’ (PUCT) to-date orders in other Texas Companies’ true-up proceedings that apply to TCC. On page A-106 of that same footnote, management discloses that TCC recorded no adverse adjustment related to its obligation under the Public Utility Regulatory Act (PURA) to sell at auction capacity products equal to 15% of its installed capacity because, as will be supported in testimony to be filed in its upcoming true-up proceeding, TCC sold at least 15% of its jurisdictionally installed generating capacity in accordance with the provisions of PUC Subst. R. 25.381 and PURA Section 39.153 in 2002 and 2003 when the capacity auction true-up regulatory asset was recorded and because the relevant facts and circumstances surrounding TCC’s annual auction are different than those surrounding CenterPoint’s annual auctions.

The table below shows the calculation of the amount of jurisdictionally installed generating capacity TCC auctioned:

Year	Quantity Offered (1)	Quantity of Entitlements Sold (2)	Installed Generation Capacity (3)	Percent Sold at Auction (2) / (3)
2002	675 MW	675 MW	4496 MW	15.01%
2003	675 MW	550 MW	3001 MW	18.32%

The quantity of installed generating capacity fell from 2002 to 2003 because of TCC’s decision in 2002 to mothball uneconomic gas generation facilities. As a result, the quantity of entitlements that needed to be sold to comply with the applicable provisions of Subst. R. 25.381 in 2003 also fell, even though TCC offered at auction the same number of entitlements in both years.

A change in external conditions led to TCC mothballing gas generating capacity. Electric power is provided competitively within ERCOT as a result of industry restructuring. The advent of customer choice in 2002 changed competitive conditions in Texas.  One result of the competitive market was the building of an abundance of new, highly efficient and low-cost gas generation in ERCOT. TCC’s older and less efficient gas units were uneconomic when compared to nuclear, coal and the new gas generation. With demand in ERCOT being met by these other resources, TCC could not generate adequate market revenues from its gas units, which led TCC to mothball gas generating capacity.

AEP performed an economic evaluation and concluded that all of its gas units were uneconomic. Having made that determination, AEP requested ERCOT in October 2001, and again in September 2002, to determine if any of TCC’s gas units would be operated at the direction of ERCOT, to provide voltage support, stability or management of localized congestion. As a result of the request, ERCOT entered into Reliability Must Run (RMR) contracts for some of the gas units. The gas units that were mothballed are those that were not awarded RMR contracts.

Mothballed capacity was excluded from the determination of installed generation capacity because the capacity was not potentially marketable, according to the statutory definition of installed generation capacity. It was not potentially marketable installed generation capacity under PURA §39.154(d) and PUC Subst. R. 25.381(c)(14) because the mothballed generating units (i) were not connected with the transmission or distribution system; (ii) were not self service facilities; and (iii) were not expected to be connected to the grid and operational within twelve months from the date of the 2003 capacity auctions.

In addition, relevant facts surrounding TCC’s auctions and actions TCC took to comply with the PUCT rule were different. TCC was exempted from offering certain products because it committed to divest certain of its generation capacity pursuant to a business combination proceeding under PURA § 14.001, and, moreover, the actions that it took to reoffer products that were not sold in the auction were specific to TCC and its products. As a result, TCC’s facts and circumstances are not the same as the CenterPoint facts and circumstances.

In response to determining that CenterPoint had not met the requirement to sell 15% of generating capacity, the PUCT averaged the prices received by CenterPoint from its PUCT-authorized capacity auctions with prices obtained by CenterPoint in other multiple auctions it conducted in its operating area of Texas during the same period to calculate the capacity auction true-up adjustment. TCC does not operate in the same area of Texas as CenterPoint and TCC did not conduct other auctions, i.e. TCC only conducted one PUCT-authorized auction each year. As a result, TCC cannot quantify the adjustment that would result from applying the CenterPoint methodology to TCC.

