Operating revenues are derived from the sale of our share of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements. The unit power agreements provide for a FERC approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Fluctuations in Net Income are a result of terms in the unit power agreements which allow for the calculation of return on total capital monthly.
Gross Margin decreased $2.5 million primarily due to a decrease in operation and maintenance expense. Gross Margin fluctuates consistent with operation and maintenance expense in accordance with the unit power agreements.
The decrease in Other Operation and Maintenance expenses resulted from decreased outages and the related costs compared to prior year. In 2004, Rockport Plant Unit 2 was shutdown for planned boiler inspection and repairs from early February through the end of the quarter.
The effective tax rates for the first quarter of 2005 and 2004 were 1.8% and (9.5)%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is primarily due to amortization of investment tax credits, flow-through of book versus tax temporary differences and state income taxes. The increase in the effective tax rate is primarily due to higher pretax income in 2005.
In prior years, we entered into an off-balance sheet arrangement. Our current policy restricts the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements. Our off-balance sheet arrangement has not changed significantly since year-end. For complete information on our off-balance sheet arrangement see “Off-balance Sheet Arrangements” in the “Management’s Narrative Discussion and Analysis” section of our 2004 Annual Report.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and the impact of new accounting pronouncements.
The notes to AEGCo’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to AEGCo.
Net Income decreased $28 million to $1 million in the first quarter of 2005. The key drivers of the decrease were a $44 million decrease in gross margin partially offset by a net decrease in Other Operation and Maintenance of $8 million and by a $13 million decrease in Income Tax Expense.
The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
The effective tax rates for the first quarter of 2005 and 2004 were (906.2)% and 29.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, consolidated tax savings from parent, state income taxes and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is primarily due to lower pretax income in 2005, federal income tax adjustments and consolidated tax savings from parent, offset in part by a decrease in state income taxes.
The rating agencies currently have us on stable outlook. Our current ratings are as follows:
Our net cash flows used for operating activities were $121 million for the first three months of 2005. We produced income of $1 million during the period including noncash expense items of $29 million for Depreciation and Amortization and $(30) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relate to a number of items; the most significant are decreases in Accounts Payable, Taxes Accrued and Interest Accrued offset in part by an increase in Accounts Receivable, Net. Accounts Payable decreased $41 million primarily due to lower vendor related payables and lower third party energy transactions. Taxes Accrued decreased $118 million primarily due to a Federal income tax payment offset by the annual tax accruals related to 2005 property taxes. Interest Accrued decreased $22 million primarily due to interest payments on debentures and senior unsecured notes offset by monthly accruals.
Our net cash flows from operating activities were $26 million for the first three months of 2004.We produced income of $29 million during the period including noncash expense items of $29 million for Depreciation and Amortization and $(34) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in these asset and liability accounts relates to a number of items; the most significant is an increase in Taxes Accrued offset by decreases in Accounts Payable and Interest Accrued.Taxes Accrued increased $32 million primarily due to the annual tax accruals related to property taxes net of a payment in 2004 and by a decrease in Federal income tax refunds. Accounts Payable decreased $14 million primarily due to decreased trading related payables and fewer fuel related shipments. Interest Accrued decreased $20 million primarily due to interest payments on debentures and senior unsecured notes offset by monthly accruals.
Cash Flows From Investing Activities were $4 million in 2005 primarily due to a decrease of $32 million in Other Cash Deposits, Net related to principal payments on transition funding bonds offset by Construction Expenditures of $28 million related to projects for improved transmission and distribution service reliability. For the remainder of 2005, we expect our Construction Expenditures to be approximately $180 million.
Cash Flows From Investing Activities were $5 million in 2004 primarily due to a decrease of $28 million in Other Cash Deposits, Net related to principal payments on transition funding bonds offset by Construction Expenditures of $24 million related to projects for improved transmission and distribution service reliability.
Cash Flows From Financing Activities of $118 million in 2005 were due to a $238 million increase in Advances to/from Affiliates, Net and issuances of Installment Purchase Contracts of $159 million offset by retirements of Senior Unsecured Note Payables and Securitization Bonds of $279 million.
Cash Flows Used for Financing Activities of $29 million in 2004 were due to retirements of long-term debt, payment of dividends and increased Advances to Affiliates.
Long-term debt issuances and retirements during the first three months of 2005 were:
We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity. Finally, we expect to receive asset sale proceeds of approximately $333 million in the first half of 2005, subject to resolution of the rights of first refusal issues and obtaining the necessary regulatory approvals.
The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of our net stranded generation costs and other recoverable true-up items in our future true-up filing. We have asked permission from the PUCT to file our True-up Proceeding after the sales of our interest in STP have been concluded. If the request is approved, it is anticipated that our True-up Proceeding will be filed during the second quarter of 2005 seeking recovery of our net regulatory asset of $1.6 billion for our net stranded cost and other true-up items which we believe the Texas Restructuring Legislation allows.
We continue to accrue a carrying cost at the embedded 8.12% debt component rate and will continue to do so until we recover our approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 further clarifying how the amounts are to be calculated. This resulted in a reduction in our accrued carrying costs based on the methodology detailed in the order for calculating a cost-of-money benefit related to Accumulated Deferred Federal Income Taxes (ADFIT) on our net stranded cost and other true-up items retroactive to January 1, 2004. In the first quarter of 2005, we accrued carrying costs of $21 million, which was more than offset by an adverse adjustment of $27 million based on this order. The net reduction of $6 million in carrying costs is included in Nonoperating Income in the first quarter of 2005 on our accompanying Consolidated Statements of Income.
As of March 31, 2005, we have computed carrying costs of $450 million of which $296 million was recognized as income in 2004 and the first quarter of 2005. The remaining equity component of the carrying cost of $154 million will be recognized in income as collected.
When the True-up Proceeding is completed, we intend to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated transmission and distribution rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.
We believe that our recorded net true-up regulatory asset of $1.6 billion at March 31, 2005 isrecoverable underthe Texas Restructuring Legislation; however, we anticipate that other parties will contend that material amounts of stranded costs should not be recovered.To the extent decisions of the PUCT in our future True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated companies, additional material disallowances and reductions of recorded carrying costs are possible, which could have a material adverse effect on our future results of operations, cash flows and possibly financial condition.
We have an on-going transmission and distribution rate review before the PUCT. In that rate review, the PUCT has issued various decisions and conducted additional hearings in March 2005. At an open meeting on April 13, 2005, the PUCT decided all remaining issues except the amount of affiliate expenses to include in revenue requirements which the PUCT decided to defer. Adjusted for the decisions approved by the PUCT through April 13, 2005, the ALJ’s recommended disallowances of affiliate expenses would produce an annual rate reduction of $25 million to $52 million. If we were to prevail on the affiliate expenses issue, the result would be an annual rate increase of $2 million. An order reducing our rates could have an adverse effect on future results of operations and cash flows.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $3,634 thousand loss.
Our counterparty credit quality and exposure is generally consistent with that of AEP.
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $127 million and $120 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.
The notes to TCC’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to TCC.
Net Income decreased $6 million to $7 million in the first quarter of 2005. The key drivers of the decrease were a $9 million decrease in gross margin offset by a $3 million decrease in Income Tax Expense.
The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
The effective tax rate for the first quarter of 2005 and 2004 was 33.8% and 34.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits and state income taxes. The effective tax rate remained relatively flat for the comparative period.
The rating agencies currently have us on stable outlook. Our current ratings are as follows:
There were no long-term debt issuances or retirements during the first three months of 2005.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effects on us.
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $470 thousand loss.
Our counterparty credit quality and exposure is generally consistent with that of AEP.
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $15 million and $13 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or financial position.
The notes to TNC’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to TNC.
Net Income decreased $18 million to $47 million in the first quarter of 2005. The key drivers of the decrease were a $21 million decrease in gross margin and a $13 million net increase in operating expenses and other partially offset by a $16 million decrease in income taxes.
The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
The effective tax rates for the first quarter of 2005 and 2004 were 34.3% and 38.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in permanent differences including COLI and lower state income taxes.
The rating agencies currently have us on stable outlook. Current ratings are as follows:
Our net cash flows from operating activities were $95 million in 2005. We produced income of $47 million during the period and noncash expense items of $50 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had no significant items.
Our net cash flows from operating activities were $181 million in 2004. We produced income of $65 million during the period and had a noncash expense item of $48 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital had one significant item; a decrease in Accounts Receivable of $55 million due to settlements of affiliated receivables at December 2003 as well as a lower MLR share of physical off-system sales from December 2003 to March 2004.
In 2005, we issued Senior Unsecured Notes of $200 million with an interest rate of 4.95% and received a capital contribution from our parent of $100 million. In addition, we repaid $211 million of advances from affiliates and advanced $29 million to our affiliates.
In 2004, we retired $40 million of Installment Purchase Contracts with an interest rate of 5.45%.In addition, we repaid $66 million of advances from affiliates and paid $25 million in common stock dividends.
Long-term debt issuances and retirements during the first three months of 2005 were:
We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
We employ the use of interest rate forward and swap transactions in order to manage interest rate risk to existing floating rate debt, to manage interest rate exposure on anticipated floating rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $8,899 thousand loss.
Counterparty credit quality and exposure is generally consistent with that of AEP.
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $114 million and $99 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.
The notes to APCo’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to APCo.
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
First Quarter of 2005 Compared to First Quarter of 2004
Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)
First Quarter of 2004 Net Income | | | | | $ | 43 | |
| | | | | | | | |
Changes in Gross Margin: | | | | | | | |
| Retail Margins | | | 5 | | | | |
| Transmission Revenues | | | (7 | ) | | | |
| Off-system Sales | | | 2 | | | | |
| Other Revenues | | | 1 | | | | |
Total Change in Gross Margin | | | | | | 1 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | |
| Other Operation and Maintenance | | | (6 | ) | | | |
| Taxes Other Than Income Taxes | | | (2 | ) | | | |
| Nonoperating Income and Expenses, Net | | | (4 | ) | | | |
| Interest Charges | | | 2 | | | | |
Total Change in Operating Expenses and Other | | | | | | (10 | ) |
| | | | | | | | |
| Income Tax Expense | | | | | | 6 | |
| | | | | | | | |
First Quarter of 2005 Net Income | | | | | $ | 40 | |
Net Income decreased $3 million to $40 million in the first quarter of 2005. The key driver of the decrease was a $10 million net increase in operating and other expenses partially offset by a $6 million decrease in income taxes.
The major components of our increase in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
| · | Retail Margins increased $5 million primarily due to an $11 million increase in capacity settlement payments under the Interconnection Agreement related to the increase in an affiliate’s peak partially offset by a $6 million increase in unrecovered fuel costs. |
| · | Margins from Transmission Revenues decreased $7 million primarily due to the loss of through and out rates as mandated by the FERC. |
Operating Expenses and Other changed between years as follows:
| · | Other Operation and Maintenance expenses increased $6 million primarily due to a $12 million increase in distribution maintenance mainly for storm damage expenses partially offset by the settlement and cancellation of the corporate owned life insurance policy in February 2005. |
| · | Taxes Other Than Income Taxes increased $2 million primarily due to a $1 million increase in property taxes and a $1 million increase in payroll-related taxes. |
| · | Nonoperating Income and Expenses, Net declined $4 million reflecting lower margins on risk management transactions. |
| · | Interest Charges decreased $2 million primarily due to lower long-term debt interest expense resulting from lower debt balances and lower interest rates. |
Income Tax
The effective tax rates for the first quarter of 2005 and 2004 were 33.2% and 37.6%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to lower state and local income taxes and changes in permanent differences including COLI.
Financial Condition
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as follows:
| | Moody’s | | S&P | | Fitch |
| | | | | | |
| Senior Unsecured Debt | Baa2 | | BBB | | BBB |
Cash Flow
Cash flows for the first three months of 2005 and 2004 were as follows:
| | | 2005 | | 2004 | |
| | | (in thousands) | |
Cash and cash equivalents at beginning of period | | $ | 465 | | $ | 3,899 | |
| Cash flows from (used for): | | | | | | | |
| Operating activities | | | 42,077 | | | 181,789 | |
| Investing activities | | | (60,537 | ) | | (35,282 | ) |
| Financing activities | | | 18,530 | | | (147,177 | ) |
| Net increase (decrease) in cash and cash equivalents | | | 70 | | | (670 | ) |
Cash and cash equivalents at end of period | | $ | 535 | | $ | 3,229 | |
Operating Activities
Our net cash flows from operating activities were $42 million for the first three months of 2005.We produced income of $40 million during the period including noncash expense items of $54 million for depreciation, amortization and accretion. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant were a $15 million contribution to our pension trust, an $81 million federal income tax payment and a net change in accounts receivable and payable of $11 million.
Our net cash flows from operating activities were $182 million in 2004. We produced Net Income of $43 million during the period and noncash expense items of $52 million for Depreciation, Amortization and Accretion. The other changes in assets and liabilities represent items that had a cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items; the most significant relates to Taxes Accrued. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP Consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments.
Investing Activities
Cash flows used for investing activities during 2005 were $61 million due to construction expenditures and a deposit to purchase emissions allowances. Construction expenditures were primarily incurred for nuclear generation, transmission and distribution assets to upgrade or replace equipment and improve reliability. For the remainder of 2005, we expect our Construction Expenditures to be approximately $270 million.
Our cash flows used for investing activities were $35 million in 2004 for construction.
Financing Activities
During the first quarter of 2005, we used cash of $61 million to retire preferred stock and $21 million to pay common dividends. These activities and our Construction Expenditures were supported by additional borrowing from the Money Pool of $101 million. There were no long-term debt issuances or retirements during the first quarter of 2005.
Our cash flows used for financing activities were $147 million in 2004. We used cash from operations to repay short-term debt and pay common dividends.
Liquidity
We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.
Off-Balance Sheet Arrangements
We enter into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. Our current policy restricts the use of off-balance sheet financing entities or structures, except for traditional operating lease arrangements and sales of customer accounts receivable that are entered in the normal course of business. Our off-balance sheet arrangements have not changed significantly since year-end. For complete information on our off-balance sheet arrangements see “Off-balance Sheet Arrangements” in “Management’s Financial Discussion and Analysis” section of our 2004 Annual Report.
Significant Factors
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
Critical Accounting Estimates
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.
MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2004 | | $ | 34,573 | |
| (Gain) Loss from Contracts Realized/Settled During the Period (a) | | | (74 | ) |
| Fair Value of New Contracts When Entered During the Period (b) | | | - | |
| Net Option Premiums Paid/(Received) (c) | | | - | |
| Change in Fair Value Due to Valuation Methodology Changes | | | - | |
| Changes in Fair Value of Risk Management Contracts (d) | | | (233 | ) |
| Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) | | | 3,105 | |
Total MTM Risk Management Contract Net Assets | | | 37,371 | |
| Net Cash Flowand Fair ValueHedge Contracts (f) | | | (7,971 | ) |
| DETM Assignment (g) | | | (12,342 | ) |
Total MTM Risk Management Contract Net Assets at March 31, 2005 | | $ | 17,058 | |
| (a) | “(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005where we entered into the contractprior to 2005. |
| (b) | “Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. |
| (c) | “Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005. |
| (d) | “Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc. |
| (e) | “Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. |
| (f) | “Net Cash Flowand Fair ValueHedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss). |
| (g) | See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report. |
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)
| | | MTM Risk Management Contracts (a) | | Hedges | | DETM Assignment (b) | | Total (c) | |
| Current Assets | | $ | 69,207 | | $ | 3,282 | | $ | - | | $ | 72,489 | |
| Noncurrent Assets | | | 82,728 | | | 412 | | | - | | | 83,140 | |
Total MTM Derivative Contract Assets | | | 151,935 | | | 3,694 | | | - | | | 155,629 | |
| | | | | | | | | | | | | | |
| Current Liabilities | | | (63,778 | ) | | (10,333 | ) | | (5,052 | ) | | (79,163 | ) |
| Noncurrent Liabilities | | | (50,786 | ) | | (1,332 | ) | | (7,290 | ) | | (59,408 | ) |
Total MTM Derivative Contract Liabilities | | | (114,564 | ) | | (11,665 | ) | | (12,342 | ) | | (138,571 | ) |
| | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 37,371 | | $ | (7,971 | ) | $ | (12,342 | ) | $ | 17,058 | |
| (a) | Does not include Cash Flow and Fair Value Hedges. |
| (b) | See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report. |
| (c) | Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
| · | The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). |
| · | The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash. |
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31, 2005
(in thousands)
| | | Remainder of 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | After 2009 (c) | | Total (d) | |
| Prices Actively Quoted - ExchangeTraded Contracts | | $ | (5,505 | ) | $ | 2,119 | | $ | 4,389 | | $ | - | | $ | - | | $ | - | | $ | 1,003 | |
Prices Provided by Other ExternalSources - OTC Broker Quotes (a) | | | 10,549 | | | 11,402 | | | 7,912 | | | 3,638 | | | - | | | - | | | 33,501 | |
| Prices Based on Models and OtherValuation Methods (b) | | | (202 | ) | | (5,861 | ) | | (4,233 | ) | | 3,010 | | | 5,378 | | | 4,775 | | | 2,867 | |
Total | | $ | 4,842 | | $ | 7,660 | | $ | 8,068 | | $ | 6,648 | | $ | 5,378 | | $ | 4,775 | | $ | 37,371 | |
| (a) | “Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. |
| (b) | “Prices Based on Models and Other Valuation Methods” is in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market. |
| (c) | There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $4.6 million of this mark-to-market value is in 2010. |
| (d) | Amounts exclude Cash Flow and Fair Value Hedges. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
We employ the use of interest rate forward transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)
| | | Power | | Interest Rate | | Total | |
Beginning Balance December 31, 2004 | | $ | 1,558 | | $ | (5,634 | ) | $ | (4,076 | ) |
| Changes in Fair Value (a) | | | (4,272 | ) | | - | | | (4,272 | ) |
| Reclassifications from AOCI to NetIncome (b) | | | (2,184 | ) | | 143 | | | (2,041 | ) |
Ending Balance March 31, 2005 | | $ | (4,898 | ) | $ | (5,491 | ) | $ | (10,389 | ) |
| (a) | “Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes. |
| (b) | “Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes. |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $5,062 thousand loss.
Credit Risk
Our counterparty credit quality and exposure is generally consistent with that of AEP.
