0; American Electric Power 1 Riverside Plaza
Columbus, OH 43215-2373
Joseph M. Buonaiuto
&# 160; Senior Vice President
&# 160; & Chief Accounting Officer
&# 160; 614-716-2821
&# 160; fax: 614-716-1187
&# 160; jmbuonaiuto@aep.com
Securities and Exchange Commission
100 F Street NE
Washington, DC 20549
May 8, 2007
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, 2006
Filed February 28, 2007
Responses to the comment letter dated April 24, 2007 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 Fiscal Year Ended December 31, 2006
| 1. | Our records show the File Number for AEP Texas Central Company is 1-12973, rather than file number 0-346 that appears on the cover page of your reports. Likewise, our reports show the File Number for Public Service Company of Oklahoma is 1-12945 rather than file number 0-343 that appears on the cover page of your reports. Please make the appropriate revisions. |
Response:
We believe the file numbers of 0-346 for AEP Texas Central Company (“ATC”) and 0-343 for Public Service Company of Oklahoma (“PSO” and, with ATC, “Filers”) as reflected on the Annual Report on Form 10-K (the “Form 10-K”) are accurate. The Commission’s EDGAR database indicates that the foregoing file numbers were used for these registrants from 1995 through early 1997.
In 1997, both Filers formed wholly-owned trusts that issued trust-preferred securities in registered offerings. These securities were initially registered on the NYSE. Accordingly, at the time of issuance, the Filers each filed a Form 8-A with the Commission, and new file numbers were issued. In each of these transactions, the trust was identified as the issuer and ATC and PSO were identified as guarantors. These securities are no longer outstanding.
We did not believe that the Filers adopted the new SEC File Numbers as a result of these filings. We believe the original SEC File Number assigned to ATC (0-346) and PSO (0-343) are the correct file numbers. Tom Berkemeyer in our Legal Department spoke with Velma Smith in the SEC’s EDGAR Support Group to discuss this issue. Once the SEC EDGAR Support Group advises us of the appropriate file numbers, PSO and ATC will use those file numbers in future filings.
Exhibit 13
American Electric Power Company, Inc. and Subsidiary Companies
Management’s Financial Discussion and Analysis of Results of Operations, page A-2
Results of Operations, page A-6
| 2. | We note your presentation of earnings per share by segment, which represent non-GAAP financial measures. Please disclose how these measures are used by management and in what way they provide meaningful information to investors. Additionally, please identify these per share measures as non-GAAP measures of performance and disclose that the non-GAAP measures should not be considered as an alternative to earnings per share determined in accordance with GAAP as an indicator of operating performance. Refer to Item 10(e)(1)(i) of Regulation S-K and Question 11 of our “Frequently Asked Questions Regarding the Use of Non-GAAP Measures,” available on our website at www.sec.gov. |
Response:
In future filings, AEP will remove the earnings per share by segment information.
Utility Operation, page A-7
| 3. | In segment footnote (a) on page A-111 you disclose that the Plaquemine Cogeneration Facility is in the “All Other” segment. Please explain to us why expenses at this facility contributed to the increase in other operation and maintenance expenses of the “Utility Operations” segment as disclosed on page A-10. Please also explain to us why the operation of the facility affected revenues, fuel and other consumables used for electric generation and other operation and maintenance expenses of OPCo with no effect on income as disclosed on page I-9. |
Response:
AEP’s interest in the Plaquemine Facility (“Facility”) was sold in the fourth quarter of 2006. The interest in the Facility was recorded on the books of a nonutility subsidiary of AEP whose operations were included in “All Other” in the Business Segments Footnote. The interest in the Facility was recorded as an owned asset under a lease financing transaction with Juniper Capital L.P. (reference AEP’s 2003 Form 10-K, page A-109). The Facility was subleased to Dow Chemical Company (“Dow”) which used a portion of the energy produced by the Facility and sold the excess energy to AEP Power Marketing, Inc. (“AEPM”) pursuant to a purchase power and sale agreement (“PPA”).