* * *

9.We note that you recognized in 2004 income the debt component of $302 million in carrying costs for the period January 1, 2002 through December 31, 2004 while you will recognize the remaining equity component of $168 million, relating to the same period, in income as collected. Please explain the reason for the disparity in accounting treatment.

RESPONSE:

Paragraph 9 of SFAS 71 requires that a regulatory asset be recorded when the actions of a regulator provides reasonable assurance that an incurred cost that would otherwise be charged to expense will be recovered in future regulated rates. Footnote 5 to paragraph 9 defines an incurred cost as, “a cost arising from cash paid or obligation to pay for an acquired asset or service, a loss from any cause that has been sustained and has been or must be paid for.” Under the definition in footnote 5, an equity return is not an incurred cost. Since equity is not an incurred cost, it cannot be recorded as a regulatory asset. Also, paragraph 15 of SFAS 71 indicates that when a regulator requires the capitalization of the cost of financing construction, an interest and equity cost can be capitalized in lieu of merely capitalizing interest in accordance with SFAS 34, Capitalization of Interest Cost. SFAS 71 provides no other authority for the capitalization or deferral of equity costs. Paragraph 9 of SFAS 92, Regulated Enterprises - Accounting for Phase-In-Plans, limits the capitalization or deferral of equity cost for financial reporting purposes when it states, “If any allowance for earning on shareholders’ investment is capitalized for rate-making purposes other than during construction or as part of a phase-in plan, the amount capitalized for rate-making purposes shall not be capitalized for financial reporting.” The carrying cost to be recovered by TCC on Texas stranded generation costs is not being recorded on assets under construction or in connection with a phase-in plan. As a result of the above, the equity component of the subject carrying cost is not a regulatory asset and is not recognized in income for financial reporting purposes until collected in future regulated rates. Since the debt component of the subject carrying cost is an incurred cost pursuant to footnote 5 of SFAS 71, which is probable of future recovery in regulated rates under the Texas restructuring legislation, it is a regulatory asset, which can be and is recognized in income when accrued.

* * *

Michigan Restructuring

10.You indicate that customer choice commenced in Michigan on January 1, 2002; yet, it appears generation in Michigan continues to be cost-based regulated. Given the passage of restructuring legislation and using guidance in EITF 97-4, please explain in detail why you believe SFAS 71 remains applicable for generation in Michigan. In this regard, please explain to us the specific provisions of the restructuring legislation in Michigan and whether any further actions, other than unbundling, will occur. Further, help us understand how each component of unbundled rates will be determined on an on-going basis and why I&M’s rates for generation are considered to be cost-based determined.

RESPONSE:

Indiana Michigan Power Company (I&M) continues to be subject to cost-based regulation in Michigan. Although the Michigan restructuring legislation provided customers the opportunity for customer choice of electric supply, cost-based regulation continues for those incumbent utilities whose customers opt not to switch electric supply.

The Michigan Electric Industry Restructuring Legislation, commonly referred to as 2000 Public Act (PA) 141 (the Michigan Restructuring Act), is unlike other state electric restructuring laws in that it did not deregulate the generation of electricity. The Michigan Restructuring Act did not repeal or alter the Michigan Public Service Commission’s (MPSC) rate regulation authority granted under existing statutes. Instead, the Michigan Restructuring Act established only a process for allowing customers the opportunity to choose a different electricity supplier than the incumbent electric utility while still remaining as a customer of the incumbent utility for distribution service. Section 10 of the Michigan Restructuring Act provided that, among other things:

“Sec. 10.

(1) Sections 10 through 10bb shall be known and may be cited as the “customer choice and electricity reliability act.”

(2) The purpose of sections 10a through 10bb is to do all of the following:

(a)   To ensure that all retail customers in this state of electric power have a choice of electric suppliers.