VaR Associated with Risk Management Contracts
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
| | Three Months Ended | | Twelve Months Ended | |
| | March 31, 2005 | | December 31, 2004 | |
| | (in thousands) | | (in thousands) | |
| | End | | High | | Average | | Low | | End | | High | | Average | | Low | |
| | $360 | | $796 | | $390 | | $235 | | $371 | | $1,211 | | $522 | | $178 | |
VaR Associated with Debt Outstanding
The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $53 million at both March 31, 2005 and December 31, 2004. We would not expect to liquidate our entire portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING REVENUES | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 361,592 | | $ | 353,822 | |
| Sales to AEP Affiliates | | | 80,551 | | | 57,645 | |
TOTAL | | | 442,143 | | | 411,467 | |
| | | | | | | | |
OPERATING EXPENSES | | | | | | | |
| Fuel for Electric Generation | | | 77,824 | | | 64,041 | |
| Purchased Electricity for Resale | | | 11,272 | | | 6,363 | |
| Purchased Electricity from AEP Affiliates | | | 74,009 | | | 63,128 | |
| Other Operation | | | 90,976 | | | 100,850 | |
| Maintenance | | | 54,322 | | | 38,042 | |
| Depreciation and Amortization | | | 42,745 | | | 42,715 | |
| Taxes Other Than Income Taxes | | | 17,507 | | | 15,216 | |
| Income Taxes | | | 19,934 | | | 24,299 | |
TOTAL | | | 388,589 | | | 354,654 | |
| | | | | | | | |
OPERATING INCOME | | | 53,554 | | | 56,813 | |
| | | | | | | | |
| Nonoperating Income | | | 17,497 | | | 20,588 | |
| Nonoperating Expenses | | | 16,013 | | | 14,851 | |
| Nonoperating Income Tax Expense (Credit) | | | (237 | ) | | 1,613 | |
| Interest Charges | | | 15,606 | | | 17,929 | |
| | | | | | | | |
NET INCOME | | | 39,669 | | | 43,008 | |
| | | | | | | | |
| Preferred Stock Dividend Requirements including CapitalStock Expense | | | 118 | | | 118 | |
| | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 39,551 | | $ | 42,890 | |
The common stock of I&M is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
DECEMBER 31, 2003 | | $ | 56,584 | | $ | 858,694 | | $ | 187,875 | | $ | (25,106 | ) | $ | 1,078,047 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (29,646 | ) | | | | | (29,646 | ) |
| Preferred Stock Dividends | | | | | | | | | (84 | ) | | | | | (84 | ) |
| Capital Stock Expense | | | | | | 34 | | | (34 | ) | | | | | - | |
TOTAL | | | | | | | | | | | | | | | 1,048,317 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Loss,Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $1,127 | | | | | | | | | | | | (2,093 | ) | | (2,093 | ) |
NET INCOME | | | | | | | | | 43,008 | | | | | | 43,008 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 40,915 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2004 | | $ | 56,584 | | $ | 858,728 | | $ | 201,119 | | $ | (27,199 | ) | $ | 1,089,232 | |
| | | | | | | | | | | | | | | | | |
DECEMBER 31, 2004 | | $ | 56,584 | | $ | 858,835 | | $ | 221,330 | | $ | (45,251 | ) | $ | 1,091,498 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (21,000 | ) | | | | | (21,000 | ) |
| Preferred Stock Dividends | | | | | | | | | (85 | ) | | | | | (85 | ) |
| Capital Stock Expense | | | | | | 33 | | | (33 | ) | | | | | - | |
TOTAL | | | | | | | | | | | | | | | 1,070,413 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Loss,Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $3,400 | | | | | | | | | | | | (6,313 | ) | | (6,313 | ) |
NET INCOME | | | | | | | | | 39,669 | | | | | | 39,669 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 33,356 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2005 | | $ | 56,584 | | $ | 858,868 | | $ | 239,881 | | $ | (51,564 | ) | $ | 1,103,769 | |
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
ELECTRIC UTILITY PLANT | | | | | |
| Production | | $ | 3,123,688 | | $ | 3,122,883 | |
| Transmission | | | 1,008,687 | | | 1,009,551 | |
| Distribution | | | 1,005,142 | | | 990,826 | |
| General (including nuclear fuel) | | | 278,890 | | | 275,622 | |
| Construction Work in Progress | | | 183,623 | | | 163,515 | |
Total | | | 5,600,030 | | | 5,562,397 | |
| Accumulated Depreciation and Amortization | | | 2,629,388 | | | 2,603,479 | |
TOTAL - NET | | | 2,970,642 | | | 2,958,918 | |
| | | | | | | | |
OTHER PROPERTY AND INVESTMENTS | | | | | | | |
| Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds | | | 1,079,926 | | | 1,053,439 | |
| Nonutility Property, Net | | | 49,731 | | | 50,440 | |
| Other Investments | | | 13,251 | | | 21,848 | |
TOTAL | | | 1,142,908 | | | 1,125,727 | |
| | | | | | | | |
CURRENT ASSETS | | | | | | | |
| Cash and Cash Equivalents | | | 535 | | | 465 | |
| Other Cash Deposits | | | 8,005 | | | 46 | |
| Advances to Affiliates | | | - | | | 5,093 | |
| Accounts Receivable: | | | | | | | |
| Customers | | | 61,822 | | | 62,608 | |
| Affiliated Companies | | | 101,537 | | | 124,134 | |
| Miscellaneous | | | 4,346 | | | 4,339 | |
| Allowance for Uncollectible Accounts | | | (76 | ) | | (187 | ) |
| Fuel | | | 21,219 | | | 27,218 | |
| Materials and Supplies | | | 104,886 | | | 103,342 | |
| Risk Management Assets | | | 72,489 | | | 52,141 | |
| Margin Deposits | | | 9,184 | | | 5,400 | |
| Prepayments and Other | | | 15,242 | | | 10,541 | |
TOTAL | | | 399,189 | | | 395,140 | |
| | | | | | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | | | | |
| Regulatory Assets: | | | | | | | |
| SFAS 109 Regulatory Asset, Net | | | 140,123 | | | 147,167 | |
| Incremental Nuclear Refueling Outage Expenses, Net | | | 38,727 | | | 44,244 | |
| Unamortized Loss on Reacquired Debt | | | 20,699 | | | 21,039 | |
| DOE Decontamination Fund | | | 12,928 | | | 14,215 | |
| Other | | | 48,426 | | | 31,015 | |
| Long-term Risk Management Assets | | | 83,140 | | | 52,256 | |
| Emission Allowances | | | 28,024 | | | 27,093 | |
| Deferred Property Taxes | | | 31,461 | | | 22,372 | |
| Deferred Charges and Other Assets | | | 18,381 | | | 28,955 | |
TOTAL | | | 421,909 | | | 388,356 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 4,934,648 | | $ | 4,868,141 | |
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)
| | | 2005 | | 2004 | |
CAPITALIZATION | | (in thousands) | |
| Common Shareholder’s Equity: | | | | | | | |
| Common Stock - No Par Value: | | | | | | | |
| Authorized - 2,500,000 Shares | | | | | | | |
| Outstanding - 1,400,000 Shares | | $ | 56,584 | | $ | 56,584 | |
| Paid-in Capital | | | 858,868 | | | 858,835 | |
| Retained Earnings | | | 239,881 | | | 221,330 | |
| Accumulated Other Comprehensive Income (Loss) | | | (51,564 | ) | | (45,251 | ) |
Total Common Shareholder’s Equity | | | 1,103,769 | | | 1,091,498 | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,084 | | | 8,084 | |
Total Shareholders’ Equity | | | 1,111,853 | | | 1,099,582 | |
| Long-term Debt | | | 1,314,137 | | | 1,312,843 | |
TOTAL | | | 2,425,990 | | | 2,412,425 | |
| | | | | | | | |
CURRENT LIABILITIES | | | | | | | |
| Cumulative Preferred Stock Due Within One Year | | | - | | | 61,445 | |
| Advances from Affiliates | | | 95,967 | | | - | |
| Accounts Payable: | | | | | | | |
| General | | | 92,019 | | | 91,472 | |
| Affiliated Companies | | | 38,599 | | | 51,066 | |
| Customer Deposits | | | 34,117 | | | 29,366 | |
| Taxes Accrued | | | 76,868 | | | 123,159 | |
| Interest Accrued | | | 22,072 | | | 12,465 | |
| Risk Management Liabilities | | | 79,163 | | | 47,174 | |
| Obligations Under Capital Leases | | | 5,730 | | | 6,124 | |
| Other | | | 74,372 | | | 70,237 | |
TOTAL | | | 518,907 | | | 492,508 | |
| | | | | | | | |
DEFERRED CREDITS AND OTHER LIABILITIES | | | | | | | |
| Deferred Income Taxes | | | 304,460 | | | 315,730 | |
| Regulatory Liabilities: | | | | | | | |
| Asset Removal Costs | | | 281,382 | | | 280,054 | |
| Deferred Investment Tax Credits | | | 80,970 | | | 82,802 | |
| Excess ARO for Nuclear Decommissioning | | | 259,825 | | | 245,175 | |
| Unrealized Gain on Forward Commitments | | | 48,972 | | | 35,534 | |
| Other | | | 30,832 | | | 33,695 | |
| Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 | | | 65,545 | | | 66,472 | |
| Long-term Risk Management Liabilities | | | 59,408 | | | 36,815 | |
| Obligations Under Capital Leases | | | 40,380 | | | 44,608 | |
| Asset Retirement Obligations | | | 723,433 | | | 711,769 | |
| Employee Benefits and Pension Obligations | | | 55,999 | | | 70,027 | |
| Deferred Credits and Other | | | 38,545 | | | 40,527 | |
TOTAL | | | 1,989,751 | | | 1,963,208 | |
| | | | | | | | |
| Commitments and Contingencies (Note 5) | | | | | | | |
| | | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 4,934,648 | | $ | 4,868,141 | |
See Notes to Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING ACTIVITIES | | | | | |
Net Income | | $ | 39,669 | | $ | 43,008 | |
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: | | | | | | | |
| Depreciation and Amortization | | | 42,745 | | | 42,715 | |
| Accretion Expense | | | 11,664 | | | 9,698 | |
| Amortization, net of Deferrals of Incremental Nuclear | | | | | | | |
| Refueling Outage Expenses | | | 5,517 | | | 13,179 | |
| Deferred Income Taxes | | | (876 | ) | | 1,895 | |
| Deferred Investment Tax Credits | | | (1,832 | ) | | (1,832 | ) |
| Deferred Property Taxes | | | (9,089 | ) | | (7,959 | ) |
| Pension Contributions | | | (15,350 | ) | | - | |
| Mark-to-Market of Risk Management Contracts | | | (5,722 | ) | | (7,396 | ) |
| Change in Other Noncurrent Assets | | | (1,214 | ) | | (7,341 | ) |
| Change in Other Noncurrent Liabilities | | | (5,972 | ) | | 8,960 | |
Changes in Components of Working Capital: | | | | | | | |
| Accounts Receivable, Net | | | 23,265 | | | 52,625 | |
| Fuel, Materials and Supplies | | | 4,455 | | | (7,335 | ) |
| Accounts Payable | | | (11,920 | ) | | (29,218 | ) |
| Taxes Accrued | | | (46,291 | ) | | 37,754 | |
| Customer Deposits | | | 4,751 | | | 8,873 | |
| Interest Accrued | | | 9,607 | | | 5,007 | |
| Rent Accrued - Rockport Plant Unit 2 | | | 18,464 | | | 18,464 | |
| Other Current Assets | | | (5,072 | ) | | 1,006 | |
| Other Current Liabilities | | | (14,722 | ) | | (314 | ) |
Net Cash Flows From Operating Activities | | | 42,077 | | | 181,789 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | |
| Construction Expenditures | | | (52,749 | ) | | (35,244 | ) |
| Change in Other Cash Deposits, Net | | | (7,959 | ) | | (38 | ) |
| Proceeds from Sale of Assets | | | 171 | | | - | |
Net Cash Flows Used For Investing Activities | | | (60,537 | ) | | (35,282 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | |
| Retirement of Cumulative Preferred Stock | | | (61,445 | ) | | (2,000 | ) |
| Changes in Advances to/from Affiliates, Net | | | 101,060 | | | (115,447 | ) |
| Dividends Paid on Common Stock | | | (21,000 | ) | | (29,646 | ) |
| Dividends Paid on Cumulative Preferred Stock | | | (85 | ) | | (84 | ) |
Net Cash Flows From (Used For) Financing Activities | | | 18,530 | | | (147,177 | ) |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 70 | | | (670 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 465 | | | 3,899 | |
Cash and Cash Equivalents at End of Period | | $ | 535 | | $ | 3,229 | |
SUPPLEMENTAL DISCLOSURE: |
| Cash paid (received) for interest net of capitalized amounts was $5,035,000 and $12,007,000 and for income taxes was $82,338,000 and $(5,480,000) in 2005 and 2004, respectively. Noncash acquisitions under capital leases were $404,000 and $373,000 in 2005 and 2004, respectively. |
See Notes to Respective Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to I&M’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to I&M.
| | Footnote Reference |
| | |
| Significant Accounting Matters | Note 1 |
| New Accounting Pronouncements | Note 2 |
| Rate Matters | Note 3 |
| Commitments and Contingencies | Note 5 |
| Guarantees | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Financing Activities | Note 10 |
KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
First Quarter of 2005 Compared to First Quarter of 2004
Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)
| First Quarter of 2004 Net Income | | | | | $ | 12 | |
| | | | | | | | |
Changes in Gross Margin: | | | | | | | |
| Retail Margins | | | (4 | ) | | | |
| Off-system Sales | | | 4 | | | | |
| Transmission Revenues | | | (2 | ) | | | |
| Other Revenues | | | (2 | ) | | | |
Total Change in Gross Margin | | | | | | (4 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | |
| Other Operation and Maintenance | | | - | | | | |
| Depreciation and Amortization | | | - | | | | |
| Taxes Other Than Income Taxes | | | - | | | | |
| Nonoperating Income and Expenses, Net | | | - | | | | |
| Interest Charges | | | - | | | | |
Total Change in Operating Expenses and Other | | | | | | - | |
| | | | | | | | |
| Income Tax Expense | | | | | | 2 | |
| | | | | | | | |
First Quarter of 2005 Net Income | | | | | $ | 10 | |
Net Income decreased $2 million to $10 million in the first quarter of 2005. The key driver of the decrease was a $4 million decrease in gross margin partially offset by a $2 million decrease in income taxes.
The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
| · | Retail Margins decreased by $4 million in comparison to 2004 primarily due to our higher MLR share caused by the increase in our peak demand established in both December 2004 and January 2005 resulting in a $4 million increase in capacity settlement payments under the Interconnection Agreement. |
| · | Margins from Off-system Sales for 2005 increased by $4 million in comparison to 2004 primarily due to higher sales volumes as well as higher optimization activity. |
| · | Margins from Transmission Revenues decreased $2 million primarily due to the elimination of $3 million of revenues related to through and out rates partially offset by an increase of $1 million in unbundled transmission revenues due to the addition of SECA rates as mandated by the FERC. |
| · | Margins from Other Revenues decreased $2 million primarily due to a $3 million adjustment of the Demand Side Management Program regulatory asset in March 2005. |
Income Taxes
The effective tax rates for the first quarter of 2005 and 2004 were 29.1% and 35.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in various permanent and flow-through temporary differences and lower state and local income taxes.
Financial Condition
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as follows:
| | Moody’s | | S&P | | Fitch |
| | | | | | |
| Senior Unsecured Debt | Baa2 | | BBB | | BBB |
Financing Activity
Long-term debt issuances and retirements during the first three months of 2005 were:
Issuances
None
Retirements
Notes Payable-Affiliated of $20 million with an interest rate of 6.50% was retired on April 15, 2005.
Significant Factors
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
Critical Accounting Estimates
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.
MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2004 | | $ | 12,691 | |
| (Gain) Loss from Contracts Realized/Settled During the Period (a) | | | (78 | ) |
| Fair Value of New Contracts When Entered During the Period (b) | | | - | |
| Net Option Premiums Paid/(Received) (c) | | | - | |
| Change in Fair Value Due to Valuation Methodology Changes | | | - | |
| Changes in Fair Value of Risk Management Contracts (d) | | | 276 | |
| Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) | | | 2,655 | |
Total MTM Risk Management Contract Net Assets | | | 15,544 | |
| Net Cash Flowand Fair ValueHedge Contracts (f) | | | (3,480 | ) |
| DETM Assignment (g) | | | (5,133 | ) |
Total MTM Risk Management Contract Net Assets at March 31, 2005 | | $ | 6,931 | |
| (a) | “(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005where we entered into the contractprior to 2005. |
| (b) | “Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. |
| (c) | “Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005. |
| (d) | “Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
| (e) | “Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. |
| (f) | “Net Cash Flowand Fair ValueHedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss). |
| (g) | See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report. |
Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of March 31, 2005
(in thousands)
| | | MTM Risk Management Contracts (a) | | Hedges | | DETM Assignment (b) | | Total (c) | |
| Current Assets | | $ | 28,786 | | $ | 1,552 | | $ | - | | $ | 30,338 | |
| Noncurrent Assets | | | 34,410 | | | 171 | | | - | | | 34,581 | |
Total MTM Derivative Contract Assets | | | 63,196 | | | 1,723 | | | - | | | 64,919 | |
| | | | | | | | | | | | | | |
| Current Liabilities | | | (26,528 | ) | | (4,239 | ) | | (2,101 | ) | | (32,868 | ) |
| Noncurrent Liabilities | | | (21,124 | ) | | (964 | ) | | (3,032 | ) | | (25,120 | ) |
Total MTM Derivative Contract Liabilities | | | (47,652 | ) | | (5,203 | ) | | (5,133 | ) | | (57,988 | ) |
| | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 15,544 | | $ | (3,480 | ) | $ | (5,133 | ) | $ | 6,931 | |
| (a) | Does not include Cash Flow and Fair Value Hedges. |
| (b) | See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report. |
| (c) | Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
| · | The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). |
| · | The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash. |
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31, 2005
(in thousands)
| | | Remainder of 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | After 2009 (c) | | Total (d) | |
Prices Actively Quoted - ExchangeTraded Contracts | | $ | (2,290 | ) | $ | 882 | | $ | 1,826 | | $ | - | | $ | - | | $ | - | | $ | 418 | |
Prices Provided by Other ExternalSources - OTC BrokerQuotes (a) | | | 4,388 | | | 4,743 | | | 3,291 | | | 1,514 | | | - | | | - | | | 13,936 | |
Prices Based on Models and OtherValuation Methods (b) | | | (88 | ) | | (2,438 | ) | | (1,760 | ) | | 1,253 | | | 2,237 | | | 1,986 | | | 1,190 | |
Total | | $ | 2,010 | | $ | 3,187 | | $ | 3,357 | | $ | 2,767 | | $ | 2,237 | | $ | 1,986 | | $ | 15,544 | |
| (a) | “Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. |
| (b) | “Prices Based on Models and Other Valuation Methods” is in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market. |
| (c) | There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $1.9 million of this mark-to-market value is in 2010. |
| (d) | Amounts exclude Cash Flow and Fair Value Hedges. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
We employ the use of interest rate swap transactions in order to manage interest rate risk to existing floating rate debt. We do not hedge all interest rate risk.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)
| | | Power | | Interest Rate | | Total | |
Beginning Balance December 31, 2004 | | $ | 569 | | $ | 244 | | $ | 813 | |
| Changes in Fair Value (a) | | | (1,702 | ) | | - | | | (1,702 | ) |
| Reclassifications from AOCI to NetIncome (b) | | | (903 | ) | | (22 | ) | | (925 | ) |
Ending Balance March 31, 2005 | | $ | (2,036 | ) | $ | 222 | | $ | (1,814 | ) |
| (a) | “Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes. |
| (b) | “Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes. |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,782 thousand loss.
Credit Risk
Our counterparty credit quality and exposure is generally consistent with that of AEP.