Before the Facility commenced operations, AEPM assigned its rights under the PPA to Ohio Power Company (“OPCo”), one of AEP’s utility subsidiaries. AEPM did not have a trading organization in place to support sales of power from the Facility, and under the Code of Conduct of the Federal Energy Regulatory Commission (“FERC”), AEPM could not use the existing trading organization at American Electric Power Service Corporation (“AEPSC”), which acts as agent for OPCo for power sales. OPCo’s retail generation rates had become deregulated in September 2000 and it had existing authorization from the FERC to sell wholesale power at market-based rates. The most efficient way to perform under this PPA was to assign it from AEPM to OPCo, thereby avoiding the necessity to form and maintain a separate trading organization. However, in order to mitigate any risk of potential losses related to this contract at a public utility company, OPCo entered into an indemnification agreement for this contract with the parent of AEPM (AEP Resources, Inc. or “AEPR”). When market revenues were less than the related incurred costs, AEPR paid OPCo an indemnity adjustment. The indemnity agreement between AEPR and OPCo effectively held OPCo harmless from market exposure related to its PPA with Dow.
The PPA required OPCo to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. The Facility was a major source of steam supply for Dow which operated the Facility at certain minimum levels. OPCo was obligated to purchase the energy generated at those minimum operating levels. The PPA required OPCo to reimburse Dow for the operation and maintenance costs of the Facility, including fuel. The indemnity adjustment was required within each respective quarter and year for the Facility’s operations from March 2004 through December 2006.
Although both OPCo and AEP’s “Utility Operations” segment had no net income impact from the transactions related to the Facility, it did have fluctuations in related expenses and revenues. The indemnification payment to OPCo from AEPR effectively transferred any risk of loss associated with the Facility to AEPR, which is reflected in the “All Other” Business Segments footnote consistent with the actual economics of the respective Facility transactions.
Consolidated Statements of Income, page A-45
| 4. | Please present the subtotal “Income before extraordinary items and cumulative effects of changes in accounting principles” as required by Item 5-03(b)(16) of Regulation S-X. |
Response:
In future filings, AEP and its registrant subsidiaries will include the subtotal “Income before extraordinary items and cumulative effects of changes in accounting principles”, when applicable.
Note 1. Organization and Summary of Significant Accounting Policies, page A-51
General
| 5. | Please tell us and disclose how you account for sales and purchases of power to and from regional transmission organizations. Specifically address whether you account for these transactions on a gross or net basis. |
Response:
Most of the power produced at the generation plants of our East operating companies (Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company, collectively, the “AEP East Companies”) is sold to PJM, the regional transmission organization (“RTO”) operating in our service territory, and we purchase power back from the same RTO to supply power to our load. These power sales and purchases are reported on a net basis in Operating Revenues in the respective registrants’ financial statements. Other RTOs in which the Company operates do not function in the same manner as PJM. They function as balancing organizations and not as an exchange.
For the remaining power transactions with RTOs, we account for the following types of energy marketing and risk management activities as follows:
| · | On page A-56 of the 2006 Form 10-K, in the third sentence of the second paragraph under Energy Marketing and Risk Management Activities states: "We include the unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM in Revenues on our Consolidated Statements of Income on a net basis". |
| · | Certain physical energy purchases from RTOs that are identified as non-trading (accrual accounting treatment) are accounted for on a gross basis in Purchased Energy for Resale in the AEP Consolidated Statements of Income, and Purchased Electricity for Resale in the subsidiaries' Statements of Income. |
In future filings, AEP and its registrant subsidiaries will expand our disclosure related to sales and purchases to and from RTOs.
Property, Plant and Equipment and Equity Investments, page A-53
| 6. | With respect to your nonregulated operations, please explain to us why you charge retirements from plant accounts, net of salvage, to accumulated depreciation rather than recording a gain or loss. |
Response:
The AEP Utility Operations segment’s generation fleet provides power to its cost based regulated utilities and is managed as an integrated pool. In Ohio and Virginia (until recently), generating plants are considered nonregulated. However, operationally they were retained in AEP’s power pool and used to supply power to the east utility operating companies. In addition, several of the generating plants are jointly owned and are considered both “regulated” and “nonregulated” (see discussion below). Because the operational nature of the nonregulated plants did not change, AEP did not change its depreciation policies related to the plants that are considered “nonregulated”. Accordingly, these generation assets continued to be included in the assets of the Utility Operations segment.