(b)   To allow and encourage the Michigan Public Service Commission to foster competition in this state in the provision of electric supply and maintain cost-based regulation of electric supply for customers who continue to choose supply from incumbent electric utilities.(emphasis added)

(c)   To encourage the development and construction of merchant plants which will diversify the ownership of electric generation in this state.

(d)   To ensure that all persons in this state are afforded safe, reliable electric power at a reasonable rate.

(e)   To improve the opportunities for economic development in the state and to promote financially healthy and competitive utilities in the state.”

Pursuant to the Michigan Restructuring Act and with MPSC approval, I&M unbundled its cost-based Michigan retail rates and implemented terms and conditions of service effective January 1, 2002. Unbundled MPSC-approved rates allow retail customers in Michigan the opportunity to compare the cost of competitive generation service from an alternative electric supplier (AES) and to switch if so desired, or to remain served by the same regulated utility under the same, albeit now unbundled, cost-based rates. No further actions are required or anticipated by I&M to comply with the unbundling and customer choice provisions of the Michigan Restructuring Act. No AESs have registered with I&M to compete for its generation load and no customers have chosen to receive service from an AES. As a result, all of I&M’s Michigan customers are under regulated cost-based rates and will continue unless they switch suppliers.

I&M’s base rates for electric service have not changed since the unbundling occurred on January 1, 2002, although the Power Supply Cost Recovery (PSCR) adjustment factors associated with the unbundled generation service have been modified as allowed by law and with MPSC approval to track I&M’s incremental fuel and purchased power costs. Moreover, under the Michigan Restructuring Act and other rate regulation legislation, the MPSC will continue to establish and regulate I&M’s unbundled services and rates, including generation, based upon I&M’s costs of providing those services. Since I&M’s cost-based rates are currently below market, it is not anticipated that customers will switch suppliers and, therefore, customers are expected to continue paying the cost-based regulated rates.

In making the decision to continue to apply SFAS 71 following the Michigan Restructuring Act, I&M specifically applied EITF 97-4, which states:

“On Issue 1, the Task Force reached a consensus that when deregulatory legislation is passed or when a rate order (whichever is necessary to effect the change in the jurisdiction) that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the responsible portion of its business whose pricing is being deregulated is issued, the enterprise should stop applying Statement 71 to that separable portion of its business…”

I&M evaluated whether the Michigan Restructuring Act deregulated its supply business, and we concluded that it did not and that I&M’s rates, including generation, continued to be cost-based regulated rates under the regulatory authority of the MPSC, exercised pursuant to the previously existing legislation. Under the Michigan Restructuring Act, I&M continues to charge cost-based regulated rates to all of its retail customers and if it needs to change its rates, it is required to file a traditional cost-based rate filing with the MPSC.

Although I&M does not anticipate losing its electric supply customers due to its low cost-based rates, it continues to monitor the application of SFAS 71 to its Michigan jurisdiction.

* * *

Note 10. Dispositions, Impairments, Assets Held for Sale and Assets Held and Used

11.We note that the generation assets and liabilities of TCC are classified as held for sale on the balance sheet. In this regard, please explain why the results of operations of the generation business are not reported in discontinued operations in the statement of income. See paragraphs 41-44 of SFAS 144.

RESPONSE:

TCC is in the process of selling its generation assets in Texas as a part of its plan pursuant to the Texas Restructuring Legislation to support and recover its stranded cost.

TCC’s analysis (discussed below) of the requirements of SFAS 144 and related accounting principles generally accepted in the United States of America (GAAP) indicates that the generating stations are not a component of an entity. Accordingly, the generation assets being sold do not qualify for discontinued operations.

The TCC plants do not meet the criteria in SFAS 144 to classify the results of operations of the TCC plant assets held for sale as discontinued operations in the statements of income.

Component of an Entity

Paragraph 41 of SFAS 144 states, “For purposes of this Statement, a component of an entity comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity. A component of an entity may be a reportable segment or an operating segment (as those terms are defined in paragraph 10 of Statement 131), a reporting unit (as that term is defined in Statement 142), a subsidiary, or an asset group (as that term is defined in paragraph 4).”