VaR Associated with Risk Management Contracts
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
| | Three Months Ended | | Twelve Months Ended | |
| | March 31, 2005 | | December 31, 2004 | |
| | (in thousands) | | (in thousands) | |
| | End | | High | | Average | | Low | | End | | High | | Average | | Low | |
| | $150 | | $331 | | $162 | | $98 | | $135 | | $442 | | $191 | | $65 | |
VaR Associated with Debt Outstanding
The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $16 million at both March 31, 2005 and December 31, 2004. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or financial position.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING REVENUES | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 115,660 | | $ | 107,046 | |
| Sales to AEP Affiliates | | | 12,189 | | | 6,612 | |
TOTAL | | | 127,849 | | | 113,658 | |
| | | | | | | | |
OPERATING EXPENSES | | | | | | | |
| Fuel for Electric Generation | | | 27,892 | | | 20,894 | |
| Purchased Electricity from AEP Affiliates | | | 44,863 | | | 33,306 | |
| Other Operation | | | 14,560 | | | 13,272 | |
| Maintenance | | | 5,916 | | | 7,325 | |
| Depreciation and Amortization | | | 11,152 | | | 10,859 | |
| Taxes Other Than Income Taxes | | | 2,425 | | | 2,328 | |
| Income Taxes | | | 4,008 | | | 6,460 | |
TOTAL | | | 110,816 | | | 94,444 | |
| | | | | | | | |
OPERATING INCOME | | | 17,033 | | | 19,214 | |
| | | | | | | | |
| Nonoperating Income | | | 445 | | | 952 | |
| Nonoperating Expenses | | | 171 | | | 1,313 | |
| Nonoperating Income Tax Expense (Credit) | | | 52 | | | (127 | ) |
| Interest Charges | | | 7,370 | | | 7,369 | |
| | | | | | | | |
NET INCOME | | $ | 9,885 | | $ | 11,611 | |
| | | | | | | | |
The common stock of KPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
DECEMBER 31, 2003 | | $ | 50,450 | | $ | 208,750 | | $ | 64,151 | | $ | (6,213 | ) | $ | 317,138 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (6,250 | ) | | | | | (6,250 | ) |
TOTAL | | | | | | | | | | | | | | | 310,888 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $406 | | | | | | | | | | | | (754 | ) | | (754 | ) |
NET INCOME | | | | | | | | | 11,611 | | | | | | 11,611 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 10,857 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2004 | | $ | 50,450 | | $ | 208,750 | | $ | 69,512 | | $ | (6,967 | ) | $ | 321,745 | |
| | | | | | | | | | | | | | | | | |
DECEMBER 31, 2004 | | $ | 50,450 | | $ | 208,750 | | $ | 70,555 | | $ | (8,775 | ) | $ | 320,980 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $1,415 | | | | | | | | | | | | (2,627 | ) | | (2,627 | ) |
NET INCOME | | | | | | | | | 9,885 | | | | | | 9,885 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 7,258 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2005 | | $ | 50,450 | | $ | 208,750 | | $ | 80,440 | | $ | (11,402 | ) | $ | 328,238 | |
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
ELECTRIC UTILITY PLANT | | | | | |
| Production | | $ | 464,637 | | $ | 462,641 | |
| Transmission | | | 385,912 | | | 385,667 | |
| Distribution | | | 442,925 | | | 438,766 | |
| General | | | 58,979 | | | 57,929 | |
| Construction Work in Progress | | | 14,702 | | | 16,544 | |
Total | | | 1,367,155 | | | 1,361,547 | |
| Accumulated Depreciation and Amortization | | | 406,584 | | | 398,455 | |
TOTAL - NET | | | 960,571 | | | 963,092 | |
| | | | | | | | |
OTHER PROPERTY AND INVESTMENTS | | | | | | | |
| Nonutility Property, Net | | | 5,437 | | | 5,438 | |
| Other Investments | | | 351 | | | 422 | |
TOTAL | | | 5,788 | | | 5,860 | |
| | | | | | | | |
CURRENT ASSETS | | | | | | | |
| Cash and Cash Equivalents | | | 276 | | | 127 | |
| Other Cash Deposits | | | 3,319 | | | 5 | |
| Advances to Affiliates | | | 24,734 | | | 16,127 | |
| Accounts Receivable: | | | | | | | |
| Customers | | | 24,674 | | | 22,130 | |
| Affiliated Companies | | | 23,232 | | | 23,046 | |
| Accrued Unbilled Revenues | | | 5,703 | | | 7,340 | |
| Miscellaneous | | | 109 | | | 94 | |
| Allowance for Uncollectible Accounts | | | (9 | ) | | (34 | ) |
| Fuel | | | 8,111 | | | 6,551 | |
| Materials and Supplies | | | 8,698 | | | 9,385 | |
| Risk Management Assets | | | 30,338 | | | 19,845 | |
| Margin Deposits | | | 3,760 | | | 1,960 | |
| Prepayments and Other | | | 3,294 | | | 1,782 | |
TOTAL | | | 136,239 | | | 108,358 | |
| | | | | | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | | | | |
| Regulatory Assets: | | | | | | | |
| SFAS 109 Regulatory Asset, Net | | | 100,954 | | | 103,849 | |
| Other | | | 22,875 | | | 14,558 | |
| Long-term Risk Management Assets | | | 34,581 | | | 19,067 | |
| Emission Allowances | | | 10,714 | | | 9,666 | |
| Deferred Property Taxes | | | 5,408 | | | 7,036 | |
| Deferred Charges and Other | | | 8,256 | | | 11,761 | |
TOTAL | | | 182,788 | | | 165,937 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 1,285,386 | | $ | 1,243,247 | |
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)
| | | 2005 | | 2004 | |
CAPITALIZATION | | (in thousands) | |
| Common Shareholder’s Equity: | | | | | | | |
| Common Stock - $50 par value per share: | | | | | | | |
| Authorized - 2,000,000 shares | | | | | | | |
| Outstanding - 1,009,000 shares | | $ | 50,450 | | $ | 50,450 | |
| Paid-in Capital | | | 208,750 | | | 208,750 | |
| Retained Earnings | | | 80,440 | | | 70,555 | |
| Accumulated Other Comprehensive Income (Loss) | | | (11,402 | ) | | (8,775 | ) |
Total Common Shareholder’s Equity | | | 328,238 | | | 320,980 | |
| Long-term Debt: | | | | | | | |
| Nonaffiliated | | | 427,375 | | | 428,310 | |
| Affiliated | | | 80,000 | | | 80,000 | |
Total Long-term Debt | | | 507,375 | | | 508,310 | |
TOTAL | | | 835,613 | | | 829,290 | |
| | | | | | | | |
CURRENT LIABILITIES | | | | | | | |
| Accounts Payable: | | | | | | | |
| General | | | 23,975 | | | 20,080 | |
| Affiliated Companies | | | 21,075 | | | 24,899 | |
| Risk Management Liabilities | | | 32,868 | | | 17,205 | |
| Taxes Accrued | | | 11,663 | | | 9,248 | |
| Interest Accrued | | | 8,992 | | | 6,754 | |
| Customer Deposits | | | 15,709 | | | 12,309 | |
| Obligations Under Capital Leases | | | 1,458 | | | 1,561 | |
| Other | | | 8,304 | | | 9,038 | |
TOTAL | | | 124,044 | | | 101,094 | |
| | | | | | | | |
DEFERRED CREDITS AND OTHER LIABILITIES | | | | | | | |
| Deferred Income Taxes | | | 224,214 | | | 227,536 | |
| Regulatory Liabilities: | | | | | | | |
| Asset Removal Costs | | | 29,214 | | | 28,232 | |
| Deferred Investment Tax Credits | | | 6,430 | | | 6,722 | |
| Other Regulatory Liabilities | | | 22,982 | | | 15,622 | |
| Employee Benefits and Pension Obligations | | | 14,714 | | | 17,729 | |
| Long-term Risk Management Liabilities | | | 25,120 | | | 13,484 | |
| Obligations Under Capital Leases | | | 2,577 | | | 2,802 | |
| Deferred Credits | | | 478 | | | 736 | |
TOTAL | | | 325,729 | | | 312,863 | |
| | | | | | | | |
| Commitments and Contingencies (Note 5) | | | | | | | |
| | | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 1,285,386 | | $ | 1,243,247 | |
See Notes to Financial Statements of Registrant Subsidiaries.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING ACTIVITIES | | | | | |
Net Income | | $ | 9,885 | | $ | 11,611 | |
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities: | | | | | | | |
| Depreciation and Amortization | | | 11,152 | | | 10,859 | |
| Deferred Income Taxes | | | 988 | | | 3,442 | |
| Deferred Investment Tax Credits | | | (292 | ) | | (292 | ) |
| Deferred Property Taxes | | | 1,628 | | | 1,581 | |
| Pension Contributions | | | (3,045 | ) | | - | |
| Pension and Postemployment Benefit Reserves | | | 30 | | | (377 | ) |
| Mark-to-Market of Risk Management Contracts | | | (3,290 | ) | | (2,135 | ) |
| Over/Under Fuel Recovery | | | (5,203 | ) | | (988 | ) |
| Loss on Sale of Assets | | | - | | | 1,051 | |
| Change in Other Noncurrent Assets | | | 94 | | | (7,219 | ) |
| Change in Other Noncurrent Liabilities | | | 4,413 | | | 8,274 | |
Changes in Components of Working Capital: | | | | | | | |
| Accounts Receivable, Net | | | (1,133 | ) | | 8,202 | |
| Fuel, Materials and Supplies | | | (873 | ) | | (2,772 | ) |
| Accounts Payable | | | 71 | | | 3,266 | |
| Taxes Accrued | | | 2,415 | | | 5,027 | |
| Customer Deposits | | | 3,400 | | | 2,564 | |
| Interest Accrued | | | 2,238 | | | 1,970 | |
| Other Current Assets | | | (2,234 | ) | | 798 | |
| Other Current Liabilities | | | (833 | ) | | (1,190 | ) |
Net Cash Flows From Operating Activities | | | 19,411 | | | 43,672 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | |
| Construction Expenditures | | | (7,341 | ) | | (7,374 | ) |
| Change in Other Cash Deposits, Net | | | (3,314 | ) | | (15 | ) |
| Proceeds from Sale of Assets | | | - | | | 1,538 | |
Net Cash Flows Used For Investing Activities | | | (10,655 | ) | | (5,851 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | |
| Issuance of Long-term Debt - Affiliated | | | - | | | 20,000 | |
| Changes in Advances to/from Affiliates, Net | | | (8,607 | ) | | (51,238 | ) |
| Dividends Paid on Common Stock | | | - | | | (6,250 | ) |
Net Cash Flows Used For Financing Activities | | | (8,607 | ) | | (37,488 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 149 | | | 333 | |
Cash and Cash Equivalents at Beginning of Period | | | 127 | | | 863 | |
Cash and Cash Equivalents at End of Period | | $ | 276 | | $ | 1,196 | |
SUPPLEMENTAL DISCLOSURE: |
| Cash paid (received) for interest net of capitalized amounts was $3,570,000 and $5,104,000 and for income taxes was $691,000 and $(833,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions in 2005 were $126,000. |
See Notes to Respective Financial Statements.
KENTUCKY POWER COMPANY
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to KPCo’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to KPCo.
| | Footnote Reference |
| | |
| Significant Accounting Matters | Note 1 |
| New Accounting Pronouncements | Note 2 |
| Rate Matters | Note 3 |
| Commitments and Contingencies | Note 5 |
| Guarantees | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Financing Activities | Note 10 |
OHIO POWER COMPANY CONSOLIDATED
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
First Quarter of 2005 Compared to First Quarter of 2004
Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)
First Quarter of 2004 Net Income | | | | | $ | 80 | |
| | | | | | | | |
Changes in Gross Margin: | | | | | | | |
| Retail Margins | | | (7 | ) | | | |
| Transmission Revenues | | | (7 | ) | | | |
| Off-system Sales | | | 5 | | | | |
Total Change in Gross Margin | | | | | | (9 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | |
| Other Operation and Maintenance | | | 5 | | | | |
| Depreciation and Amortization | | | (2 | ) | | | |
| Nonoperating Income and Expenses, Net | | | 23 | | | | |
| Interest Charges | | | 6 | | | | |
Total Change in Operating Expenses and Other | | | | | | 32 | |
| | | | | | | | |
| Income Tax Expense | | | | | | (4 | ) |
| | | | | | | | |
First Quarter of 2005 Net Income | | | | | $ | 99 | |
Net Income increased $19 million in the first quarter of 2005. The key driver of the increase was a $32 million net decrease in operating expenses and other partially offset by a $9 million decrease in gross margin.
The major components of our decrease in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
| · | Retail Margins were $7 million less than the prior period primarily due to higher fuel costs. |
| · | Margins from Transmission Revenues decreased $7 million primarily due to the loss of through and out rates as mandated by the FERC. The decrease was partially offset by an increase in unbundled transmission revenues due to the addition of SECA rates. |
| · | Margins from Off-system Sales increased $5 million primarily due to favorable optimization activity and increased sales volumes. |
Operating Expenses and Other changed between years as follows:
| · | Nonoperating Income and Expenses, Net increased $23 million primarily due to an establishment of a regulatory asset for carrying costs on environmental capital expenditures of $22 million as a result of the recent PUCO rate stabilization plan order. |
| · | Interest Charges decreased by $6 million primarily due to refinancing debt maturities and optional redemptions with lower cost debt. |
| · | Other Operation and Maintenance expenses decreased $5 million primarily due to the settlement and cancellation of the corporate owned life insurance policy of $7 million in February 2005, a decrease in administrative expenses of $4 million related to the Gavin Scrubber, the establishment of a regulatory asset for PJM administrative fees of $2 million and decreases in employee benefit expenses and administrative and support expenses offset by a $10 million increase in expense from a major ice storm in January 2005. |
Income Tax
The effective tax rates for the first quarter of 2005 and 2004 were 33.1% and 36.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in permanent differences including COLI.
Financial Condition
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as follows:
| | Moody’s | | S&P | | Fitch |
| | | | | | |
| Senior Unsecured Debt | A3 | | BBB | | BBB+ |
Cash Flow
Cash flows for the three months ended March 31, 2005 and 2004 were as follows:
| | | 2005 | | 2004 | |
| | | (in thousands) | |
Cash and cash equivalents at beginning of period | | $ | 9,300 | | $ | 7,233 | |
| Cash flows from (used for): | | | | | | | |
| Operating activities | | | 74,821 | | | 125,131 | |
| Investing activities | | | (144,208 | ) | | 2,187 | |
| Financing activities | | | 61,170 | | | (123,792 | ) |
| Net increase (decrease) in cash and cash equivalents | | | (8,217 | ) | | 3,526 | |
Cash and cash equivalents at end of period | | $ | 1,083 | | $ | 10,759 | |
Operating Activities
Our net cash flows from operating activities were $74 million for the first three months of 2005. We produced income of $99 million during the period and a noncash expense item of $74 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital primarily relates to a $73 million decrease in Taxes Accrued due to a 2004 federal income tax payment made in the first quarter of 2005.
Our net cash flows from operating activities were $125 million for the first three months of 2004. We produced income of $80 million during the period and a noncash expense item of $72 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items; none of which were significant.
Investing Activities
Our net cash flows used for investing activities for the first three months of 2005 were $144 million primarily due to Construction Expenditures and a deposit to purchase emissions allowances. Construction expenditures were focused primarily on environmental upgrades, as well as projects to improve service reliability for transmission and distribution. For the remainder of 2005, we expect our Construction Expenditures to be approximately $632 million.
Our net cash flows from investing activities for the first three months of 2004 were $2 million. The change is primarily due to a cash deposit that we used to redeem $50 million of debt in January 2004 offset by construction expenditures.
Financing Activities
Our net cash flows from financing activities during the first three months of 2005 were $61 million primarily due to increased repayment of borrowings from the AEP Utility Money Pool.
Our net cash flows used for financing activities during the first three months of 2004 were $124 million primarily due to decreased repayments of borrowings from the AEP Utility Money Pool and dividend payments on Common Stock.
Financing Activity
In January 2005, we redeemed $5 million of 5.90% Cumulative Preferred Stock Subject to Mandatory Redemption. Additionally, long-term debt issuances and retirements during the three months ended March 31, 2005 were:
Issuances
| | | Principal | | Interest | | Due |
Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Installment Purchase Contracts | | $54,500 | | Variable | | 2029 |
| Installment Purchase Contracts | | 54,500 | | Variable | | 2028 |
| Installment Purchase Contracts | | 54,500 | | Variable | | 2028 |
| Installment Purchase Contracts | | 54,500 | | Variable | | 2028 |
Retirements and Principal Payments
| | | Principal | | Interest | | Due |
Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Installment Purchase Contracts | | $51,000 | | 6.375 | | 2029 |
| Installment Purchase Contracts | | 51,000 | | 6.375 | | 2029 |
| Installment Purchase Contracts | | 40,000 | | Variable | | 2028 |
| Installment Purchase Contracts | | 40,000 | | Variable | | 2028 |
| Installment Purchase Contracts | | 18,000 | | Variable | | 2029 |
| Installment Purchase Contracts | | 18,000 | | Variable | | 2029 |
| Notes Payable | | 1,463 | | 6.81 | | 2008 |
| Notes Payable | | 3,250 | | 6.27 | | 2009 |
Liquidity
We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.
Significant Factors
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
Critical Accounting Estimates
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.
Roll-Forward of MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2004 | | $ | 47,777 | |
| (Gain) Loss from Contracts Realized/Settled During the Period (a) | | | (11,363 | ) |
| Fair Value of New Contracts When Entered During the Period (b) | | | 374 | |
| Net Option Premiums Paid/(Received) (c) | | | - | |
| Change in Fair Value Due to Valuation Methodology Changes | | | - | |
| Changes in Fair Value of Risk Management Contracts (d) | | | 9,814 | |
| Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) | | | - | |
Total MTM Risk Management Contract Net Assets | | | 46,602 | |
| Net Cash Flow Hedge Contracts (f) | | | (9,770 | ) |
| DETM Assignment (g) | | | (15,413 | ) |
Total MTM Risk Management Contract Net Assets at March 31, 2005 | | $ | 21,419 | |
| (a) | “(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005where we entered into the contractprior to 2005. |
| (b) | “Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. |
| (c) | “Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005. |
| (d) | “Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
| (e) | “Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. |
| (f) | “Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss). |
| (g) | See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report. |
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)
| | | MTM Risk Management Contracts (a) | | Cash Flow Hedges | | DETM Assignment (b) | | Total (c) | |
| Current Assets | | $ | 99,111 | | $ | 6,303 | | $ | - | | $ | 105,414 | |
| Noncurrent Assets | | | 106,219 | | | 811 | | | - | | | 107,030 | |
Total MTM Derivative Contract Assets | | | 205,330 | | | 7,114 | | | - | | | 212,444 | |
| | | | | | | | | | | | | | |
| Current Liabilities | | | (91,128 | ) | | (15,588 | ) | | (6,309 | ) | | (113,025 | ) |
| Noncurrent Liabilities | | | (67,600 | ) | | (1,296 | ) | | (9,104 | ) | | (78,000 | ) |
| | | | | | | | | | | | | |
Total MTM Derivative Contract Liabilities | (158,728 | ) | | (16,884 | ) | | (15,413 | ) | | (191,025 | ) |
| | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | | $ | 46,602 | | $ | (9,770 | ) | $ | (15,413 | ) | $ | 21,419 | |
| Assets (Liabilities) |
| (a) | Does not include Cash Flow Hedges. |
| (b) | See “Natural Gas Contracts with DETM” section in Note 17 of the 2004 Annual Report. |
| (c) | Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
| · | The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). |
| · | The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash. |
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31, 2005
(in thousands)
| | | Remainder of 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | After 2009 (c) | | Total (d) | |
Prices Actively Quoted - ExchangeTraded Contracts | | $ | (6,874 | ) | $ | 2,647 | | $ | 5,481 | | $ | - | | $ | - | | $ | - | | $ | 1,254 | |
| Prices Provided by Other ExternalSources - OTC Broker Quotes (a) | | | 16,284 | | | 11,207 | | | 10,584 | | | 4,544 | | | - | | | - | | | 42,619 | |
Prices Based on Models and OtherValuation Methods (b) | | | (508 | ) | | (7,876 | ) | | (5,324 | ) | | 3,759 | | | 6,716 | | | 5,962 | | | 2,729 | |
Total | | $ | 8,902 | | $ | 5,978 | | $ | 10,741 | | $ | 8,303 | | $ | 6,716 | | $ | 5,962 | | $ | 46,602 | |
| (a) | “Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. |
| (b) | “Prices Based on Models and Other Valuation Methods” is in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market. |
| (c) | There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $5.7 million of this mark-to-market value is in 2010. |
| (d) | Amounts exclude Cash Flow Hedges. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)
| | | Power | | Foreign Currency | | Total | |
Beginning Balance December 31, 2004 | | $ | 1,599 | | $ | (358 | ) | $ | 1,241 | |
| Changes in Fair Value (a) | | | (5,476 | ) | | - | | | (5,476 | ) |
| Reclassifications from AOCI to NetIncome (b) | | | (2,463 | ) | | 3 | | | (2,460 | ) |
Ending Balance March 31, 2005 | | $ | (6,340 | ) | $ | (355 | ) | $ | (6,695 | ) |
| (a) | “Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes. |
| (b) | “Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $6,040 thousand loss.