At certain generating plants, the individual generating units are owned by utilities whose generation rates are both regulated and nonregulated. For example, Amos generating Unit 3 is owned 2/3 by Ohio Power (nonregulated) and 1/3 by Appalachian Power (regulated in West Virginia and nonregulated in Virginia). At Sporn Generating Plant, generating Units 1 and 3 are owned by Appalachian Power (regulated in West Virginia and nonregulated in Virginia) and generating Units 2, 4 and 5 are owned by Ohio Power Company (nonregulated).
Retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for nonregulated operations because AEP has continued accounting for its nonregulated operations using the group composite method of depreciation. AEP believes the group composite method of depreciation complies with both Generally Accepted Accounting Principles and SEC Staff Accounting Bulletin No. 5B. Accounting Research Bulletin 43 allows the application of systematic and rational methods of depreciation. SAB 5B permits gains and losses to be charged or credited to accumulated depreciation.
The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in the original cost, less salvage, being charged to accumulated depreciation. The depreciation rates that are established for the generating plants take into account the past history of interim capital replacements and the amount of salvage received. These rates and the related lives are subject to periodic review.
AEP records gains or losses for our nonregulated generation assets for retirements from the plant accounts if the retirement is not considered an interim routine replacement. For example, as disclosed on page A-99 in our 2006 Form 10-K, we recorded a pre-tax loss in 2005 totaling $39 million for the retirement of Columbus Southern Power Company’s Conesville Units 1 and 2.
To date, we have re-applied SFAS 71 for two states which had been deregulated, Arkansas and West Virginia. The continued application of the composite method of depreciation during the interim deregulated period was critical in our use of the per books balance of accumulated depreciation as the appropriate amount for inclusion in rate base. The Virginia legislature passed a law on April 4, 2007 re-regulating generation.
AEP believes the application of the group composite method of depreciation continues to be appropriate for its regulated and nonregulated generation plant. The group composite method enables AEP to operate, account and report for the operations of its generating fleet in a consistent manner for both regulated and nonregulated generating plants.
AEP records gains or losses in the respective income statements for any retirements in its MEMCO and Generation and Marketing segments.
In future filings, AEP and its registrant subsidiaries will clarify our policy for recording gains and losses for retirements.
Inventory, page A-54
| 7. | If material please disclose the excess of replacement or current cost over stated LIFO value of PSO and TNC inventories. See Rule 5-02(6)(c) of Regulation S-X. |
Response:
The excess of replacement or current cost over stated LIFO value for PSO and TNC inventories as of December 31, 2006, was immaterial. The LIFO “reserves” were $3.6 million and negative $.3 million for PSO and TNC, respectively.
PSO has an active fuel clause which requires it to recover fuel cost using the LIFO method, and, as a result, PSO’s LIFO reserves have no impact on earnings. The amount for TNC was de minimis.
In the future, if material, PSO and TNC will make the appropriate disclosures.
Emission Allowances, page A-58
| 8. | We note that you record the net margin on the sales of emission allowances in Utility Operations Revenues “because of its integral nature to the production process of energy and [your] revenue optimization strategy for [your] utility operations.” Please explain to us in greater detail why your accounting treatment is appropriate. Specifically address how the sale of emission allowances relates to your ongoing major or central operations, as contemplated in paragraphs 78-79 of FASB Concepts Statement 6. Finally, please explain to us in greater detail your revenue optimization strategy and tell us why it impacted the classification of gains or losses on the sale of emission allowances. |
Response:
Generation of electricity for sale to retail and wholesale customers is classified under AEP’s Utility Operations segment for reporting purposes (see Footnote 11 of our 2006 Form 10-K on page A-108). The Generation group at AEP is responsible for making economic generation dispatch decisions. We dispatch the power produced at our generating units on a least cost basis. These decisions are made considering optimal revenue generating strategies.