The TCC plants do not meet the component of an entity criteria in SFAS 144 paragraph 41. Even though the TCC plants are a disposal group as defined in paragraph 4 of SFAS 144, they do not have cash flows that can be clearly distinguished, operationally, and for financial reporting purposes because they are not operated individually, but rather as part of AEP’s Power Pool which includes all of the generation facilities owned by the registrant subsidiaries. As discussed in the response to Comment 7, the power pooling process controls each plant and the plants are dispatched when market conditions and management determines it is beneficial. TCC sells energy in the ERCOT market, some of which is generated, and some of which is purchased. Due to the nature of electrical energy, it is impossible to match cash inflows from sales to cash outflows from either purchased or generated power.

The SEC comment suggests that the TCC generation assets constitute a business. EITF 98-3 Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business defines the criteria of a business as having inputs, processes and outputs. The plants do have inputs and processes, but as stand alone plants they do not possess the ability to obtain access to the customers that purchase the outputs, thus making it impossible to identify specific cash inflows. As such the plants are not considered a business, nor are the plants operated by the company as a separate business. As noted above, it is not possible to identify cash flows with a specific plant. The plants do not have customers that purchase directly from the plants.

* * *

Note 12. Business Segments

12.Based on your disclosure that “operations are managed on an integrated basis, we assume you consider your regulated and unregulated businesses to be one operating segment as defined by paragraph 10 of SFAS 131. However, we have noted that many utilities separate their business into regulated and unregulated segments. Please address each of the sub-paragraphs of paragraph 10 of SFAS 131 in explaining the business reason(s) for your segment treatment. In doing so, for each registrant with an unregulated generation business, supplementally provide us with a detailed description of the reports reviewed by the chief operating decision maker in deciding how resources will be allocated to the segment and to assess its performance. Please ensure you fully explain to us how such reports are used. Finally, cite examples of other utilities that include regulated and unregulated utility operations within one segment.

RESPONSE:

Each of AEP’s registrant subsidiaries has only one operating segment, a vertically integrated electricity generation, transmission, and distribution business except AEPGCo, an electricity generation business (referred to herein as “registrant subsidiary operating segment”). Generation is not an operating segment for the registrant subsidiaries and there is no commercial distinction between the operations of the formerly regulated generation assets and the generation assets of the registrant subsidiaries still under SFAS 71 because all the generation assets of the registrant subsidiaries are coordinated under the Power Pool Agreements as discussed in detail in our response to comment 7. We are compliant with SFAS 131 because our segments are consistent with the “management approach” of paragraph 4, which the Statement notes should be, “…based on the way that management organizes the segments within the enterprise for making operating decisions and assessing performance.”

As discussed in our response to comment 7, within a registrant subsidiary, there are not regulated and unregulated businesses. The generation assets are integral to each registrant utility. Two of the registrant subsidiaries, OPCo and CSPCo, have generation assets that are no longer considered regulated under SFAS 71. APCo has generation assets that are both regulated (in the state of West Virginia) and unregulated (in the state of Virginia). As noted in our response to comment 7, the generation plants that are no longer accounted for as “regulated” under SFAS 71 are managed and operated no differently than the generation that continues to be accounted for as regulated assets under SFAS 71. The generation assets that are not considered regulated under SFAS 71 still provide the native load capacity to customers because we have lost virtually no customers in Ohio and Virginia and the respective registrant subsidiaries - APCo, CSPCo, and OPCo still have an obligation to serve those customers under a POLR obligation.