Credit Risk
Our counterparty credit quality and exposure is generally consistent with that of AEP.
VaR Associated with Risk Management Contracts
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
| | Three Months Ended | | Twelve Months Ended | |
| | March 31, 2005 | | December 31, 2004 | |
| | (in thousands) | | (in thousands) | |
| | End | | High | | Average | | Low | | End | | High | | Average | | Low | |
| | $449 | | $994 | | $488 | | $294 | | $464 | | $1,513 | | $652 | | $223 | |
VaR Associated with Debt Outstanding
The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $155 million and $146 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING REVENUES | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 456,231 | | $ | 443,729 | |
| Sales to AEP Affiliates | | | 151,839 | | | 146,488 | |
TOTAL | | | 608,070 | | | 590,217 | |
| | | | | | | | |
OPERATING EXPENSES | | | | | | | |
| Fuel for Electric Generation | | | 180,261 | | | 166,271 | |
| Purchased Electricity for Resale | | | 18,762 | | | 12,183 | |
| Purchased Electricity from AEP Affiliates | | | 25,618 | | | 19,303 | |
| Other Operation | | | 73,783 | | | 91,096 | |
| Maintenance | | | 45,755 | | | 34,051 | |
| Depreciation and Amortization | | | 73,947 | | | 71,782 | |
| Taxes Other Than Income Taxes | | | 47,142 | | | 47,190 | |
| Income Taxes | | | 38,571 | | | 39,982 | |
TOTAL | | | 503,839 | | | 481,858 | |
| | | | | | | | |
OPERATING INCOME | | | 104,231 | | | 108,359 | |
| | | | | | | | |
| Nonoperating Income | | | 54,972 | | | 16,751 | |
| Carrying Costs Income | | | 22,037 | | | 179 | |
| Nonoperating Expenses | | | 45,027 | | | 8,069 | |
| Nonoperating Income Tax Expense | | | 10,567 | | | 5,087 | |
| Interest Charges | | | 26,163 | | | 31,969 | |
| | | | | | | | |
NET INCOME | | | 99,483 | | | 80,164 | |
| | | | | | | | |
| Preferred Stock Dividend Requirements | | | 183 | | | 183 | |
| | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 99,300 | | $ | 79,981 | |
The common stock of OPCo is wholly-owned by AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
DECEMBER 31, 2003 | | $ | 321,201 | | $ | 462,484 | | $ | 729,147 | | $ | (48,807 | ) | $ | 1,464,025 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (57,057 | ) | | | | | (57,057 | ) |
| Preferred Stock Dividends | | | | | | | | | (183 | ) | | | | | (183 | ) |
TOTAL | | | | | | | | | | | | | | | 1,406,785 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $1,358 | | | | | | | | | | | | (2,522 | ) | | (2,522 | ) |
| Minimum Pension Liability, Net of Tax of $2,123 | | | | | | | | | | | | (3,942 | ) | | (3,942 | ) |
NET INCOME | | | | | | | | | 80,164 | | | | | | 80,164 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 73,700 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2004 | | $ | 321,201 | | $ | 462,484 | | $ | 752,071 | | $ | (55,271 | ) | $ | 1,480,485 | |
| | | | | | | | | | | | | | | | | |
DECEMBER 31, 2004 | | $ | 321,201 | | $ | 462,485 | | $ | 764,416 | | $ | (74,264 | ) | $ | 1,473,838 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (7,500 | ) | | | | | (7,500 | ) |
| Preferred Stock Dividends | | | | | | | | | (183 | ) | | | | | (183 | ) |
TOTAL | | | | | | | | | | | | | | | 1,466,155 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $4,273 | | | | | | | | | | | | (7,936 | ) | | (7,936 | ) |
NET INCOME | | | | | | | | | 99,483 | | | | | | 99,483 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 91,547 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2005 | | $ | 321,201 | | $ | 462,485 | | $ | 856,216 | | $ | (82,200 | ) | $ | 1,557,702 | |
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
ELECTRIC UTILITY PLANT | | | | | |
| Production | | $ | 4,137,431 | | $ | 4,127,284 | |
| Transmission | | | 984,702 | | | 978,492 | |
| Distribution | | | 1,213,373 | | | 1,202,550 | |
| General | | | 242,690 | | | 248,749 | |
| Construction Work in Progress | | | 329,393 | | | 240,957 | |
Total | | | 6,907,589 | | | 6,798,032 | |
| Accumulated Depreciation and Amortization | | | 2,641,778 | | | 2,617,238 | |
TOTAL - NET | | | 4,265,811 | | | 4,180,794 | |
| | | | | | | | |
OTHER PROPERTY AND INVESTMENTS | | | | | | | |
| Nonutility Property, Net | | | 44,743 | | | 44,774 | |
| Other | | | 8,901 | | | 13,409 | |
TOTAL | | | 53,644 | | | 58,183 | |
| | | | | | | | |
CURRENT ASSETS | | | | | | | |
| Cash and Cash Equivalents | | | 1,083 | | | 9,300 | |
| Other Cash Deposits | | | 9,986 | | | 37 | |
| Advances to Affiliates | | | 41,407 | | | 125,971 | |
| Accounts Receivable: | | | | | | | |
| Customers | | | 112,135 | | | 109,592 | |
| Affiliated Companies | | | 147,532 | | | 144,175 | |
| Miscellaneous | | | 27,144 | | | 7,626 | |
| Allowance for Uncollectible Accounts | | | (37 | ) | | (93 | ) |
| Fuel | | | 69,506 | | | 70,309 | |
| Materials and Supplies | | | 56,855 | | | 55,569 | |
| Emissions Allowances | | | 48,097 | | | 95,303 | |
| Risk Management Assets | | | 105,414 | | | 79,541 | |
| Margin Deposits | | | 11,926 | | | 7,056 | |
| Prepayments and Other | | | 16,598 | | | 10,492 | |
TOTAL | | | 647,646 | | | 714,878 | |
| | | | | | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | | | | |
| Regulatory Assets: | | | | | | | |
| SFAS 109 Regulatory Asset, Net | | | 171,688 | | | 169,866 | |
| Transition Regulatory Assets | | | 202,908 | | | 225,273 | |
| Unamortized Loss on Reacquired Debt | | | 10,866 | | | 11,046 | |
| Other | | | 65,433 | | | 22,189 | |
| Long-term Risk Management Assets | | | 107,030 | | | 66,727 | |
| Deferred Property Taxes | | | 54,556 | | | 70,214 | |
| Deferred Charges and Other Assets | | | 63,973 | | | 74,095 | |
TOTAL | | | 676,454 | | | 639,410 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 5,643,555 | | $ | 5,593,265 | |
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)
| | | 2005 | | 2004 | |
CAPITALIZATION | | (in thousands) | |
| Common Shareholder’s Equity | | | | | | | |
| Common Stock - No par value: | | | | | | | |
| Authorized - 40,000,000 shares | | | | | | | |
| Outstanding - 27,952,473 shares | | $ | 321,201 | | $ | 321,201 | |
| Paid-in Capital | | | 462,485 | | | 462,485 | |
| Retained Earnings | | | 856,216 | | | 764,416 | |
| Accumulated Other Comprehensive Income (Loss) | | | (82,200 | ) | | (74,264 | ) |
Total Common Shareholder’s Equity | | | 1,557,702 | | | 1,473,838 | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 16,641 | | | 16,641 | |
Total Shareholders’ Equity | | | 1,574,343 | | | 1,490,479 | |
| Long-term Debt: | | | | | | | |
| Nonaffiliated | | | 1,594,364 | | | 1,598,706 | |
| Affiliated | | | 400,000 | | | 400,000 | |
Total Long-term Debt | | | 1,994,364 | | | 1,998,706 | |
TOTAL | | | 3,568,707 | | | 3,489,185 | |
| | | | | | | | |
| Minority Interest | | | 13,475 | | | 14,083 | |
| | | | | | | | |
CURRENT LIABILITIES | | | | | | | |
| Short-term Debt - Nonaffiliated | | | 18,702 | | | 23,498 | |
| Long-term Debt Due Within One Year - Nonaffiliated | | | 12,354 | | | 12,354 | |
| Cumulative Preferred Stock Subject to Mandatory Redemption | | | - | | | 5,000 | |
| Accounts Payable: | | | | | | | |
| General | | | 190,301 | | | 143,247 | |
| Affiliated Companies | | | 60,079 | | | 116,615 | |
| Customer Deposits | | | 30,991 | | | 22,620 | |
| Taxes Accrued | | | 159,776 | | | 233,026 | |
| Interest Accrued | | | 23,045 | | | 39,254 | |
| Risk Management Liabilities | | | 113,025 | | | 70,311 | |
| Obligations Under Capital Leases | | | 8,806 | | | 9,081 | |
| Other | | | 71,539 | | | 74,977 | |
TOTAL | | | 688,618 | | | 749,983 | |
| | | | | | | | |
DEFERRED CREDITS AND OTHER LIABILITIES | | | | | | | |
| Deferred Income Taxes | | | 945,105 | | | 943,465 | |
| Regulatory Liabilities: | | | | | | | |
| Asset Removal Costs | | | 105,503 | | | 102,875 | |
| Deferred Investment Tax Credits | | | 12,290 | | | 12,539 | |
| Long-term Risk Management Liabilities | | | 78,000 | | | 46,261 | |
| Deferred Credits | | | 43,280 | | | 24,377 | |
| Employee Benefits and Pension Obligations | | | 106,201 | | | 126,825 | |
| Obligations Under Capital Leases | | | 29,867 | | | 31,652 | |
| Asset Retirement Obligations | | | 46,494 | | | 45,606 | |
| Other | | | 6,015 | | | 6,414 | |
TOTAL | | | 1,372,755 | | | 1,340,014 | |
| Commitments and Contingencies (Note 5) | | | | | | | |
| | | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 5,643,555 | | $ | 5,593,265 | |
See Notes to Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING ACTIVITIES | | | | | |
Net Income | | $ | 99,483 | | $ | 80,164 | |
Adjustments to Reconcile Net Income to Net Cash FlowsFrom Operating Activities: | | | | | | | |
| Depreciation and Amortization | | | 73,947 | | | 71,782 | |
| Deferred Income Taxes | | | 4,092 | | | 7,701 | |
| Deferred Investment Tax Credits | | | (249 | ) | | (761 | ) |
| Deferred Property Taxes | | | 15,658 | | | 14,745 | |
| Pension and Postemployment Benefit Reserves | | | (617 | ) | | 4,160 | |
| Mark-to-Market of Risk Management Contracts | | | (2,477 | ) | | (5,729 | ) |
| Pension Contributions | | | (20,007 | ) | | - | |
| Carrying Costs Income | | | (22,037 | ) | | (179 | ) |
| Change in Other Noncurrent Assets | | | (12,780 | ) | | (11,116 | ) |
| Change in Other Noncurrent Liabilities | | | 19,811 | | | (2,682 | ) |
Changes in Components of Working Capital: | | | | | | | |
| Accounts Receivable, Net | | | (25,474 | ) | | (13,886 | ) |
| Fuel, Materials and Supplies | | | (483 | ) | | 2,743 | |
| Accounts Payable | | | (9,482 | ) | | (21,674 | ) |
| Taxes Accrued | | | (73,250 | ) | | 18,336 | |
| Customer Deposits | | | 8,371 | | | 10,280 | |
| Interest Accrued | | | (16,209 | ) | | (16,934 | ) |
| Other Current Assets | | | 40,237 | | | 618 | |
| Other Current Liabilities | | | (3,713 | ) | | (12,437 | ) |
Net Cash Flows From Operating Activities | | | 74,821 | | | 125,131 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | |
| Construction Expenditures | | | (134,848 | ) | | (49,868 | ) |
| Change in Other Cash Deposits, Net | | | (9,949 | ) | | 50,953 | |
| Proceeds from Sale of Assets | | | 589 | | | 1,102 | |
Net Cash Flows From (Used For) Investing Activities | | | (144,208 | ) | | 2,187 | |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | |
| Change in Short-term Debt, Net | | | (4,796 | ) | | 631 | |
| Issuance of Long-term Debt | | | 216,798 | | | - | |
| Issuance of Long-term Debt- Affiliated | | | - | | | 200,000 | |
| Retirement of Long-term Debt- Nonaffiliated | | | (222,713 | ) | | (192,963 | ) |
| Retirement of Cumulative Preferred Stock | | | (5,000 | ) | | (2,250 | ) |
| Changes in Advances to/from Affiliates, Net | | | 84,564 | | | (71,970 | ) |
| Dividends Paid on Common Stock | | | (7,500 | ) | | (57,057 | ) |
| Dividends Paid on Cumulative Preferred Stock | | | (183 | ) | | (183 | ) |
Net Cash Flows From (Used For) Financing Activities | | | 61,170 | | | (123,792 | ) |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (8,217 | ) | | 3,526 | |
Cash and Cash Equivalents at Beginning of Period | | | 9,300 | | | 7,233 | |
Cash and Cash Equivalents at End of Period | | $ | 1,083 | | $ | 10,759 | |
SUPPLEMENTAL DISCLOSURE: |
| Cash paid (received) for interest net of capitalized amounts was $37,519,000 and $46,636,000 and for income taxes was $87,763,000 and $(8,644,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $555,000 and $0 in 2005 and 2004, respectively. |
See Notes to Respective Financial Statements.
OHIO POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to OPCo’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to OPCo.
| | Footnote Reference |
| | |
| Significant Accounting Matters | Note 1 |
| New Accounting Pronouncements | Note 2 |
| Rate Matters | Note 3 |
| Customer Choice and Industry Restructuring | Note 4 |
| Commitments and Contingencies | Note 5 |
| Guarantees | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Financing Activities | Note 10 |
PUBLIC SERVICE COMPANY OF OKLAHOMA
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
First Quarter of 2005 Compared to First Quarter of 2004
Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)
First Quarter of 2004 Net Income | | | | | $ | (9 | ) |
| | | | | | | | |
Changes in Gross Margin: | | | | | | | |
| Retail Margins | | | (4 | ) | | | |
| Off-system Sales | | | 3 | | | | |
Total Change in Gross Margin | | | | | | (1 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | |
| Other Operation and Maintenance | | | 15 | | | | |
| Depreciation and Amortization | | | (1 | ) | | | |
| Interest Charges | | | 2 | | | | |
Total Change in Operating Expenses and Other | | | | | | 16 | |
| | | | | | | | |
| Income Tax Expense | | | | | | (6 | ) |
| | | | | | | | |
First Quarter of 2005 Net Income | | | | | $ | - | |
Net Income increased $9 million in the first quarter of 2005. The key drivers of the increase were a $16 million decrease in operating expenses and other partially offset by a $6 million increase in income taxes and a $1 million decrease in gross margin. Fluctuations occurring in retail fuel revenues generally do not impact operating income, as they are offset in the retail portion of fuel and purchased power expense due to the functioning of the fuel adjustment clause in Oklahoma.
The major components of our decrease in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
| · | Retail Margins decreased by $4 million in comparison to 2004primarily due to a $1 million decrease in retail sales due to slightly lower volumes and a $2 million decrease in net fuel revenue/fuel expense. |
| · | Margins from Off-system Sales for 2005 increased by $3 million in comparison to 2004 primarily due to higher sales volumes of approximately 9% as well as higher optimization activity. |
Operating Expenses and Other decreased between years as follows:
| · | Other Operation and Maintenance expenses decreased $15 million. Transmission related expenses decreased $6 million primarily due to a prior year unfavorable adjustment for affiliated OATT and ancillary services resulting from revised ERCOT data for the years 2001 through 2003 of approximately $5 million. Distribution expenses decreased $2 million resulting primarily from a 2004 labor settlement. Administrative and general expenses decreased approximately $6 million due to lower outside service and employee related expenses, while customer related expenses increased $1 million. Maintenance expenses decreased $2 million primarily due to higher 2004 cost of scheduled plant maintenance offset in part by increased maintenance of overhead lines. |
| · | Interest Charges decreased $2 million primarily due to the retirement of higher rate First Mortgage Bonds replaced by lower rate Senior Unsecured Notes and the retirement of Trust Preferred Securities in 2004. |
Income Taxes
The effective tax rates for the first quarter of 2005 and 2004 were 184.9% and 46.2%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The increase in the effective tax rate from the comparative period is primarily due to higher pre-tax income in 2005 and federal income tax adjustments.
Financial Condition
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as follows:
| | Moody’s | | S&P | | Fitch |
| | | | | | |
| First Mortgage Bonds | A3 | | A- | | A |
| Senior Unsecured Debt | Baa1 | | BBB | | A- |
Financing Activity
There were no long-term debt issuances or retirements during the first three months of 2005.
Liquidity
We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.
Significant Factors
Oklahoma Regulatory Activity
PSO Rate Review
We are involved in a commission staff-initiated rate review before the OCC seeking to increase our base rates, while various other parties made recommendations to reduce our base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. Pending approval by the OCC, the settlement provides for a $7 million base rate reduction partially offset by a $6 million reduction in annual depreciation expense. The settlement also provides for recovery of $9 million of deferred fuel and the continuation of the vegetation management rider. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. Finally, the settlement stipulates that we may not file for a base rate increase before April 1, 2006. The OCC did not approve the settlement in time for implementation of new base rates in May 2005 as agreed to by the parties, which voids the settlement. The OCC issued an Order approving the stipulation on May 2, 2005 with one exception. The Order approves the implementation of new base rates in June 2005 versus the stipulation date of May 2005.