AEP follows the inventory model for recording allowances. Each of the registrant subsidiaries’ inventory consists of allowances granted and purchased. Operating expenses are charged when allowances are consumed in generating electricity. The management of emission allowances is an integral factor in the decision to generate or to purchase power. When determining whether to run certain power plants, the Generation group considers the market prices of consumables such as fuel and emission allowances, as part of an overall revenue optimization strategy. In particular, market prices of consumables are considered when determining the greatest revenue potential for the utility (i.e., the utility can run the marginal generating unit to produce power and consume the allowances, or it can decide not to run the facility and sell the emission allowances that would have been consumed into the market at a net profit).
AEP is in the midst of a program to retrofit several generating facilities with environmental equipment, which will allow the generating units to run using fewer emission allowances. Therefore, as the new environmental equipment is brought on line, the number of emission allowances needed for consumption during the power production process will significantly decrease, resulting in additional revenue generating opportunities to be considered in AEP’s revenue optimization strategies.
Considering the revenue optimization strategy as described above, and its impact on AEP’s ongoing central generation operations, it is our accounting policy to record activity related to the sale of emission allowances as Utility Operations Revenue in accordance with the guidance contained within FASB Concept Statement 6, paragraphs 78 and 79.
Note 4. Rate Matters, page A-67
SECA Revenue Subject to Refund, page A-81
| 9. | In light of the ALJ decision to disallow $126 million of your unsettled gross SECA revenues, please explain to us how you determined it was appropriate to only reserve for $37 million in net refunds. Refer to paragraph 11.a of SFAS 71 and paragraph 8 of SFAS 5. |
Response:
The AEP east transmission zone electric operating companies provided through December 31, 2006 for $37 million of SECA refunds as management’s best estimate of the probable loss rather than the $126 million exposure computed from the FERC Administrative Law Judge’s (ALJ) recommended Initial Decision to the FERC. The $37 million was based on executed settlements with SECA ratepayers that had been approved by the FERC, executed settlements that have not yet been approved but that are expected to be approved by the FERC and an estimate of future settlements with all remaining SECA ratepayers based on actual settlement experience. Management thought it was appropriate, however, to disclose the exposure to the $126 million ALJ recommendation.
The relevant Generally Accepted Accounting Principles that support AEP’s decision merely to disclose rather than to provide for the possible refund that could result from the ALJ’s recommendations in their entirety are paragraph 11 of SFAS 71 and paragraph 8 and 10 of SFAS 5. Paragraph 11 of SFAS 71 indicates that a regulator can impose a liability on a regulated enterprise by requiring a refund to customers, and paragraph 11 further states that a refund that meets the criteria in paragraph 8 of SFAS 5 shall be recorded as a liability. Paragraph 8 of SFAS 5 requires that an estimated loss from a loss contingency be recorded as a charge to income if the information available prior to the issuance of the financial statements indicates that it is probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. Management applied these principles to the facts available at each balance sheet issuance date since the issuance of the ALJ’s recommendation in August 2006 and concluded that the appropriate provision for a possible SECA refund at September 30, 2006 was $22 million and at December 31, 2006 was $37 million.
Relative to paragraph 11 of SFAS 71, it is important to note, that the ALJ is not the regulator nor has the ALJ imposed a liability on the AEP east companies. Further, the ALJ does not have the legal authority to order a refund or impose a liability on the AEP east companies. Only a majority of the FERC Commissioners can order a refund and impose a liability on FERC jurisdictional companies. The ALJ’s Initial Decision is a recommendation that the Commission should find that the rate design for the recovery of SECA charges was flawed and that a large portion of the revenues collected through the SECA rates were not recoverable. The FERC Commissioners are required to review the evidence in the case and the ALJ’s recommendations. The FERC will decide whether it agrees with the ALJ’s recommendations and order a refund or whether it disagrees and opt not to order a refund. Further, if the FERC orders a refund, and thereby imposes a liability, it could determine that a different amount for such refund is appropriate rather than the $126 million that would result from the FERC upholding the ALJ’s recommendations in their entirety. It is not unusual for the FERC to reverse an ALJ’s recommendations in their entirety or in part. In fact, the FERC recently issued orders reversing the ALJ’s recommended decisions in two proceedings that impacted AEP.