In these states, we have not legally separated the formerly regulated generation, although it became deregulated through state restructuring legislation. The respective registrant subsidiaries still own those generation assets (except for certain Texas generation assets which have been sold) and the costs and benefits of those generation assets are shared among our registrant subsidiaries pursuant to the Power Pool Agreements. Commercial operations for the registrant subsidiaries are an integral part of AEPSC’s activity, performed for the benefit of the power pool participants. Those utility plants, including the portion applicable to deregulated jurisdictions, are centrally dispatched in accordance with the Power Pool Agreements and their output is available to satisfy the native load obligations of customers. The registrant subsidiaries’ operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on business processes, cost structures and operating results. Additionally, paragraph 4 of SFAS 131 states that, “…the segments are evident from the structure of the enterprise’s internal organization…” Each AEP registrant subsidiary is reporting for external purposes its operations as one operating segment because that is how it is managed, internally reported and structured for making operating decisions including the allocation of resources and the measurement of operations.

Chief Operating Decision Maker of the Registrant Subsidiaries

The chief operating decision maker of AEP’s respective registrant utilities is the Executive Council (EC) which consists of AEP’s CEO and certain direct reports including a President-AEP Utilities, an Executive Vice-President - Plant Operations, a Senior Vice President of Commercial Operations, the Executive Vice President-CFO, the Senior Vice President General Counsel & Secretary, and the Senior Vice President Shared Services. The EC also includes other members reporting to the President - AEP Utilities: the Senior Vice President-Regulatory, and Executive Vice Presidents for the East and West operating utilities.

The EC, as the chief operating decision maker, is compliant with SFAS 131, paragraph 12, which states:

“The term chief operating decision maker identifies a function, not necessarily a manager with a specific title. That function is to allocate resources to and assess the performance of the segments of an enterprise. Often the chief operating decision maker of an enterprise is its chief executive officer or chief operating officer, but it may be a group consisting of, for example, the enterprise’s president, executive vice presidents, and others.”

The Plant Operations and Commercial Operations functions supervise the operation and maintenance of the generation plants and their commercial optimization, respectively. The President-AEP Utilities has primary responsibility over the financial results of the operating companies and is assisted by a structure including Operating Company Presidents, with responsibility for decisions on operations and maintenance of the distribution system in their region and a wide range of customer and regulatory relationships. The Operating Company Presidents have direct authority over rate activities including requests for rate changes.

The Operating Company Presidents have authority for their respective Companies as demonstrated by the AEP TCC President leading the project to recover stranded generation costs in Texas and the CSPCo and OPCo President directing the effort to obtain approval from the Public Utilities Commission of Ohio (PUCO) to recover costs related to pollution control assets and request cost recovery of a new generating plant using new technology.

The Operating Company Presidents are organized into an East and West grouping which reports to two respective Executive Vice Presidents, who report to the President-AEP Utilities who also has responsibility for transmission and centralized planning and coordination of distribution and customer operations. Note, however, that internal and external reports are not prepared in this East / West view.

Discussion of Current Monthly Management Reporting

The monthly reporting of financial information prepared for EC management is coordinated by the Financial Reporting Group together with the Corporate Planning and Budgeting Group. Those reports include color coding applicable to earnings for AEP Utility Operations Segment (yellow); Investments Segments (green); and All Other - Parent (salmon). Investments and All Other only apply to consolidated AEP, not to the registrant subsidiaries. The Investment group includes separate identification of the various investments, including gas, UK, as well as the other items comprising Investment - Other. The AEP Utility Operations Segment includes the ten registrant subsidiary operating segments. The financial reports for the registrant subsidiaries and the AEP Utility Operations Segment do not distinguish between generation, transmission and distribution in measuring results of operations, nor do they distinguish between regulated or unregulated generation. As noted in our responses to comments 7 and 11, it is not possible to identify cash inflows with a specific plant. There are no revenues to external customers at the plant level.