PSO Fuel and Purchased Power
In 2002, we experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, we submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending we recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of our 2001 fuel and purchased power practices.
In the proceeding, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and AEP West companies should have received more margins. The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. Using the intervenors’ method, we estimate that the increase in margins would be $29 million through March 31, 2005. In April 2005, the OCC heard arguments from intervenors that requested the OCC to conduct a prudence review of our fuel and purchased power for 2003. We are unable to predict if the OCC will order a prudence review of our fuel and purchased power activities for 2003 or the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
Critical Accounting Estimates
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.
MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2004 | | $ | 14,771 | |
| (Gain) Loss from Contracts Realized/Settled During the Period (a) | | | 115 | |
| Fair Value of New Contracts When Entered During the Period (b) | | | - | |
| Net Option Premiums Paid/(Received) (c) | | | - | |
| Change in Fair Value Due to Valuation Methodology Changes | | | - | |
| Changes in Fair Value of Risk Management Contracts (d) | | | - | |
| Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) | | | (10,588 | ) |
Total MTM Risk Management Contract Net Assets | | | 4,298 | |
| Net Cash Flow Hedge Contracts (f) | | | (913 | ) |
Total MTM Risk Management Contract Net Assets at March 31, 2005 | | $ | 3,385 | |
| (a) | “(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005where we entered into the contractprior to 2005. |
| (b) | “Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. |
| (c) | “Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005. |
| (d) | “Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
| (e) | “Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. |
| (f) | “Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss). |
Reconciliation of MTM Risk Management Contracts to
Balance Sheets
As of March 31, 2005
(in thousands)
| | | MTM Risk Management Contracts (a) | | Cash Flow Hedges | | Total (b) | |
| Current Assets | | $ | 7,540 | | $ | 908 | | $ | 8,448 | |
| Noncurrent Assets | | | 6,510 | | | 70 | | | 6,580 | |
Total MTM Derivative Contract Assets | | | 14,050 | | | 978 | | | 15,028 | |
| | | | | | | | | | | |
| Current Liabilities | | | (6,692 | ) | | (1,716 | ) | | (8,408 | ) |
| Noncurrent Liabilities | | | (3,060 | ) | | (175 | ) | | (3,235 | ) |
Total MTM Derivative Contract Liabilities | | | (9,752 | ) | | (1,891 | ) | | (11,643 | ) |
| | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 4,298 | | $ | (913 | ) | $ | 3,385 | |
| (a) | Does not include Cash Flow Hedges. |
| (b) | Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
| · | The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). |
| · | The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash. |
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31, 2005
(in thousands)
| | | Remainder of 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | After 2009 | | Total (c) | |
Prices Actively Quoted - ExchangeTraded Contracts | | $ | (927 | ) | $ | 357 | | $ | 739 | | $ | - | | $ | - | | $ | - | | $ | 169 | |
| Prices Provided by Other ExternalSources - OTC BrokerQuotes (a) | | | 1,804 | | | 1,532 | | | 1,127 | | | 483 | | | - | | | - | | | 4,946 | |
Prices Based on Models and OtherValuation Methods (b) | | | 21 | | | (1,302 | ) | | (1,086 | ) | | 263 | | | 580 | | | 707 | | | (817 | ) |
Total | | $ | 898 | | $ | 587 | | $ | 780 | | $ | 746 | | $ | 580 | | $ | 707 | | $ | 4,298 | |
| (a) | “Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. |
| (b) | “Prices Based on Models and Other Valuation Methods” is in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market. |
| (c) | Amounts exclude Cash Flow Hedges. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
We employ the use of interest rate forward transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)
| | | Power | | Interest Rate | | Total | |
Beginning Balance December 31, 2004 | | $ | 1,000 | | $ | (600 | ) | $ | 400 | |
| Changes in Fair Value (a) | | | (1,570 | ) | | 945 | | | (625 | ) |
Reclassifications from AOCI to Net Income (b) | | | (368 | ) | | - | | | (368 | ) |
Ending Balance March 31, 2005 | | $ | (938 | ) | $ | 345 | | $ | (593 | ) |
| (a) | “Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes. |
| (b) | “Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes. |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $810 thousand loss.
Credit Risk
Our counterparty credit quality and exposure is generally consistent with that of AEP.
VaR Associated with Risk Management Contracts
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
| | Three Months Ended | | Twelve Months Ended | |
| | March 31, 2005 | | December 31, 2004 | |
| | (in thousands) | | (in thousands) | |
| | End | | High | | Average | | Low | | End | | High | | Average | | Low | |
| | $61 | | $134 | | $66 | | $40 | | $238 | | $778 | | $335 | | $115 | |
VaR Associated with Debt Outstanding
The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $40 million and $35 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or financial position.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING REVENUES | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 250,368 | | $ | 204,043 | |
| Sales to AEP Affiliates | | | 2,632 | | | 3,142 | |
TOTAL | | | 253,000 | | | 207,185 | |
| | | | | | | | |
OPERATING EXPENSES | | | | | | | |
| Fuel for Electric Generation | | | 134,171 | | | 89,085 | |
| Purchased Electricity for Resale | | | 14,793 | | | 9,168 | |
| Purchased Electricity from AEP Affiliates | | | 22,845 | | | 26,899 | |
| Other Operation | | | 30,185 | | | 43,395 | |
| Maintenance | | | 11,359 | | | 13,122 | |
| Depreciation and Amortization | | | 22,619 | | | 22,176 | |
| Taxes Other Than Income Taxes | | | 9,677 | | | 9,817 | |
| Income Taxes (Credits) | | | (852 | ) | | (7,333 | ) |
TOTAL | | | 244,797 | | | 206,329 | |
| | | | | | | | |
OPERATING INCOME | | | 8,203 | | | 856 | |
| | | | | | | | |
| Nonoperating Income | | | 478 | | | 244 | |
| Nonoperating Expenses | | | 551 | | | 542 | |
| Nonoperating Income Tax Credit | | | 250 | | | 392 | |
| Interest Charges | | | 7,875 | | | 9,953 | |
| | | | | | | | |
NET INCOME (LOSS) | | | 505 | | | (9,003 | ) |
| | | | | | | | |
| Preferred Stock Dividend Requirements | | | 53 | | | 53 | |
| | | | | | | | |
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK | | $ | 452 | | $ | (9,056 | ) |
The common stock of PSO is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
DECEMBER 31, 2003 | | $ | 157,230 | | $ | 230,016 | | $ | 139,604 | | $ | (43,842 | ) | $ | 483,008 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (8,750 | ) | | | | | (8,750 | ) |
| Preferred Stock Dividends | | | | | | | | | (53 | ) | | | | | (53 | ) |
TOTAL | | | | | | | | | | | | | | | 474,205 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE LOSS | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $239 | | | | | | | | | | | | (444 | ) | | (444 | ) |
NET LOSS | | | | | | | | | (9,003 | ) | | | | | (9,003 | ) |
TOTAL COMPREHENSIVE LOSS | | | | | | | | | | | | | | | (9,447 | ) |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2004 | | $ | 157,230 | | $ | 230,016 | | $ | 121,798 | | $ | (44,286 | ) | $ | 464,758 | |
| | | | | | | | | | | | | | | | | |
DECEMBER 31, 2004 | | $ | 157,230 | | $ | 230,016 | | $ | 141,935 | | $ | 75 | | $ | 529,256 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (8,500 | ) | | | | | (8,500 | ) |
| Preferred Stock Dividends | | | | | | | | | (53 | ) | | | | | (53 | ) |
TOTAL | | | | | | | | | | | | | | | 520,703 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE LOSS | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $534 | | | | | | | | | | | | (993 | ) | | (993 | ) |
NET INCOME | | | | | | | | | 505 | | | | | | 505 | |
TOTAL COMPREHENSIVE LOSS | | | | | | | | | | | | | | | (488 | ) |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2005 | | $ | 157,230 | | $ | 230,016 | | $ | 133,887 | | $ | (918 | ) | $ | 520,215 | |
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
ELECTRIC UTILITY PLANT | | | |
| Production | | $ | 1,068,205 | | $ | 1,072,022 | |
| Transmission | | | 467,953 | | | 468,735 | |
| Distribution | | | 1,100,348 | | | 1,089,187 | |
| General | | | 201,397 | | | 200,044 | |
| Construction Work in Progress | | | 47,129 | | | 41,028 | |
Total | | | 2,885,032 | | | 2,871,016 | |
| Accumulated Depreciation and Amortization | | | 1,126,729 | | | 1,117,113 | |
TOTAL - NET | | | 1,758,303 | | | 1,753,903 | |
| | | | | | | | |
OTHER PROPERTY AND INVESTMENTS | | | | | | | |
| Nonutility Property, Net | | | 4,636 | | | 4,401 | |
| Other Investments | | | - | | | 81 | |
TOTAL | | | 4,636 | | | 4,482 | |
| | | | | | | | |
CURRENT ASSETS | | | | | | | |
| Cash and Cash Equivalents | | | 642 | | | 91 | |
| Other Cash Deposits | | | 156 | | | 188 | |
| Accounts Receivable: | | | | | | | |
| Customers | | | 31,319 | | | 34,002 | |
| Affiliated Companies | | | 31,288 | | | 46,399 | |
| Miscellaneous | | | 8,747 | | | 6,984 | |
| Allowance for Uncollectible Accounts | | | - | | | (76 | ) |
| Fuel Inventory | | | 14,674 | | | 14,268 | |
| Materials and Supplies | | | 37,950 | | | 35,485 | |
| Risk Management Assets | | | 8,448 | | | 21,388 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | | - | | | 366 | |
| Margin Deposits | | | 1,388 | | | 2,881 | |
| Prepayments and Other | | | 2,532 | | | 1,378 | |
TOTAL | | | 137,144 | | | 163,354 | |
| | | | | | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | | | | |
| Regulatory Assets: | | | | | | | |
| Unamortized Loss on Reacquired Debt | | | 14,143 | | | 14,705 | |
| Other | | | 16,401 | | | 17,246 | |
| Long-term Risk Management Assets | | | 6,580 | | | 14,477 | |
| Prepaid Pension Obligations | | | 82,466 | | | 82,419 | |
| Deferred Charges and Other Assets | | | 39,958 | | | 18,232 | |
TOTAL | | | 159,548 | | | 147,079 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 2,059,631 | | $ | 2,068,818 | |
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)
| | | 2005 | | 2004 | |
CAPITALIZATION | | (in thousands) | |
| Common Shareholder’s Equity: | | | | | | | |
| Common Stock - $15 par value per share: | | | | | | | |
| Authorized - 11,000,000 shares | | | | | | | |
| Issued - 10,482,000 shares | | | | | | | |
| Outstanding - 9,013,000 shares | | $ | 157,230 | | $ | 157,230 | |
| Paid-in Capital | | | 230,016 | | | 230,016 | |
| Retained Earnings | | | 133,887 | | | 141,935 | |
| Accumulated Other Comprehensive Income (Loss) | | | (918 | ) | | 75 | |
Total Common Shareholder’s Equity | | | 520,215 | | | 529,256 | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 5,262 | | | 5,262 | |
Total Shareholders’ Equity | | | 525,477 | | | 534,518 | |
| Long-term Debt: | | | | | | | |
| Nonaffiliated | | | 446,121 | | | 446,092 | |
| Affiliated | | | 50,000 | | | 50,000 | |
Total Long-term Debt | | | 496,121 | | | 496,092 | |
TOTAL | | | 1,021,598 | | | 1,030,610 | |
CURRENT LIABILITIES | | | | | | | |
| Long-term Debt Due Within One Year - Nonaffiliated | | | 50,000 | | | 50,000 | |
| Advances from Affiliates | | | 39,588 | | | 55,002 | |
| Accounts Payable: | | | | | | | |
| General | | | 66,278 | | | 71,442 | |
| Affiliated Companies | | | 53,755 | | | 58,632 | |
| Customer Deposits | | | 33,867 | | | 33,757 | |
| Taxes Accrued | | | 33,817 | | | 18,835 | |
| Interest Accrued | | | 2,725 | | | 4,023 | |
| Risk Management Liabilities | | | 8,408 | | | 13,705 | |
| Regulatory Liability for Over-Recovered Fuel Costs | | | 40,529 | | | - | |
| Obligations Under Capital Leases | | | 603 | | | 537 | |
| Other | | | 18,449 | | | 30,477 | |
TOTAL | | | 348,019 | | | 336,410 | |
| | | | | | | | |
DEFERRED CREDITS AND OTHER LIABILITIES | | | | | | | |
| Deferred Income Taxes | | �� | 386,293 | | | 384,090 | |
| Long-term Risk Management Liabilities | | | 3,235 | | | 7,455 | |
| Regulatory Liabilities: | | | | | | | |
| Asset Removal Costs | | | 225,316 | | | 220,298 | |
| Deferred Investment Tax Credits | | | 28,172 | | | 28,620 | |
| SFAS 109 Regulatory Liability, Net | | | 21,351 | | | 21,963 | |
| Unrealized Gain on Forward Commitments | | | 7,339 | | | 19,676 | |
| Obligations Under Capital Leases | | | 1,086 | | | 747 | |
| Deferred Credits and Other | | | 17,222 | | | 18,949 | |
TOTAL | | | 690,014 | | | 701,798 | |
| | | | | | | | |
| Commitments and Contingencies (Note 5) | | | | | | | |
| | | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 2,059,631 | | $ | 2,068,818 | |
See Notes to Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING ACTIVITIES | | | | | |
Net Income (Loss) | | $ | 505 | | $ | (9,003 | ) |
Adjustments to Reconcile Net Income to Net Cash FlowsFrom Operating Activities: | | | | | | | |
| Depreciation and Amortization | | | 22,619 | | | 22,176 | |
| Deferred Property Taxes | | | (24,368 | ) | | (25,943 | ) |
| Deferred Income Taxes | | | 2,126 | | | (489 | ) |
| Deferred Investment Tax Credits | | | (448 | ) | | (448 | ) |
| Mark-to-Market of Risk Management Contracts | | | 10,473 | | | 10,029 | |
| Fuel Recovery | | | 40,895 | | | 4,398 | |
| Change in Other Noncurrent Assets | | | (4,964 | ) | | (1,664 | ) |
| Change in Other Noncurrent Liabilities | | | (9,279 | ) | | (7,768 | ) |
Changes in Components of Working Capital: | | | | | | | |
| Accounts Receivable, Net | | | 15,955 | | | 4,054 | |
| Fuel, Materials and Supplies | | | (2,871 | ) | | 635 | |
| Accounts Payable | | | (10,041 | ) | | (7,740 | ) |
| Taxes Accrued | | | 14,982 | | | 17,424 | |
| Customer Deposits | | | 110 | | | 2,357 | |
| Interest Accrued | | | (1,298 | ) | | 32 | |
| Other Current Assets | | | 2,285 | | | (576 | ) |
| Other Current Liabilities | | | (11,964 | ) | | (4,562 | ) |
Net Cash Flows From Operating Activities | | | 44,717 | | | 2,912 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | |
| Construction Expenditures | | | (20,231 | ) | | (14,471 | ) |
| Change in Other Cash Deposits, Net | | | 32 | | | 3,688 | |
| Proceeds from Sale of Assets | | | - | | | 244 | |
Net Cash Flows Used For Investing Activities | | | (20,199 | ) | | (10,539 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | |
| Changes in Advances to/from Affiliates, Net | | | (15,414 | ) | | 14,778 | |
| Dividends Paid on Common Stock | | | (8,500 | ) | | (8,750 | ) |
| Dividends Paid on Cumulative Preferred Stock | | | (53 | ) | | (53 | ) |
Net Cash Flows From (Used For) Financing Activities | | | (23,967 | ) | | 5,975 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 551 | | | (1,652 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 91 | | | 3,738 | |
Cash and Cash Equivalents at End of Period | | $ | 642 | | $ | 2,086 | |
SUPPLEMENTAL DISCLOSURE: |
| Cash paid (received) for interest net of capitalized amounts was $7,806,000 and $8,951,000 and for income taxes was $(1,366,000) and $(2,695,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $551,000 and $141,000 in 2005 and 2004, respectively. |
See Notes to Respective Financial Statements.
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to PSO’s financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to PSO.
| | Footnote Reference |
| | |
| Significant Accounting Matters | Note 1 |
| New Accounting Pronouncements | Note 2 |
| Rate Matters | Note 3 |
| Commitments and Contingencies | Note 5 |
| Guarantees | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Financing Activities | Note 10 |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
First Quarter of 2005 Compared to First Quarter of 2004
Reconciliation of First Quarter of 2004 to First Quarter of 2005 Net Income
(in millions)
First Quarter of 2004 Net Income | | | | | $ | 5 | |
| | | | | | | | |
Changes in Gross Margin: | | | | | | | |
| Retail Margins* | | | 3 | | | | |
| Off-system Sales | | | (1 | ) | | | |
| Other Revenues | | | 1 | | | | |
Total Change in Gross Margin | | | | | | 3 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | |
| Other Operation and Maintenance | | | 5 | | | | |
| Depreciation and Amortization | | | (1 | ) | | | |
| Taxes Other Than Income Taxes | | | 1 | | | | |
| Interest Charges | | | 3 | | | | |
Total Change in Operating Expenses and Other: | | | | | | 8 | |
| | | | | | | | |
| Income Tax Expense | | | | | | (4 | ) |
| | | | | | | | |
First Quarter of 2005 Net Income | | | | | $ | 12 | |
| * | Includes firm wholesale sales to municipals and cooperatives. |
Net Income increased $7 million to $12 million in the first quarter of 2005. The key drivers of the increase were a $3 million increase in gross margin and an $8 million net decrease in operating expenses and other partially offset by a $4 million increase in income taxes.
The major components of our change in gross margin, defined as revenues net of related fuel and purchased power, were as follows:
| · | Retail Margins increased $3 million in comparison to 2004primarily due to a $1 million increase in retail sales due to slightly higher volumes and a $2 million increase in net fuel revenue/fuel expense. |
| · | Margins from Off-system Sales decreased $1 million in comparison to 2004 primarily due to lower optimization activity. |
Operating Expenses and Other changed between years as follows:
| · | Other Operation and Maintenance expenses decreased $5 million. Transmission related expenses decreased $6 million primarily due to a prior year unfavorable adjustment for affiliated OATT and ancillary services resulting from revised ERCOT data for the years 2001 through 2003, offset in part by $1 million of higher production plant related expenses. |
| · | Taxes Other Than Income Taxes decreased $1 million primarily due to property related taxes and state franchise taxes. |
| · | Interest Charges decreased $3 million primarily due to refinancing higher interest rate debt with lower interest rate debt. |
Income Taxes
The effective tax rates for the first quarter of 2005 and 2004 were 26.5% and (4.7%), respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The increase in the effective tax rate for the comparative period is primarily due to higher pretax income in 2005 and federal income tax adjustments.