Based on the above, whether the AEP East companies should record a provision for a refund is subject to a probability analysis pursuant to paragraph 8 of SFAS 5. As disclosed on page A-43 of the Form 10-Q for the period ended September 30, 2006 (the “Third Quarter 10-Q”), “We believe that the FERC should reject the initial ALJ decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, we believe the ALJ’s findings on key issues are largely without merit.” This disclosure is repeated on page A-81 of the 2006 Form 10-K. As further reported in the Third Quarter 10-Q, AEP filed an extensive brief noting exceptions to the ALJ recommendations in her Initial Decision and recommended that the FERC reverse the ALJ. Among other errors in the ALJ’s Initial Decision, AEP’s brief pointed out that at least two of the ALJ’s recommendations, which account for the bulk of the $126 million refund exposure, contradict FERC policy and prior FERC orders, thus making it probable, in AEP’s opinion, that the ALJ will be reversed on these points. The beliefs expressed in the Third Quarter 10-Q are based on the strength of the filed brief and on legal opinions of AEP’s internal and external FERC legal counsel. As a result, management concluded that it was only reasonably possible that the FERC would impose a significant SECA refund on the AEP East companies. Since management concluded that it was not probable that the FERC would affirm the ALJ’s recommended decision, it disclosed the existing contingency in accordance with the requirements of paragraph 10 of SFAS 5, but did not record a provision for the ALJ’s recommended $126 million refund.
Prior to the ALJ’s Initial Decision and at the request of the FERC, AEP was actively engaged in settlement discussions with SECA ratepayers to mitigate the risk of litigation. These discussions resulted in settlements being reached with certain SECA ratepayers that had collectively paid about one-third of the SECA revenues collected by AEP. Under those executed settlements, AEP agreed to refund about 10% of approximately $70 million in SECA rates collected by AEP from customers willing to reach settlements at that time. Based on these executed settlements at approximately 10% and the fact that collected SECA revenues totaled approximately $220 million, the AEP East companies provided for $22 million in executed and probable future SECA refunds prior to the ALJ Initial Decision. After the ALJ’s Initial Decision and based on subsequent on-going settlement discussions, AEP provided an additional $15 million in recognition that the ALJ’s Initial Decision had increased settlement expectations of the remaining SECA ratepayers. The additional $15 million increased the amount provided for unsettled SECA refunds to 20%, or about 17% overall. It is important to note that the FERC has approved several of the executed settlements which are for amounts significantly less than the ALJ’s recommendation and settlements have been reached since the ALJ’s recommendation that are also for amounts significantly less than the ALJ’s recommendation. Management expects that by the time the FERC issues its final decision on SECA, we would have executed additional settlements and the FERC will approve all of the remaining executed settlements. At this time the AEP East companies have reached settlements for approximately $70 million of the original $220 million of SECA revenues for a total agreed refund amount of about $7 million. We are in process of finalizing additional settlements which support the reasonableness of the $37 million provision.
When the fourth quarter 2006 financial statements were issued, management concluded that due to executed settlements and on-going settlement discussions it is probable that the FERC will order refunds and that there is a range of possible refunds that the FERC could order. At the low end was the $10 million that AEP has agreed to refund in executed settlements. Also included in the range of possible refunds is (i) the ALJ’s recommended Initial Decision, which was computed to produce a $126 million refund and (ii) AEP’s estimate of $37 million to settle with all SECA ratepayers. FASB Interpretation No. 14, an interpretation of SFAS 5, states that when a probable loss cannot be determined and there is a range of possible losses and there is an amount within the range that appears at the time to be a better estimate of the probable loss then that amount should be accrued. If no amount in the range is a better estimate than any other amount then the minimum should be accrued. Management applied these principles and concluded that its $37 million estimate of the amount to be refunded was the better amount along the range of possible amounts because it concluded that the total settlement refunds FERC will ultimately approve will probably exceed the $10 million minimum amount of executed settlements and because legal counsel advised management that it is probable that the ALJ’s $126 million refund recommendation would be rejected by the FERC. As a result, management recorded a $37 million provision for refund and disclosed the $126 million exposure to the ALJ’s recommendation in the 2006 10-K.