The following reports are prepared and distributed to EC management for the review of the results of each registrant subsidiary and for consolidated AEP in the segment format noted above:

·   Monthly Earnings Packages

Prepared for each registrant subsidiary, as well as the AEP Utility Operations Segment, Investments Segments, and All Other. The reports are distributed to EC management and are reviewed at monthly meetings, focusing on the current month and year to date results compared to plan, and quarter and year to date actuals compared to the prior year (for earnings press releases). These reports also include analysis of gross margin, operations and maintenance expense, and capital spending levels.

·   Monthly Financial Statements

Prepared for each registrant subsidiary, as well as the AEP Utility Operations Segment, Investments Segments, and All Other, and distributed to and reviewed by EC management in a format similar to those prepared for SEC filings. The financial statement reporting packages include income statements, balance sheets, and cash flows compared to current year plan and prior year results.

·   Budgets, Long-Term Financial Plans

The Budgets and Long-Term Financial Plans are prepared for each registrant subsidiary, as well as the AEP Utility Operations Segment, Investments Segments, and All Other. These plans are compiled by input from various supporting groups within the organization (Finance, Tax, HR, Load and Revenue Forecasting, etc.), including registrant subsidiary employees. These plans are reviewed and approved by the EC management and are used as input into the monthly earnings packages and monthly financial statements by each registrant subsidiary (included in the AEP Utility Operations Segment), Investments Segments, and All Other.

Also, a quarterly earnings book is prepared in a similar format to review ongoing and GAAP earnings and to prepare for the quarterly press release. Finally, quarterly reports are prepared in a similar format for presentations made by senior AEP management.

These reports are regularly used by EC management to plan and operate each registrant subsidiary and the AEP Utility Operations Segment, as a whole, and to make the key operating decisions.

The EC’s use of the information for each registrant subsidiary supports the conclusion that each registrant subsidiary operates with only one reporting segment. In addition, the EC’s utilization of reports with segment information directly supports the current presentation of AEP’s segments under SFAS 131.

SFAS 131 Requirements

Paragraph 10 of SFAS 31 defines an operating segment as:

An operating segment is a component of an enterprise:

a.   That engages in business activities from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other components of the same enterprise),

The notes to the financial statements for the registrant subsidiaries indicates that each registrant subsidiary has only one reportable segment. Each of the registrant subsidiaries earn revenues primarily from generation, transmission, and distribution services and incur related expenses.

b.   Whose operating results are regularly reviewed by the enterprise’s chief operating decision maker to make decisions about resources to be allocated to the segment and assess its performance,

The operating results of each registrant subsidiary are reviewed monthly. The financial reports that are reviewed for each registrant subsidiary are the financial statements for the registrant subsidiary as a whole. There is no breakdown of generation, transmission or distribution (see Discussion of Current Monthly Management Reporting). AEP’s chief operating decision maker (EC) reviews the registrant subsidiary financial information to make operating decisions and allocate resources to and within the registrant subsidiary and the AEP Utility Operations Segment as a whole.

And c., for which discrete financial information is available.

Each registrant subsidiary has discrete financial statements which are reviewed by the EC. The AEP Utility Operations Segment has discrete financial information (see Discussion of Current Monthly Management Reporting) which is reviewed by EC management and reported externally to the Commission, and in a similar format for various stakeholder presentations.

Each registrant subsidiary is subject to the significant effect of regulatory oversight performed by state commissions in the exercise of their authority over cost-based rates, the oversight of the FERC over our transmission rates, and the significance of the FERC-approved Power Pool Agreements which define the way costs and benefits of the generation plants are shared among our registrant subsidiaries, including generation plants in Virginia, Texas and Ohio. As mentioned earlier, all of the generation owned by the registrant subsidiaries is available to satisfy the retail load of Ohio and Virginia, both of which deregulated their generation. The financial results of the registrant subsidiaries is aggregated and included in the AEP Utility Operations Segment.