Financial Condition
Credit Ratings
The rating agencies currently have us on stable outlook. Current ratings are as follows:
| | Moody’s | | S&P | | Fitch |
| | | | | | |
| First Mortgage Bonds | A3 | | A- | | A |
| Senior Unsecured Debt | Baa1 | | BBB | | A- |
Cash Flow
Cash flows for the three months ended March 31, 2005 and 2004 were as follows:
| | | 2005 | | 2004 | |
| | | (in thousands) | |
Cash and cash equivalents at beginning of period | | $ | 2,308 | | $ | 5,676 | |
| Cash flows from (used for): | | | | | | | |
| Operating activities | | | 53,866 | | | 16,892 | |
| Investing activities | | | (33,260 | ) | | (72,298 | ) |
| Financing activities | | | (15,941 | ) | | 56,959 | |
| Net increase in cash and cash equivalents | | | 4,665 | | | 1,553 | |
Cash and cash equivalents at end of period | | $ | 6,973 | | $ | 7,229 | |
Operating Activities
Our net cash flows from operating activities were $54 million in 2005. We produced income of $12 million during the period and noncash expense items of $32 million for Depreciation and Amortization and $(29) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items; the most significant are Accounts Receivable, Net, Fuel, Materials and Supplies, Accounts Payable and Taxes Accrued. Accounts Receivable, Net decreased $13 million related to decreased affiliated energy transactions. The $2 million decrease in Fuel, Materials and Supplies is primarily due to lower purchases of fuel. Accounts Payable decreased $6 million due primarily to lower vendor related payables and lower affiliated energy transactions. Taxes Accrued increased $16 million primarily due to the annual tax accruals related to 2005 property taxes offset in part by a reduction of income tax related accruals.
Our net cash flows from operating activities were $17 million in 2004. We produced income of $5 million during the period and noncash expense items of $31 million for Depreciation and Amortization and $(29) million for Deferred Property Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items; the most significant are Accounts Receivable, Net, Fuel, Materials and Supplies, Accounts Payable and Taxes Accrued. Accounts Receivables, Net increased $13 million related to affiliated energy transactions. The $6 million decrease in Fuel, Materials and Supplies is primarily due to lower purchases of fuel. Accounts Payable decreased $14 million primarily due to lower vendor related payables and lower affiliated energy transactions. Taxes Accrued increased $40 million primarily due to the annual tax accruals related to 2004 property taxes and by an increase of income tax related accruals.
Investing Activities
Cash flows used for investing activities during 2005 and 2004 were $33 million and $72 million, respectively. They were comprised of Construction Expenditures related to projects for improved transmission and distribution service reliability and in 2004, a Change in Other Cash Deposits, Net related to funds held in trust for the retirement of Installment Purchase Contracts. For the remainder of 2005, we expect our Construction Expenditures to be approximately $170 million.
Financing Activities
Cash flows from financing activities were $16 million during 2005. During the first quarter, we retired $2 million of Notes Payable. Common stock dividends were $13 million.
Cash flows from financing activities were $57 million during 2004. During the first quarter, we increased our Utility Money Pool borrowing by $103 million, retired $83 million of First Mortgage Bonds, issued $52 million of Installment Purchase Contracts and paid $15 million in common stock dividends.
Financing Activity
There were no long-term debt issuances during the first three months of 2005. Retirements are shown below:
Retirements
| | | Principal | | Interest | | Due |
Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| | | | | | | |
| Note Payable | | $1,707 | | 4.47 | | 2011 |
| Note Payable | | 750 | | Variable | | 2008 |
Liquidity
We have solid investment grade ratings, which provide us ready access to capital markets in order to refinance long-term debt maturities. In addition, we participate in the AEP Utility Money Pool, which provides access to AEP’s liquidity.
Significant Factors
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.
Critical Accounting Estimates
See “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2004 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.
MTM Risk Management Contract Net Assets
This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2005
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2004 | | $ | 17,527 | |
| (Gain) Loss from Contracts Realized/Settled During the Period (a) | | | (2,871 | ) |
| Fair Value of New Contracts When Entered During the Period (b) | | | 21 | |
| Net Option Premiums Paid/(Received) (c) | | | - | |
| Change in Fair Value Due to Valuation Methodology Changes | | | - | |
| Changes in Fair Value of Risk Management Contracts (d) | | | (1,448 | ) |
| Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (e) | | | (8,121 | ) |
Total MTM Risk Management Contract Net Assets | | | 5,108 | |
| Net Cash Flow Hedge Contracts (f) | | | (4,095 | ) |
Total MTM Risk Management Contract Net Assets at March 31, 2005 | | $ | 1,013 | |
| (a) | “(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2005where we entered into the contractprior to 2005. |
| (b) | “Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. |
| (c) | “Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2005. |
| (d) | “Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
| (e) | “Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions. |
| (f) | “Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss). |
Reconciliation of MTM Risk Management Contracts to
Consolidated Balance Sheets
As of March 31, 2005
(in thousands)
| | | MTM Risk Management Contracts (a) | | Cash Flow Hedges | | Total (b) | |
| Current Assets | | $ | 9,003 | | $ | 449 | | $ | 9,452 | |
| Noncurrent Assets | | | 7,756 | | | 82 | | | 7,838 | |
Total MTM Derivative Contract Assets | | | 16,759 | | | 531 | | | 17,290 | |
| | | | | | | | | | | |
| Current Liabilities | | | (7,996 | ) | | (4,142 | ) | | (12,138 | ) |
| Noncurrent Liabilities | | | (3,655 | ) | | (484 | ) | | (4,139 | ) |
Total MTM Derivative Contract Liabilities | | | (11,651 | ) | | (4,626 | ) | | (16,277 | ) |
| | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 5,108 | | $ | (4,095 | ) | $ | 1,013 | |
| (a) | Does not include Cash Flow Hedges. |
| (b) | Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:
| · | The source of fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally). |
| · | The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash. |
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31, 2005
| | | Remainder of 2005 | | 2006 | | 2007 | | 2008 | | 2009 | | After 2009 | | Total (c) | |
Prices Actively Quoted - ExchangeTraded Contracts | | $ | (1,102 | ) | $ | 424 | | $ | 878 | | $ | - | | $ | - | | $ | - | | $ | 200 | |
Prices Provided by Other ExternalSources - OTC Broker Quotes (a) | | | 2,145 | | | 1,821 | | | 1,339 | | | 574 | | | - | | | - | | | 5,879 | |
Prices Based on Models and OtherValuation Methods (b) | | | 24 | | | (1,547 | ) | | (1,291 | ) | | 313 | | | 690 | | | 840 | | | (971 | ) |
Total | | $ | 1,067 | | $ | 698 | | $ | 926 | | $ | 887 | | $ | 690 | | $ | 840 | | $ | 5,108 | |
| (a) | “Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms. |
| (b) | “Prices Based on Models and Other Valuation Methods” is in absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market. |
| (c) | Amounts exclude Cash Flow Hedges. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Balance Sheet
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.
We employ the use of interest rate forward transactions in order to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.
The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table indicates the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI, therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2005
(in thousands)
| | | Power | | Interest Rate | | Total | |
Beginning Balance December 31, 2004 | | $ | 1,188 | | $ | (2,008 | ) | $ | (820 | ) |
| Changes in Fair Value (a) | | | (1,867 | ) | | 774 | | | (1,093 | ) |
| Reclassifications from AOCI to NetIncome (b) | | | (436 | ) | | - | | | (436 | ) |
Ending Balance March 31, 2005 | | $ | (1,115 | ) | $ | (1,234 | ) | $ | (2,349 | ) |
| (a) | “Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at March 31, 2005. Amounts are reported net of related income taxes. |
| (b) | “Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes above. |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,123 thousand loss.
Credit Risk
Our counterparty credit quality and exposure is generally consistent with that of AEP.
VaR Associated with Risk Management Contracts
The following table shows the end, high, average, and low market risk as measured by VaR for the period indicated:
| | Three Months Ended | | Twelve Months Ended | |
| | March 31, 2005 | | December 31, 2004 | |
| | (in thousands) | | (in thousands) | |
| | End | | High | | Average | | Low | | End | | High | | Average | | Low | |
| | $72 | | $159 | | $78 | | $47 | | $283 | | $923 | | $398 | | $136 | |
VaR Associated with Debt Outstanding
The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $32 million and $31 million at March 31, 2005 and December 31, 2004, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not negatively affect our results of operation or consolidated financial position.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING REVENUES | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 229,874 | | $ | 213,949 | |
| Sales to AEP Affiliates | | | 17,122 | | | 22,211 | |
TOTAL | | | 246,996 | | | 236,160 | |
| | | | | | | | |
OPERATING EXPENSES | | | | | | | |
| Fuel for Electric Generation | | | 90,110 | | | 88,823 | |
| Purchased Electricity for Resale | | | 13,380 | | | 5,934 | |
| Purchased Electricity from AEP Affiliates | | | 5,864 | | | 7,307 | |
| Other Operation | | | 44,449 | | | 50,268 | |
| Maintenance | | | 15,715 | | | 15,648 | |
| Depreciation and Amortization | | | 32,393 | | | 31,285 | |
| Taxes Other Than Income Taxes | | | 15,663 | | | 16,567 | |
| Income Taxes | | | 4,596 | | | 131 | |
TOTAL | | | 222,170 | | | 215,963 | |
| | | | | | | | |
OPERATING INCOME | | | 24,826 | | | 20,197 | |
| | | | | | | | |
| Nonoperating Income | | | 1,319 | | | 1,403 | |
| Nonoperating Expenses | | | 474 | | | 611 | |
| Nonoperating Income Tax Credit | | | 200 | | | 356 | |
| Interest Charges | | | 12,780 | | | 15,443 | |
| Minority Interest | | | (886 | ) | | (881 | ) |
| | | | | | | | |
NET INCOME | | | 12,205 | | | 5,021 | |
| | | | | | | | |
| Preferred Stock Dividend Requirements | | | 57 | | | 57 | |
| | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 12,148 | | $ | 4,964 | |
The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | |
DECEMBER 31, 2003 | | $ | 135,660 | | $ | 245,003 | | $ | 359,907 | | $ | (43,910 | ) | $ | 696,660 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (15,000 | ) | | | | | (15,000 | ) |
| Preferred Stock Dividends | | | | | | | | | (57 | ) | | | | | (57 | ) |
TOTAL | | | | | | | | | | | | | | | 681,603 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $281 | | | | | | | | | | | | (522 | ) | | (522 | ) |
| Minimum Pension Liability, Net of Tax of $12,420 | | | | | | | | | | | | 23,066 | | | 23,066 | |
NET INCOME | | | | | | | | | 5,021 | | | | | | 5,021 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 27,565 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2004 | | $ | 135,660 | | $ | 245,003 | | $ | 349,871 | | $ | (21,366 | ) | $ | 709,168 | |
| | | | | | | | | | | | | | | | | |
DECEMBER 31, 2004 | | $ | 135,660 | | $ | 245,003 | | $ | 389,135 | | $ | (1,180 | ) | $ | 768,618 | |
| | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (12,500 | ) | | | | | (12,500 | ) |
| Preferred Stock Dividends | | | | | | | | | (57 | ) | | | | | (57 | ) |
TOTAL | | | | | | | | | | | | | | | 756,061 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | |
| Cash Flow Hedges, Net of Tax of $824 | | | | | | | | | | | | (1,529 | ) | | (1,529 | ) |
NET INCOME | | | | | | | | | 12,205 | | | | | | 12,205 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 10,676 | |
| | | | | | | | | | | | | | | | | |
MARCH 31, 2005 | | $ | 135,660 | | $ | 245,003 | | $ | 388,783 | | $ | (2,709 | ) | $ | 766,737 | |
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2005 and December 31, 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
ELECTRIC UTILITY PLANT | | | |
| Production | | $ | 1,668,689 | | $ | 1,663,161 | |
| Transmission | | | 634,206 | | | 632,964 | |
| Distribution | | | 1,121,224 | | | 1,114,480 | |
| General | | | 428,751 | | | 427,910 | |
| Construction Work in Progress | | | 59,465 | | | 48,852 | |
Total | | | 3,912,335 | | | 3,887,367 | |
| Accumulated Depreciation and Amortization | | | 1,734,533 | | | 1,709,758 | |
TOTAL - NET | | | 2,177,802 | | | 2,177,609 | |
| | | | | | | | |
OTHER PROPERTY AND INVESTMENTS | | | | | | | |
| Nonutility Property, Net | | | 4,049 | | | 4,049 | |
| Other Investments | | | 4,628 | | | 4,628 | |
TOTAL | | | 8,677 | | | 8,677 | |
| | | | | | | | |
CURRENT ASSETS | | | | | | | |
| Cash and Cash Equivalents | | | 6,973 | | | 2,308 | |
| Other Cash Deposits | | | 6,504 | | | 6,292 | |
| Advances to Affiliates | | | 40,033 | | | 39,106 | |
| Accounts Receivable: | | | | | | | |
| Customers | | | 40,117 | | | 39,042 | |
| Affiliated Companies | | | 14,733 | | | 28,817 | |
| Miscellaneous | | | 5,834 | | | 5,856 | |
| Allowance for Uncollectible Accounts | | | (5 | ) | | (45 | ) |
| Fuel Inventory | | | 42,531 | | | 45,793 | |
| Materials and Supplies | | | 36,886 | | | 36,051 | |
| Risk Management Assets | | | 9,452 | | | 25,379 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | | - | | | 4,687 | |
| Margin Deposits | | | 1,650 | | | 3,419 | |
| Prepayments and Other | | | 17,639 | | | 18,331 | |
TOTAL | | | 222,347 | | | 255,036 | |
| | | | | | | | |
| | | | | | | | |
DEFERRED DEBITS AND OTHER ASSETS | | | | | | | |
| Regulatory Assets: | | | | | | | |
| SFAS 109 Regulatory Asset, Net | | | 20,874 | | | 18,000 | |
| Unamortized Loss on Reacquired Debt | | | 20,067 | | | 20,765 | |
| Other | | | 14,100 | | | 16,350 | |
| Long-term Risk Management Assets | | | 7,838 | | | 17,179 | |
| Prepaid Pension Obligations | | | 80,941 | | | 81,132 | |
| Deferred Charges | | | 74,217 | | | 51,561 | |
TOTAL | | | 218,037 | | | 204,987 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 2,626,863 | | $ | 2,646,309 | |
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
March 31, 2005 and December 31, 2004
(Unaudited)
| | | 2005 | | 2004 | |
CAPITALIZATION | | (in thousands) | |
| Common Shareholder’s Equity: | | | | | | | |
| Common Stock - $18 par value per share: | | | | | | | |
| Authorized - 7,600,000 shares | | | | | | | |
| Outstanding - 7,536,640 shares | | $ | 135,660 | | $ | 135,660 | |
| Paid-in Capital | | | 245,003 | | | 245,003 | |
| Retained Earnings | | | 388,783 | | | 389,135 | |
| Accumulated Other Comprehensive Income (Loss) | | | (2,709 | ) | | (1,180 | ) |
Total Common Shareholder’s Equity | | | 766,737 | | | 768,618 | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,700 | | | 4,700 | |
Total Shareholders’ Equity | | | 771,437 | | | 773,318 | |
| Long-term Debt: | | | | | | | |
| Nonaffiliated | | | 535,525 | | | 545,395 | |
| Affiliated | | | 50,000 | | | 50,000 | |
Total Long-term Debt | | | 585,525 | | | 595,395 | |
TOTAL | | | 1,356,962 | | | 1,368,713 | |
| | | | | | | | |
| Minority Interest | | | 1,921 | | | 1,125 | |
| | | | | | | | |
CURRENT LIABILITIES | | | | | | | |
| Long-term Debt Due Within One Year - Nonaffiliated | | | 217,474 | | | 209,974 | |
| Accounts Payable: | | | | | | | |
| General | | | 36,154 | | | 40,001 | |
| Affiliated Companies | | | 30,719 | | | 33,285 | |
| Customer Deposits | | | 29,684 | | | 30,550 | |
| Taxes Accrued | | | 61,590 | | | 45,474 | |
| Interest Accrued | | | 11,523 | | | 12,509 | |
| Risk Management Liabilities | | | 12,138 | | | 18,607 | |
| Obligations Under Capital Leases | | | 4,052 | | | 3,692 | |
| Regulatory Liability for Over-Recovered Fuel Costs | | | 13,655 | | | 9,891 | |
| Other | | | 32,083 | | | 33,417 | |
TOTAL | | | 449,072 | | | 437,400 | |
| | | | | | | | |
DEFERRED CREDITS AND OTHER LIABILITIES | | | | | | | |
| Deferred Income Taxes | | | 397,563 | | | 399,756 | |
| Long-term Risk Management Liabilities | | | 4,139 | | | 9,128 | |
| Reclamation Reserve | | | 5,761 | | | 7,624 | |
| Regulatory Liabilities: | | | | | | | |
| Asset Removal Costs | | | 250,637 | | | 249,892 | |
| Deferred Investment Tax Credits | | | 34,466 | | | 35,539 | |
| Excess Earnings | | | 3,167 | | | 3,167 | |
| Other | | | 11,104 | | | 21,320 | |
| Asset Retirement Obligations | | | 27,518 | | | 27,361 | |
| Obligations Under Capital Leases | | | 30,525 | | | 30,854 | |
| Deferred Credits and Other | | | 54,028 | | | 54,430 | |
TOTAL | | | 818,908 | | | 839,071 | |
| | | | | | | | |
| Commitments and Contingencies (Note 5) | | | | | | | |
| | | | | | | | |
TOTAL CAPITALIZATION AND LIABILITIES | | $ | 2,626,863 | | $ | 2,646,309 | |
See Notes to Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2005 and 2004
(Unaudited)
(in thousands)
| | | 2005 | | 2004 | |
OPERATING ACTIVITIES | | | | | |
Net Income | | $ | 12,205 | | $ | 5,021 | |
Adjustments to Reconcile Net Income to Net Cash FlowsFrom Operating Activities: | | | | | | | |
| Depreciation and Amortization | | | 32,393 | | | 31,285 | |
| Deferred Property Taxes | | | (28,570 | ) | | (29,063 | ) |
| Deferred Income Taxes | | | (4,312 | ) | | (5,182 | ) |
| Deferred Investment Tax Credits | | | (1,073 | ) | | (1,081 | ) |
| Mark-to-Market of Risk Management Contracts | | | 12,419 | | | 11,837 | |
| Over/Under Fuel Recovery | | | 8,451 | | | 9,649 | |
| Change in Other Noncurrent Assets | | | 4,760 | | | 1,175 | |
| Change in Other Noncurrent Liabilities | | | (10,413 | ) | | (3,620 | ) |
Changes in Components of Working Capital: | | | | | | | |
| Accounts Receivable, Net | | | 12,991 | | | (12,895 | ) |
| Fuel, Materials and Supplies | | | 2,427 | | | 6,226 | |
| Accounts Payable | | | (6,413 | ) | | (13,590 | ) |
| Taxes Accrued | | | 16,116 | | | 39,682 | |
| Customer Deposits | | | (866 | ) | | 2,132 | |
| Interest Accrued | | | (986 | ) | | (2,598 | ) |
| Other Current Assets | | | 4,849 | | | 901 | |
| Other Current Liabilities | | | (112 | ) | | (22,987 | ) |
Net Cash Flows From Operating Activities | | | 53,866 | | | 16,892 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | |
| Construction Expenditures | | | (33,156 | ) | | (19,376 | ) |
| Change in Other Cash Deposits, Net | | | (212 | ) | | (52,922 | ) |
| Proceeds from Sale of Assets | | | 108 | | | - | |
Net Cash Flows Used For Investing Activities | | | (33,260 | ) | | (72,298 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | |
| Issuance of Long-term Debt | | | - | | | 52,179 | |
| Retirement of Long-term Debt | | | (2,457 | ) | | (82,907 | ) |
| Changes in Advances to/from Affiliates, Net | | | (927 | ) | | 102,744 | |
| Dividends Paid on Common Stock | | | (12,500 | ) | | (15,000 | ) |
| Dividends Paid on Cumulative Preferred Stock | | | (57 | ) | | (57 | ) |
Net Cash Flows From (Used For) Financing Activities | | | (15,941 | ) | | 56,959 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 4,665 | | | 1,553 | |
Cash and Cash Equivalents at Beginning of Period | | | 2,308 | | | 5,676 | |
Cash and Cash Equivalents at End of Period | | $ | 6,973 | | $ | 7,229 | |
SUPPLEMENTAL DISCLOSURE: |
| Cash paid (received) for interest net of capitalized amounts was $12,304,000 and $15,964,000 and for income taxes was $22,257,000 and $(2,228,000) in 2005 and 2004, respectively. Noncash capital lease acquisitions were $775,000 and $887,000 in 2005 and 2004, respectively. |
See Notes to Respective Financial Statements. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to SWEPCo’s consolidated financial statements are combined with the notes to financial statements for other subsidiary registrants. Listed below are the notes that apply to SWEPCo.
| | Footnote Reference |
| | |
| Significant Accounting Matters | Note 1 |
| New Accounting Pronouncements | Note 2 |
| Rate Matters | Note 3 |
| Commitments and Contingencies | Note 5 |
| Guarantees | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Financing Activities | Note 10 |
NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
| The notes to financial statements that follow are a combined presentation for AEP’s registrant subsidiaries. The following list indicates the registrants to which the footnotes apply: |
| | | |
| 1. | Significant Accounting Matters | AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
| 2. | New Accounting Pronouncements | AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
| 3. | Rate Matters | APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
| 4. | Customer Choice andIndustry Restructuring | CSPCo, OPCo, TCC, TNC |
| 5. | Commitments and Contingencies | AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
| 6. | Guarantees | AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
| 7. | Dispositions and Assets Held for Sale | TCC |
| 8. | Benefit Plans | APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
| 9. | Business Segments | AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
| 10. | Financing Activities | AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC |
1. SIGNIFICANT ACCOUNTING MATTERS
General
The accompanying unaudited interim financial statements should be read in conjunction with the 2004 Annual Report as incorporated in and filed with our 2004 Form 10-K.