Note 5. Effects of Regulation, page A-84
| 10. | Please provide us with your probability assessment of the future recovery of the unfunded status of your defined benefit plans for each regulatory jurisdiction. In your response, please tell us how SFAS 87 costs are currently being recovered in rates and on what basis they are being recovered, explain the regulators’ historical approach to inclusion of the costs in rates, provide an analysis of whether there are significant uncertainties indicated by the regulators regarding the current or future rate recovery approach for SFAS 87 costs and the specific actions by the regulators with respect to unfunded pension liabilities. |
Response:
In accordance with paragraph 9 of SFAS 71, Accounting for the Effects of Certain Types of Regulation, a regulatory asset is recorded for deferred costs for which it is probable that future revenue will result from inclusion of the deferred costs in future cost of service for ratemaking purposes. Such deferred costs are recognized in the income statement and in equity on a delayed basis when the related revenue is recognized.
SFAS 158 results in balance sheet adjustments related to SFAS 87 pension costs. For pension regulatory assets, Question 4 of the SFAS 87 FASB Staff Implementation Guide specifically addresses the recording of a regulatory asset or a regulatory liability when the amount of pension cost for ratemaking purposes differs from SFAS 87 pension cost. As discussed below, the SFAS 71 regulated operations of the AEP System companies meet the regulatory asset criteria for pension cost in all jurisdictions. Specifically, recovery of SFAS 158 pension regulatory assets in those regulated jurisdictions is probable. Accordingly, the AEP utility subsidiaries recorded a pension regulatory asset for their SFAS 71 regulated operations to offset the negative AOCI equity effect of adopting SFAS 158 in December 2006.
The AEP nonregulated companies and the nonregulated generation operations in Ohio, Texas, and Virginia did not qualify for SFAS 71 regulatory assets, and as such, recorded no regulatory asset to offset the negative AOCI equity effect of adopting SFAS 158 in December 2006.
AEP’s treatment in its jurisdictions is as follows:
FERC, Arkansas, Indiana, Kentucky, Michigan, Ohio, Oklahoma, Tennessee, Virginia, and West Virginia Jurisdictions
Pension costs are recovered in current rates based on accrual accounting under SFAS 87, as the utility’s SFAS 87 costs are included in the cost of service approved in a commission rate order. Historically, each of these commissions has followed this rate treatment for many years. We do not expect any change in these commissions’ recovery approach. Therefore, recovery of SFAS 158 pension regulatory assets is probable.
Louisiana Jurisdiction
Although the Louisiana Commission has previously set other utilities’ rates based on pension costs under SFAS 87, AEP’s current Louisiana rates are based on a settlement agreement that does not specifically address pension cost, and prior rates from before implementation of SFAS 87 were based on pension contributions. However, as part of AEP’s pending rate review proceeding with the Louisiana Commission, AEP agreed in 2005 to follow the Commission’s standard treatment of pension cost for other utilities by following accrual accounting under SFAS 87. Therefore, recovery of SFAS 158 pension regulatory assets is probable.
Texas Jurisdiction
In 2005, the Texas Legislature enacted Senate Bill 1447, which changes Texas state law to require the Texas Commission to include in rates pension costs in accordance with generally accepted accounting principles. Previously, pension costs were included in rates based on cash contributions.
There have been no Texas rate orders since the law changed, but in AEP’s current rate case proceeding, no parties have opposed our including pension costs in rates based on SFAS 87, as the new state law requires. Therefore, pension costs are expected to be recovered in rates based on accrual accounting under SFAS 87, and recovery of SFAS 158 pension regulatory assets is probable.
Note 13. Income Taxes, page A-115
| 11. | We note that a significant portion of deferred tax assets and deferred tax liabilities were netted in the line item “All Other, Net” in the table on page A-116. To the extent material, please separately disclose each type of deferred tax asset and deferred tax liability comprising this line item. See paragraph 43 of SFAS 109. |
Response:
We applied a materiality test for the net deferred tax liability table equal to 5% of AEP’s consolidated total net deferred tax liability balance of $4,690 million in 2006 and $4,810 million in 2005. As such, we separately reported deferred tax assets and deferred tax liabilities for items that exceeded $234 million in 2006 and $241 million in 2005 of total net deferred tax liabilities. There were no deferred tax asset or deferred tax liability items that exceeded the 5% materiality level included in the “All Other, Net” category; therefore, we aggregated the amounts.