With respect to state commission regulatory oversight, the registrant subsidiaries, with the exception of AEPGCo, which has no distribution assets, continue to maintain fully regulated distribution service in states with deregulated generation, including Ohio, Texas and Virginia. Further, although the Ohio generation (applicable to OPCo and CSPCo) is deregulated, it is serving POLR obligations in Ohio to retail customers through 2008, in accordance with various transition agreements approved by the PUCO. TCC is in the process of selling its Texas generation assets, as described in its Form 10-K. In Virginia, although state restructuring legislation deregulated generation, APCo’s generation rates are below the market, and virtually no customers have switched providers.

With respect to FERC regulatory oversight, effective October 2004 AEP's East utility companies became members of PJM, as mandated by FERC. FERC also approves AEP’s transmission tariff (OATT). The generation of AEP is dispatched centrally and the costs are shared in accordance with the Power Pool Agreements. These Power Pool Agreements have continued to operate in a historical manner regardless of state deregulation.

Concluding Comments

We only have access to publicly available information and do not have access to the information provided to the chief operating decision maker of other companies. Thus, we do not think it is appropriate to comment on other companies’ disclosures related to segments.

* * *

Note 14. Income Taxes

13.Please explain your basis under paragraph 40 of SFAS 109 for allocating the tax loss of the parent company to its subsidiaries with taxable income. In this regard, please tell us the amount of the loss allocated to each subsidiary for each period presented and the allocation method used. Finally, your disclosure suggests but for allocation of the parent company’s tax loss, your method “approximates” the separate return method. Tell us why it only “approximates” rather than reflects the method.

RESPONSE:

Paragraph 40 of SFAS 109 requires that the consolidated amount of current and deferred tax expense for a group that files a consolidated tax return shall be allocated among the members of the group when those members issue separate financial statements. SFAS 109 does not require a single allocation method. The method adopted, however, must be systematic, rational and consistent with the broad principles established by the statement. A method that allocates current and deferred taxes to members of the group by applying SFAS 109 to each member as if it were a separate taxpayer meets the criteria.

AEP and its subsidiaries join in the filing of a consolidated federal income tax return. AEP bases its allocation of consolidated current and deferred tax expense on the basis of each subsidiary’s separate company taxable income. Certain items like separate company charitable contribution deductions, capital losses and tax credits, which may be limited in a separate return computation for a year, but are allowed in consolidation, are reflected in the separate company taxable income when allocating the consolidated current and deferred tax expense of the group. After the separate company computation, the tax loss benefit of the parent is then allocated to each subsidiary with taxable income.

The basis for allocating the tax loss of the parent company is consistent with the Commission rules under The Public Utility Holding Company Act of 1935 and has been approved by the U.S. Treasury Department. The Commission has approved the allocation method AEP uses, and AEP considers the method to be systematic, rational and consistently applied for decades. In addition, the AEP method does not fall within any of the examples provided in paragraph 40 that are considered inconsistent with the principles established by SFAS 109. As such, the methodology complies with the requirements of paragraph 40 of SFAS 109, particularly since the statement does not specify a single allocation method.

Losses incurred by the parent result from its corporate governance and financing activities as a public utility holding company. The tax loss benefit of the parent company allocated to the subsidiaries for each period is $20,845,000, $30,373,000 and $6,574,000 for the years 2004, 2003 and 2002, respectively. A schedule showing the parent company tax loss benefit allocation to the respective subsidiaries is attached hereto as Exhibit A.

Finally, the AEP disclosure states that our method “approximates” the separate return method. As mentioned previously, there are certain deductions that in a pure federal income tax separate return context may be limited when computing the separate company’s taxable income, but participation in the consolidated return provides for current recognition of the deduction or credit. As such, the allocation does reflect a separate company method with consolidated adjustments, therefore we chose to use the term “approximates.” Commencing with the 2005 Form 10-K, we will use the term “reflects.”

* * *

AEP acknowledges that: it is responsible for the adequacy and accuracy of the disclosure in the filing; staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and AEP may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Please do not hesitate to call Thomas Berkemeyer (614-716-1648) or William E. Johnson (614-716-1624) with any questions you may have regarding this filing or if you wish to discuss the above responses.

Very truly yours,

/s/ Thomas G. Berkemeyer

Thomas G. Berkemeyer

c:Jim Allegretto, Senior Assistant Chief Accountant

Exhibit A

AEP SYSTEM
SEC TAX ALLOCATION
	Allocation of Parent Company Tax Loss Benefit
COMPANY NAME	For the Year Ended
	12/31/04			12/31/03			12/31/02
AEP C&I Company, LLC	$	0		$	0		$	(72,000	)
AEP Coal Marketing , LLC		(425,000	)		0			0
AEP Communications		0			(24,000	)		0
AEP Credit, Inc		(175,000	)		(30,000	)		(29,000	)
AEP Delaware Invest. Co. II		0			0			(10,000	)
AEP Delaware Invest. Co. III		0			(450,000	)		(167,000	)
AEP Elmwood, LLC		(100,000	)		(50,000	)		0
AEP Energy Services		0			0			(341,000	)
AEP Energy Srvcs Gas Holding		0			0			(68,000	)
AEP Energy Srvcs Ventures III		(100,000	)		(150,000	)		(23,000	)
AEP Gas Marketing LP		(400,000	)		(150,000	)		(19,000	)
AEP Generating		(150,000	)		(275,000	)		(47,000	)
AEP Ohio Retail Energy, LLC		0			(15,000	)		0
AEP Pro Serv		0			0			(44,000	)
AEP Service Corp		0			(450,000	)		0
AEP Texas Central Co.		(4,900,000	)		(3,800,000	)		(460,000	)
AEP Texas North Co.		(675,000	)		(1,300,000	)		(87,000	)
AEP Utilities		(150,000	)		(206,000	)		(17,000	)
Appalachian Power Co.		(1,200,000	)		(4,100,000	)		(759,000	)
Blackhawk Coal		(15,000	)		(12,000	)		0
Cedar Coal		(10,000	)		(50,000	)		0
Colomet, Inc		(35,000	)		0			0
Columbus Southern Power Co.		(2,150,000	)		(4,200,000	)		(780,000	)
Conesville Coal		0			(24,000	)		0
CSW Development - 1, Inc.		(200,000	)		(12,000	)		0
CSW Eastex LP II, Inc.		0			(700,000	)		0
CSW Fort Lupton, Inc.		(300,000	)		0			0
CSW International T		(150,000	)		0			0
CSW Int'l Two, Inc. - SEEBOARD		0			0			(219,000	)
CSW Mulberry, Inc.		(660,000	)		0			0
CSW Orange, Inc.		(1,050,000	)		0			0
CSW Services International, Inc.		0			(12,000	)		0
CSW Sweeny LP I, Inc.		(100,000	)		(24,000	)		0
CSW Sweeny LP II, Inc.		0			(150,000	)		(21,000	)
Dolet Hills Lignite Co., LLC		0			(75,000	)		0
Houston Pipeline Company		(625,000	)		(75,000	)		(376,000	)
Indiana Michigan Power Co.		(2,250,000	)		(2,900,000	)		(1,396,000	)
Kentucky Power Co.		(100,000	)		0			(106,000	)
Kingsport Power Co.		0			(75,000	)		(14,000	)
Mutual Energy, LLC		0			(340,000	)		0
Ohio Power Co.		(4,000,000	)		(6,900,000	)		(1,141,000	)
Public Service Co. of Oklahoma Co.		0			(1,600,000	)		0
Rep Holdco, LLC		0			0			(11,000	)
Southern Appal		0			(24,000	)		0
Southwestern Electric Power Co.		(850,000	)		(2,000,000	)		(342,000	)
Wheeling Power Co.		(75,000	)		(200,000	)		(25,000	)
Total System	$	(20,845,000	)	$	(30,373,000	)	$	(6,574,000	)