The 5% threshold was also calculated and applied at the subsidiary registrant level. There were no deferred tax asset or deferred tax liability items that exceeded the 5% materiality level included in the “All Other, Net” category; therefore, we aggregated the amounts.
Note 15. Financing Activities, page A-120
Dividend Restrictions, page A-123
| 12. | In light of the dividend restrictions placed on the registrant subsidiaries, please explain to us in detail how you concluded that you are not required to provide Schedule I. Refer to Rules 4-08(e), 5-04 and 12-04 of Regulation S-X. |
Response:
AEP’s language in the Form 10-K describing the dividend restrictions referenced above is inaccurate. Section 305(a) of the Federal Power Act restricts public utilities from paying dividends from capital accounts comprised of the stated/par value of common and preferred stock (the “Par Value Accounts”). The amounts in the Par Value Accounts of the utility registrants would be considered restricted net assets under Rules 4-08 and 5-04 of Regulation S-X. Because such restricted net assets were only approximately 14% of AEP’s consolidated net assets as of the end of the most recently completed fiscal year, Schedule I disclosure is not required pursuant to Regulation S-X. In future filings, AEP will change the language describing the dividend restriction to read as follows:
“Under the Federal Power Act, AEP’s public utility subsidiaries are restricted from paying dividends out of stated capital.”
AEP Generating Company Balance Sheets, page B-6
| 13. | Please explain to us the nature of the accrued tax benefits line item. We note that this line item is presented on several of the registrant subsidiaries’ balance sheets. |
Response:
Several of the registrant subsidiaries have accrued tax benefits which are temporary debit balances in accrued tax accounts by tax type. They result from the difference in the timing of current tax payments and tax overpayment carry forwards as compared to the tax accruals at the date of each Balance Sheet. The various types of taxes (depending upon the company) presented as Accrued Tax Benefits included federal income, state income, state franchise, state single business, and local income taxes. We perform an analysis of the accrued taxes accounts to identify occasions where an accrued tax benefit exists with respect to a particular type of tax. If any tax category has a debit balance at quarter end, it is recorded as Accrued Tax Benefits in the Current Assets section of the Balance Sheets.
Notes to Financial Statements of Registrant Subsidiaries, page L-1
General
| 14. | Please address the above comments on the financial statements and related disclosures of the parent in the financial statements and related disclosures of the registrant subsidiaries, as applicable. |
Response:
Any proposed changes to the financial statements and related disclosures of the parent will be made in the financial statements and related disclosures of the registrant subsidiaries, as applicable.
Note 15. Financing Activities, page L-73
Long-term Debt, page L-74
| 15. | Please explain to us why the AEGCo Pollution Controls Bonds were classified as current in 2005 and long-term in 2006. |
Response:
The AEGCo Pollution Control Bonds (the "Bonds") were classified as current in 2005 because they had a mandatory tender date of July 13, 2006, which was within one year from December 31, 2005. On July 13, 2006, the Bonds were remarketed as term rate bonds with a new mandatory tender date of July 15, 2011. Since the remarketed bonds have a mandatory tender date beyond one year, they were classified as long term at December 31, 2006.
Exhibits 31 and 32
| 16. | In future filings please provide separate certifications for each registrant. |
Response:
Beginning with the Form 10-Q for the period ended March 31, 2007, AEP and its registrant subsidiaries provided separate certificates for each registrant.
* * *
AEP acknowledges that: (i) it is responsible for the adequacy and accuracy of the disclosure in the filing; (ii) 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 (iii) 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 me (614-716-2821) with any questions you may have regarding this filing or if you wish to discuss the above responses.
Very truly yours,
/s/ Joseph M. Buonaituo
Joseph M. Buonaiuto
c: William Thompson, Branch Chief
c: Sarah Goldberg, Staff Accountant