In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments which are necessary for a fair presentation of the results of operations for interim periods.
Components of Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) is included on the balance sheet in the capitalization section. The components of Accumulated Other Comprehensive Income (Loss) for Registrant Subsidiaries are shown in the following table:
| | | March 31, | | December 31, | |
| | | 2005 | | 2004 | |
| | | (in thousands) | |
Components | | | | | |
Cash Flow Hedges: | | | | | |
| APCo | | $ | (17,034 | ) | $ | (9,324 | ) |
| CSPCo | | | (4,381 | ) | | 1,393 | |
| I&M | | | (10,389 | ) | | (4,076 | ) |
| KPCo | | | (1,814 | ) | | 813 | |
| OPCo | | | (6,695 | ) | | 1,241 | |
| PSO | | | (593 | ) | | 400 | |
| SWEPCo | | | (2,349 | ) | | (820 | ) |
| TCC | | | (3,679 | ) | | 657 | |
| TNC | | | (489 | ) | | 285 | |
| | | | | | | | |
Minimum Pension Liability: | | | | | | | |
| APCo | | $ | (72,348 | ) | $ | (72,348 | ) |
| CSPCo | | | (62,209 | ) | | (62,209 | ) |
| I&M | | | (41,175 | ) | | (41,175 | ) |
| KPCo | | | (9,588 | ) | | (9,588 | ) |
| OPCo | | | (75,505 | ) | | (75,505 | ) |
| PSO | | | (325 | ) | | (325 | ) |
| SWEPCo | | | (360 | ) | | (360 | ) |
| TCC | | | (4,816 | ) | | (4,816 | ) |
| TNC | | | (413 | ) | | (413 | ) |
Accounting for Asset Retirement Obligations
All of AEP’s Registrant Subsidiaries implemented SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003, which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred. Upon establishment of a legal liability, SFAS 143 requires a corresponding asset to be established which will be depreciated over its useful life.
The following is a reconciliation of beginning and ending aggregate carrying amounts of asset retirement obligations by Registrant Subsidiary:
| | | Balance at January 1, 2005 | | Accretion | | Liabilities Incurred | | Liabilities Settled | | Revisions in Cash Flow Estimates | | Balance at March 31, 2005 | |
| | | (in millions) | |
| AEGCo (a) | | $ | 1.2 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 1.2 | |
| APCo (a) | | | 24.6 | | | 0.5 | | | - | | | - | | | - | | | 25.1 | |
| CSPCo (a) | | | 11.6 | | | 0.2 | | | - | | | - | | | - | | | 11.8 | |
| I&M (b) | | | 711.8 | | | 11.6 | | | - | | | - | | | - | | | 723.4 | |
| OPCo (a) | | | 45.6 | | | 0.9 | | | - | | | - | | | - | | | 46.5 | |
| SWEPCo (c) | | | 27.4 | | | 0.2 | | | - | | | (0.1 | ) | | - | | | 27.5 | |
| TCC (d) | | | 248.9 | | | 4.5 | | | - | | | - | | | - | | | 253.4 | |
| (a) | Consists of asset retirement obligations related to ash ponds. |
| (b) | Consists of asset retirement obligations related to ash ponds ($1.2 million at March 31, 2005) and nuclear decommissioning costs for the Cook Plant ($722.2 million at March 31, 2005). |
| (c) | Consists of asset retirement obligations related to Sabine Mining Company and Dolet Hills Lignite Company, LLC. |
| (d) | Consists of asset retirement obligations related to nuclear decommissioning costs for STP included in Liabilities Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets. |
Accretion expense is included in Other Operation expense in the respective income statements of the individual registrant subsidiaries.
As of March 31, 2005 and December 31 2004, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $962 million ($819 million for I&M and $143 million for TCC) and $934 million ($791 million for I&M and $143 million for TCC), respectively, recorded in Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds on I&M’s Consolidated Balance Sheets and in Assets Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets.
Reclassification
Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income (Loss).
Prior Period Adjustment
As disclosed in the 2004 Annual Report, in the second quarter of 2004 the Registrant Subsidiaries implemented FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003 (FSP FAS 106-2), retroactive to January 1, 2004. The effect of implementing FSP FAS 106-2 on the first quarter of 2004 is as follows:
| | | Originally Reported Net Income (Loss) | | Effect of Medicare Subsidy | | Restated Net Income (Loss) | |
| | | (in thousands) | |
| APCo | | $ | 64,521 | | $ | 815 | | $ | 65,336 | |
| CSPCo | | | 44,705 | | | 414 | | | 45,119 | |
| I&M | | | 42,376 | | | 632 | | | 43,008 | |
| KPCo | | | 11,490 | | | 121 | | | 11,611 | |
| OPCo | | | 79,444 | | | 720 | | | 80,164 | |
| PSO | | | (9,284 | ) | | 281 | | | (9,003 | ) |
| SWEPCo | | | 4,730 | | | 291 | | | 5,021 | |
| TCC | | | 29,077 | | | 327 | | | 29,404 | |
| TNC | | | 12,953 | | | 143 | | | 13,096 | |
2. NEW ACCOUNTING PRONOUNCEMENTS
Upon issuance of exposure drafts or final pronouncements, we review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented during 2005 that we have determined relate to our operations.
SFAS 123 (revised 2004) “Share-Based Payment” (SFAS 123R)
In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting previously available under Accounting Principles Board (APB) Opinion No. 25. The statement is effective as of the first annual period beginning after June 15, 2005, with early implementation permitted. A cumulative effect of a change in accounting principle is recorded for the effect of initially applying the statement.
We will implement SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost will be based on the grant-date fair value of the equity award. The Registrant Subsidiaries do not expect implementation of SFAS 123R to materially affect their results of operations, cash flows or financial condition.
In March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107) which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies.
FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47)
In March 2005, the FASB issued FIN 47, which interprets the application of SFAS 143. FIN 47 clarifies that the term conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Entities are required to record a liability for the fair value of a conditional asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.
The Registrant Subsidiaries will implement FIN 47 during the fourth quarter of 2005. Implementation will require an adjustment for the cumulative effect for the nonregulated operations of initially applying FIN 47 to be recorded as a change in accounting principle, disclosure of pro forma liabilities and asset retirement obligations, and other additional disclosures. The Registrant Subsidiaries have not completed their evaluation of any potential impact to their results of operations, cash flows or financial condition.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations that may result from any such future changes. The FASB is currently working on several projects including business combinations, operating segments, liabilities and equity, revenue recognition, pension plans, fair value measurements, accounting changes and related tax impacts. We also expect to see more FASB projects as a result of their desire to converge International Accounting Standards with those generally accepted in the United States of America. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position.
3. RATE MATTERS
As discussed in our 2004 Annual Report, rate and regulatory proceedings at the FERC and at several state commissions are ongoing. The Rate Matters note within our 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material rate matters still pending. The following sections discuss current activities and update the 2004 Annual Report.
Louisiana Fuel Audit - Affecting SWEPCo
The Louisiana Public Service Commission (LPSC) is performing an audit of SWEPCo’s historical fuel costs and addressing customer complaints regarding potential overcharge of fuel costs. In testimony filed in this matter, the LPSC Staff recommended refunds of approximately $5 million. In subsequent surrebuttal testimony filed by the LPSC Staff, they recognized that SWEPCo’s costs were reasonable but that certain costs would be more appropriately recovered through base rates. While initial indications from the LPSC Staff surrebuttal testimony would not indicate a material disallowance, management cannot predict the ultimate outcome in this proceeding. If the LPSC or the Court does not agree with LPSC Staff recommendations, it could have an adverse effect on SWEPCo’s future results of operations and cash flows.
PSO Fuel and Purchased Power - Affecting PSO
In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices.
In the proceeding, parties alleged that the allocation of off-system sales margins between AEP East and AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and AEP West companies should have received more margins. The OCC expanded the scope of the proceeding to include the off-system sales margin issue for the year 2002 and an intervenor filed a motion to expand the scope to review this same issue for the years 2003 and 2004. Using the intervenors’ method, PSO estimates that the increase in margins would be $29 million through March 31, 2005. In April 2005, the OCC heard arguments from intervenors that requested the OCC to conduct a prudence review of PSO’s fuel and purchased power for 2003. Management is unable to predict if the OCC will order a prudence review of PSO’s fuel and purchased power activities for 2003 or the ultimate effect of these proceedings on PSO’s revenues, results of operations, cash flows and financial condition.
Michigan Fuel Recovery Plan - Affecting I&M
In September 2004, I&M filed its 2005 Power Supply Cost Recovery (PSCR) Plan, with the requested PSCR factors implemented pursuant to the statute effective with January 2005 billings, replacing the 2004 factors. On March 29, 2005, the Michigan Public Service Commission (MPSC) issued an order approving a settlement agreement authorizing the proposed 2005 PSCR Plan factors.
On March 31, 2005, I&M filed its 2004 PSCR Reconciliation seeking recovery of approximately $2 million of unrecovered PSCR fuel costs and interest proposed to be recovered through the application of customer bill surcharges during October 2005 through December 2005.
On April 28, 2005, the MPSC issued an Opinion and Order approving I&M’s proposed 2004 PSCR factors as billed and finding in favor of I&M on all issues, including the proposed treatment of net SO2 and NOx credits.
TCC Rate Case - Affecting TCC
TCC has an on-going transmission and distribution (T&D) rate review before the PUCT. In that rate review, the PUCT has issued various decisions and conducted additional hearings in March 2005. At an open meeting on April 13, 2005, the PUCT decided all remaining issues except the amount of affiliate expenses to include in revenue requirements, which the PUCT decided to defer. Adjusted for the decisions approved by the PUCT through April 13, 2005, the ALJs recommended disallowances of affiliate expenses would produce an annual rate reduction of $25 million to $52 million. If TCC were to prevail on the affiliate expenses issue, the result would be an annual rate increase of $2 million. An order reducing TCC’s rates could have an adverse effect on TCC’s future results of operations and cash flows.
TCC Unbundled Cost of Service (UCOS) Appeal - Affecting TCC
The UCOS proceeding established the unbundled regulated wires rates to be effective when retail electric competition began. TCC placed new T&D rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC’s UCOS proceeding. Certain PUCT rulings, including the initial determination of stranded costs, the requirement to refund TCC’s excess earnings, the regulatory treatment of nuclear insurance and the distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003, upholding the PUCT’s UCOS order with one exception. The Court ruled that the refund of the 1999 through 2001 excess earnings, solely as a credit to nonbypassable T&D rates charged to REPs, discriminates against residential and small commercial customers and is unlawful. Management estimates that the adverse effect of a decision to reduce the PTB rates for the period prior to the sale of the AEP REPs is approximately $11 million pretax. The District Court decision was appealed to the Third Court of Appeals by TCC and other parties. Based on advice of counsel, management believes that it will ultimately prevail on appeal. If the District Court’s decision is ultimately upheld on appeal or the Court of Appeals reverses the District Court on issues adverse to TCC, it could have an adverse effect on TCC’s future results of operations and cash flows.
TCC and TNC ERCOT Price-to-Beat (PTB) Fuel Factor Appeal- Affecting TCC and TNC
Several parties including the Office of Public Utility Counsel and cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU. In June 2003, the Court ruled that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, that the PUCT improperly shifted the burden of proof from the company to intervening parties and that the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. The amount of unaccounted for energy built into the PTB fuel factors was approximately $3 million for Mutual Energy WTU. The Court upheld the initial PTB orders on all other issues. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. Management believes, based on the advice of counsel, that the PUCT’s original decision will ultimately be upheld. If the court’s decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors charged to retail customers in the years 2002 through 2004 resulting in an adverse effect on TCC’s and TNC’s future results of operations and cash flows.
PSO Rate Review - Affecting PSO
PSO is involved in a commission staff-initiated rate review before the OCC seeking to increase its base rates, while various other parties made recommendations to reduce PSO’s base rates. The annual rate reduction recommendations ranged between $15 million and $36 million. In March 2005, a settlement was negotiated and approved by the ALJ. Pending approval by the OCC, the settlement provides for a $7 million base rate reduction partially offset by a $6 million reduction in annual depreciation expense. The settlement also provides for recovery of $9 million of deferred fuel and the continuation of the vegetation management rider. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC did not approve the settlement in time for implementation of new base rates in May 2005 as agreed to by the parties, which voids the settlement. The OCC issued an Order approving the stipulation on May 2, 2005 with one exception. The Order approves the implementation of new base rates in June 2005 versus the stipulation date of May 2005.
Indiana Settlement Agreement - Affecting I&M
In 2004, the IURC ordered the continuation of the fixed fuel adjustment charge on an interim basis through March 2005, pending the outcome of negotiations.Certain of the parties to the negotiations reached a settlement and signed an agreement on March 10, 2005, and filed the agreement with the IURC on March 14, 2005. The IURC may rule on the agreement during the second quarter of 2005.
The filed settlement freezes fuel rates for the March 2004 through June 2007 billing months at an increasing rate that includes 8.609 mills per KWH reflected in base rates. The settlement provides that the total fuel rates will be 9.88 mills per KWH from January 2005 through December 2005, 10.26 mills per KWH from January 2006 through December 2006, and 10.63 mills per for KWH from January 2007 through June 2007. Pursuant to a separate IURC order, I&M began billing the 9.88 mills per KWH total fuel rate on an interim basis effective with the April 2005 billing month.
The settlement agreement also covers certain events at the Cook Plant. The settlement provides that if an outage greater than 60 days occurs at Cook Plant, the recovery of actual monthly fuel costs will be in effect for the outage period beyond 60 days, capped by the average AEP System Pool Primary Energy Rate (Primary Energy Rate), excluding I&M, as defined by the AEP System Interconnection Agreement and adjusted for losses. If a second outage greater than 60 days occurs, actual monthly fuel costs capped at the Primary Energy Rate would be recovered through June 2007. Over the term of the settlement, if total actual fuel costs (except during a Cook Plant outage greater than 60 days) are under the cap prices, the excess will be credited to customers over the next two fuel adjustment clause filings. Under the settlement fuel costs in excess of the cap price cannot be recovered. If Cook Plant operates at a capacity factor greater than 87% during the fuel rate freeze period, I&M will receive credit for 30% of the savings produced and customers will be credited with 70% of these savings over the first two fuel filings after the fuel rate freeze period ends in June 2007.
Pending approval of the IURC, this settlement agreement also freezes base rates from January 1, 2005 to June 30, 2007 at the rates in effect as of January 1, 2005. During this freeze period, I&M may not implement a general increase in base rates or implement a rider or cost deferral not established in the settlement agreement unless the IURC determines that a significant change in conditions beyond I&M’s control occurs or a material impact on I&M occurs as a result of federal, state or local regulation or statute that mandates reliability standards related to transmission or distribution costs.
If the settlement is approved by the IURC, fuel costs previously expensed since January 2005 exceeding the previously authorized level of 9.2 mills up to 9.88 mills (approximately $4 million through March 31, 2005) would be deferred for future recovery. If future fuel cost per KWH exceeds the caps, or if the base rate freeze precludes I&M from seeking timely rate increases to recover increases in I&M’s cost of service, I&M’s future results of operations and cash flows would be adversely affected.
RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo, and OPCo
Prior to joining PJM, the AEP East companies deferred costs incurred under FERC orders to originally form a new RTO, (the Alliance) and subsequently to join an existing RTO (PJM). In 2004, we requested permission to amortize, beginning January 1, 2005, the $18 million of deferred non-PJM billed formation/integration costs over 15 years and the $17 million of deferred PJM-billed integration costs, but we did not propose an amortization period for the PJM-billed costs in the application. The FERC approved our application.
In January 2005, the AEP East companies began amortizing their deferred non-PJM billed costs over 15 years and the deferred PJM-billed integration costs over 10 years. The total amortization related to such costs was $1 million in the first quarter of 2005. As of March 31, 2005, the AEP East Companies have $34 million of deferred unamortized RTO formation/integration costs.
Company | | (in millions) | |
| APCo | | $ | 9.7 | |
| CSPCo | | | 4.0 | |
| I&M | | | 7.4 | |
| KPCo | | | 2.2 | |
| OPCo | | | 11.0 | |
On March 8, 2005, we jointly filed with other utilities a request with the FERC to recover deferred PJM-billed integration costs of $17 million from all load-serving entities in the PJM RTO over a ten-year period starting January 1, 2005. On March 31, 2005, we also filed a request for a revised network integration transmission service revenue requirement for the AEP zone of PJM. Included in the costs reflected in that revenue requirement was the budgeted 2005 amortization of our deferred non-PJM billed Alliance RTO formation and PJM integration costs. The AEP East companies will be responsible for paying most of the amounts allocated by the FERC to the AEP East zone since the costs are attributable to their internal load.
Although several parties have filed protests of the joint filing to recover the deferred PJM-billed integration costs, we believe that it is probable that the FERC will ultimately approve recovery of the PJM-billed integration costs through the PJM OATT and that the FERC will grant a long enough amortization period to allow us to recover the deferred non-PJM billed Alliance RTO formation and PJM integration costs in the AEP East retail jurisdictions. If the FERC issues an adverse ruling, the AEP East companies’ future results of operations and cash flows could be adversely affected.
FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M, KPCo and OPCo
A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. Billing statements from PJM for the first quarter of 2005 did not reflect any credits to AEP for SECA revenues. SECA billings by PJM crediting AEP for its SECA revenue are scheduled to begin in May 2005 with retroactive adjustments to be billed by PJM in June and July 2005. Based upon the SECA transition rate methodology approved by the FERC, the AEP East companies accrued $26 million of SECA revenue in the first quarter of 2005 and has a receivable for SECA revenues of $37 million at March 31, 2005.
| | | SECA Revenue for Three Months Ended March 31, 2005 | | SECA Receivable at March 31, 2005 | |
Company | | (in millions) | | (in millions) | |
| APCo | | $ | 8.6 | | $ | 12.1 | |
| CSPCo | | | 4.4 | | | 6.4 | |
| I&M | | | 4.9 | | | 7.1 | |
| KPCo | | | 2.0 | | | 2.8 | |
| OPCo | | | 6.1 | | | 8.9 | |
In a March 2005 FERC filing, we proposed an increase in the rate for network integration transmission service, as well as rates for other ancillary services. The primary customers of these services are the municipal and cooperative wholesale entities that have load delivery points in the AEP zone of PJM. As proposed, the rates will automatically increase to reflect the loss of SECA transition rates on April 1, 2006.
The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate was eliminated and replaced by SECA transition rates was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be sufficient to replace the SECA transition rate revenues and whether the new rates will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, if AEP zonal rates are not sufficiently increased by the FERC after March 31, 2006, or if any increase in the AEP East companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.
Hold Harmless Proceeding - Affecting AEP East companies
In a July 2002 order conditionally accepting AEP East companies’ choice to join PJM, the FERC directed ComEd, MISO, PJM and us to propose a solution that would effectively hold harmless the utilities in Michigan and Wisconsin from any adverse effects associated with loop flows or congestion resulting from ComEd and us joining PJM instead of MISO.
In July 2004, AEP East companies and PJM filed jointly with the FERC a hold-harmless proposal. In September 2004, the FERC accepted and suspended the new proposal that became effective October 1, 2004, subject to refund and to the outcome of a hearing on the appropriate compensation, if any, to the Michigan and Wisconsin utilities. A hearing is scheduled for May 2005.
The Michigan and Wisconsin utilities have presented studies that show estimated adverse effects to utilities in the two states in the range of $60 million to $70 million over the term of the agreement for AEP East companies and ComEd. The recent supplemental filing by the Michigan companies shows estimated adverse effects to utilities in Michigan of up to $50 million over the term of agreement. AEP East companies and ComEd have presented studies that show no adverse effects to the Michigan and Wisconsin utilities. ComEd has separately settled this issue with the Michigan and Wisconsin utilities for a one time total payment of approximately $5 million, which was approved by the FERC. On December 27, 2004, AEP East companies and the Wisconsin utilities jointly filed a settlement that resolves all hold-harmless issues for a one-time payment of $250,000 that was approved by the FERC on March 7, 2005. On April 25, 2005, AEP East companies and International Transmission Company in Michigan filed a settlement that resolves all hold-harmless issues for a one-time payment of $120,000. Settlement negotiations are in progress with the remaining Michigan companies.
At this time, management is unable to predict the outcome of this proceeding. AEP East companies will support vigorously its positions before the FERC. If the FERC ultimately approves a significant hold-harmless payment to the Michigan utilities, it would adversely impact results of operations and cash flows.
4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
As discussed in the 2004 Annual Report, certain AEP subsidiaries are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in the 2004 Annual Report should be read in conjunction with this report in order to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring.
OHIO RESTRUCTURING - Affecting CSPCo and OPCo
On January 26, 2005, the PUCO approved Rate Stabilization Plans for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for up to 4% of additional annual generation rate increases based on supporting the need for additional revenues. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM RTO costs from 2004 and 2005 related to their obligation as the Provider of Last Resort in Ohio’s customer choice program. First quarter 2005 pretax earnings were increased by $13 million for CSPCo and $32 million for OPCo as a result of implementing this provision of the Rate Stabilization Plans. Of these amounts approximately $8 million for CSPCo and $21 for OPCo relate to 2004 environmental carrying costs and RTO costs.
In February 2005, various intervenors filed applications for rehearing with the PUCO regarding their approval of the rate stabilization plans. On March 23, 2005, the PUCO denied all applications for rehearing. In April 2005, an intervenor filed an appeal to the Ohio Supreme Court. Management cannot predict the ultimate impact appeal proceedings will have on the Ohio companies’ future results of operations and cash flows.
TEXAS RESTRUCTURING - Affecting TCC and TNC
The stranded cost recovery process in Texas continues with the principal remaining component of the process being the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items in TCC’s future true-up filing. TCC has asked permission from the PUCT to file its True-up Proceeding after the sales of its interest in STP have been concluded, with only the ownership interest in Oklaunion remaining to be settled. If the request is approved, it is anticipated that TCC’s True-up Proceeding will be filed during the second quarter of 2005 seeking recovery of its net regulatory asset of $1.6 billion for its net stranded cost and other true-up items, which it believes the Texas Restructuring Legislation allows.
The Components of TCC’s Net True-up Regulatory Asset as of March 31, 2005 and December 31, 2004 are:
| | | TCC | |
| | | March 31, 2005 | | December 31, 2004 | |
| | | (in millions) | |
| Stranded Generation Plant Costs | | $ | 898 | | $ | 897 | |
| Net Generation-related Regulatory Asset | | | 249 | | | 249 | |
| Unrefunded Excess Earnings | | | (6 | ) | | (10 | ) |
Net Stranded Generation Costs | | | 1,141 | | | 1,136 | |
| Carrying Costs on Stranded Generation Plant Costs | | | 205 | | | 225 | |
Net Stranded Generation Costs Designated for Securitization | | | 1,346 | | | 1,361 | |
| | | | | | | | |
| Wholesale Capacity Auction True-up | | | 483 | | | 483 | |
| Carrying Costs on Wholesale Capacity Auction True-up | | | 91 | | | 77 | |
| Retail Clawback | | | (61 | ) | | (61 | ) |
| Deferred Over-recovered Fuel Balance | | | (215 | ) | | (212 | ) |
Net Other Recoverable True-up Amounts | | | 298 | | | 287 | |
Total Recorded Net True-up Regulatory Asset | | $ | 1,644 | | $ | 1,648 | |
The Components of TNC’s Net True-up Regulatory Liability as of March 31, 2005 and December 31, 2004 are:
| | | TNC | |
| | | March 31, 2005 | | December 31, 2004 | |
| | | (in millions) | |
| Retail Clawback | | $ | (14 | ) | $ | (14 | ) |
| Deferred Over-recovered Fuel Balance | | | (5 | ) | | (4 | ) |
Total Recorded Net True-up Regulatory Liability | | $ | (19 | ) | $ | (18 | ) |
TCC Fuel Reconciliation
On April 14, 2005, the PUCT ruled that specific energy-only purchased power contracts included a capacity component which is not recoverable in fuel rates. In the first quarter of 2005, TCC recorded a provision for fuel revenue refund of $3 million, inclusive of interest, for this decision and continued to accrue interest on the deferred over-recovered fuel balance. This provision for refund results in a deferred over-recovery balance of $215 million as of March 31, 2005.
TCC Carrying Costs on Net True-up Regulatory Assets
TCC continues to accrue a carrying cost at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on a methodology detailed in the order for calculating a cost-of-money benefit related to Accumulated Deferred Federal Income Taxes (ADFIT) on TCC’s net stranded cost and other true-up items which was applied retroactively to January 1, 2004. In the first quarter of 2005, TCC accrued carrying costs of $21 million which was more than offset by an adjustment based on this order of $27 million. The net reduction of $6 million in carrying costs is included in Nonoperating Income in the first quarter of 2005 on TCC’s accompanying Statements of Income.
As of March 31, 2005, TCC has computed carrying costs of $450 million of which $296 million was recognized as income in 2004 and the first quarter of 2005. The remaining equity component of the carrying costs of $154 million will be recognized in income as collected.
TCC Unrefunded Excess Earnings
At December 31, 2004, TCC had approximately $10 million of unrefunded excess earnings. In the first quarter of 2005, TCC refunded an additional $4 million reducing its unrefunded excess earnings to $6 million.
TCC True-up Proceeding
When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated T&D rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.
The nonaffiliated utility’s March order also provided for the present value of the cost free capital benefits of ADFIT associated with stranded generation costs to be offset against other recoverable true-up amounts when establishing the competition transition charges (CTC). TCC estimates its present value ADFIT benefit to be $212 million based on its current net true-up regulatory asset. TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT in the nonaffiliated utility’s order and determined that the projected cash flows from the transition charges were more than sufficient to recover TCC’s entire net true-up regulatory asset. As a result, no impairment has been recorded. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in its True-up Proceeding, TCC expects to amortize its total net true-up regulatory asset over recovery periods to be established by the PUCT in proceedings subsequent to TCC’s True-up Proceeding.
We believe that our recorded net true-up regulatory asset of $1.6 billion at March 31, 2005 isrecoverable underthe Texas Restructuring Legislation; however, we anticipate that other parties will contend that material amounts of stranded costs should not be recovered.To the extent decisions of the PUCT in TCC’s future True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated companies, additional material disallowances and reductions of recorded carrying costs are possible, which could have a material adverse effect on TCC’s future results of operations, cash flows and possibly financial condition.
TNC True-Up Proceeding
In January 2005, intervenors made various recommendations including an increase in excess earnings of $5 million and a T&D rate reduction of $3 million annually. The intervenors also recommended that TNC’s fuel over-recovery should be increased by $2 million. TNC is awaiting a PUCT decision and order and has recorded no disallowances based on intervenor contentions.
In 2004, TNC appealed to the state and federal courts the PUCT’s order in its final fuel reconciliation covering the period from July 2000 through December 31, 2001. In March 2005, the ALJ made certain recommendations regarding the deferred fuel balance resulting in an additional provision for refund of $1 million, which results in an over-recovery amount of $5 million. TNC will pursue vigorously its appeals, but cannot predict their outcome.
5. COMMITMENTS AND CONTINGENCIES
As discussed in the Commitments and Contingencies note within the 2004 Annual Report, certain Registrant Subsidiaries continue to be involved in various legal matters. The 2004 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since their disclosure in the 2004 Annual Report. The matters discussed in the 2004 Annual Report without significant changes in status since year-end include, but are not limited to, (1) carbon dioxide public nuisance claims, (2) nuclear matters, (3) construction commitments, (4) potential uninsured losses, and (5) FERC long-term contracts. See disclosure below for significant matters with changes in status subsequent to the disclosure made in the 2004 Annual Report.
ENVIRONMENTAL
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at the generating units over a 20-year period.
Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.
In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaint and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern States each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. These complaints have been assigned to the same judge in the Southern District Court. AEP filed an answer to the complaint in January 2005, denying the allegations and stating its defenses.
In August 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, a nonaffiliated utility. The District Court held that replacements of major boiler and turbine components that are infrequently performed at a single unit, that are performed with the assistance of outside contractors, that are accounted for as capital expenditures, and that require the unit to be taken out of service for a number of months are not “routine” maintenance, repair, and replacement. The District Court also held that a comparison of past actual emissions to projected future emissions must be performed prior to any nonroutine physical change in order to evaluate whether an emissions increase will occur, and that increased hours of operation that are the result of eliminating forced outages due to the repairs must be included in that calculation. Based on these holdings, the District Court ruled that all of the challenged activities in that case were not routine, and that the changes resulted in significant net increases in emissions for certain pollutants. A settlement between Ohio Edison, the Federal EPA and other parties to the litigation will avoid further litigation and result in expenditures at its plant.
Management believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in the AEP case also vary widely from plant to plant.
In August 2003, the District Court for the Middle District of South Carolina issued a decision in a case pending against Duke Energy Corporation, a nonaffiliated utility. The District Court set forth the legal standards that will be applied at the trial in that case. The District Court determined that the Federal EPA bears the burden of proof on the issue of whether a practice is “routine maintenance, repair, or replacement” and on whether or not a “significant net emissions increase” results from a physical change or change in the method of operation at a utility unit. However, the Federal EPA must consider whether a practice is “routine within the relevant source category” in determining if it is “routine.” Further, the Federal EPA must calculate emissions by determining first whether a change in the maximum achievable hourly emission rate occurred as a result of the change, and then must calculate any change in annual emissions holding hours of operation constant before and after the change. The Federal EPA requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals. The District Court denied the Federal EPA’s motion. In April 2004, the parties filed a joint motion for entry of final judgment, based on stipulations of relevant facts that eliminated the need for a trial, but preserving plaintiffs’ right to seek an appeal of the federal prevention of significant deterioration (PSD) claims. On April 14, 2004, the Court entered final judgment for Duke Energy on all of the PSD claims made in the amended complaints, and dismissed all remaining claims with prejudice. The United States subsequently filed a notice of appeal to the Fourth Circuit Court of Appeals. The case is fully briefed and oral argument was heard in February 2005.
In June 2003, the United States Court of Appeals for the 11th Circuit issued an order invalidating the administrative compliance order issued by the Federal EPA to the Tennessee Valley Authority for alleged CAA violations. The 11th Circuit determined that the administrative compliance order was not a final agency action, and that the enforcement provisions authorizing the issuance and enforcement of such orders under the CAA are unconstitutional. The United States filed a petition for certiorari with the United States Supreme Court and on May 3, 2004, that petition was denied.
In June 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which the AEP subsidiaries are members, to reopen petitions for review of the 1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA claims in the AEP case and other related cases. On August 4, 2003, UARG filed a motion to separate and expedite review of their challenges to the 1980 and 1992 rulemakings from other unrelated claims in the consolidated appeal. The Circuit Court denied that motion on September 30, 2003. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by the Federal EPA in its utility enforcement actions. A decision by the D. C. Circuit Court could significantly impact further proceedings in the AEP case. Briefing continues in this case and oral argument was held in January 2005.
In December 2000, Cinergy Corp., a nonaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with the Federal EPA and other parties to settle litigation regarding generating plant emissions under the Clean Air Act. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy’s settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement’s impact on its jointly owned facilities and its future results of operations and cash flows.
In September 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power & Light Company in the United States District Court for the Southern District of Ohio alleging that violations of the PSD and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio state implementation plan occurred at the J.M. Stuart Station, and seeking injunctive relief and civil penalties. CSPCo owns a 26% share of the J.M. Stuart Station. The owners have filed a motion to dismiss portions of the complaint, based primarily upon the federal statute of limitations. In March 2005, in an unrelated case alleging new source review permitting claims against TVA, the court granted a motion to dismiss the claims against TVA on similar grounds. The owners have advised the court of this new decision. Management believes the allegations in the complaint are without merit, and intends to defend vigorously this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.
Management is unable to estimate the loss or range of loss related to any contingent liability for civil penalties under the CAA proceedings. Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If the AEP System companies do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity.
SWEPCo Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo
On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and Pirkey plants. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions.On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo will file a response to the complaint in May.
On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide.On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of $228,312 against SWEPCo based on alleged violations of certain representations regarding heat input and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the references to a specific heat input value for each Welsh unit.
On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant.On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty of $5,550 against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.
Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, financial condition or cash flows.
OPERATIONAL
Power Generation Facility - Affecting OPCo
AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP has subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.
Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 270 MW). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.
OPCo has also agreed to sell up to approximately 800 MW of energy to SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.) (TEM) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.
In September 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. OPCo alleges that TEM has breached the PPA, and is seeking a determination of OPCo’s rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of OPCo’s breaches. If the PPA is deemed terminated or found to be unenforceable by the court, OPCo could be adversely affected to the extent it is unable to find other purchasers of the power with similar contractual terms and to the extent OPCo does not fully recover claimed termination value damages from TEM. However, OPCo has entered an agreement with an affiliate that eliminates OPCo’s market exposure related to the PPA. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) has provided a limited guaranty.
In November 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted OPCo partial summary judgment on this issue, holding that the absences of operating protocols does not prevent enforcement of the PPA.
On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for these electric power products under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under PPA, (ii) would be seeking a declaration from the New York federal court that the PPA has been terminated and (iii) would be pursuing against TEM, and SUEZ-TRACTEBEL S.A. under the guaranty, damages and the full termination payment value of the PPA.
A bench trial was conducted in March and April 2005.
Merger Litigation-Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.
On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and will file a petition for review of this Initial Decision. The SEC will review the Initial Decision.
Enron Bankruptcy -Affecting APCo, CSPCo, I&M, KPCo and OPCo
In 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.
Enron Bankruptcy - Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas-related trading transactions. The AEP subsidiaries have asserted their right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. The parties are currently in nonbinding court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding court-sponsored mediation.
Enron Bankruptcy - Summary - The amount expensed in prior years in connection with the Enron bankruptcy was based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged the offsetting of receivables and payables. Although management is unable to predict the outcome of these lawsuits it is possible that their resolution could have an adverse impact on our results of operations, cash flows or financial condition.
Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC
Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP), filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003 against AEP and four of its subsidiaries, including TCC and TNC, certain nonaffiliated energy companies and ERCOT. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, sought leave to intervene as plaintiffs asserting similar claims. AEP and its subsidiaries filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. AEP and its subsidiaries filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit. In April 2005, the defendants filed a Motion to Stay this case, pending the outcome of the appeal in the TCE case.
Coal Transportation Dispute - Affecting PSO, TCC and TNC
PSO, TCC, TNC and two nonaffiliated entities, as joint owners of a generating station, have disputed transportation costs for coal received between July 2000 and the present time. The joint plant has remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded provisions for possible loss in December 2004 and the first quarter of 2005. The provisions were deferred as a regulatory asset under PSO’s fuel mechanism and affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.
6. GUARANTEES
There are certain immaterial liabilities recorded for guarantees in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
Letter of Credit
Certain Registrant Subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover insurance programs, security deposits, debt service reserves, and credit enhancements for issued bonds. All of these LOCs were issued in the subsidiaries’ ordinary course of business. At March 31, 2005, the maximum future payments of the LOCs include $44 million, $1 million, $51 million, $4 million and $43 million for CSPCo, I&M, OPCo, SWEPCo and TCC, respectively, with maturities ranging from November 2005 to April 2007. There is no recourse to third parties in the event these letters of credit are drawn.
SWEPCo
In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $51 million with maturity dates ranging from June 2005 to February 2012.
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by a third party miner. At March 31, 2005, the cost to reclaim the mine in 2035 is estimated to be approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.
SWEPCo consolidates Sabine due to the application of FIN 46. SWEPCo does not have an ownership interest in Sabine.
Indemnifications and Other Guarantees
Contracts
All of the Registrant Subsidiaries enter into certain types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Registrant Subsidiaries cannot estimate the maximum potential exposure for any of these indemnifications entered into prior to December 31, 2002 due to the uncertainty of future events. In 2004 and the first quarter of 2005, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary except for TCC which entered into an indemnification of $129 million relating to the sale of its generation assets in July 2004. There are no material liabilities recorded for any indemnifications.
Registrant Subsidiaries are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and for activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.
Master Operating Lease
Certain Registrant Subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the subsidiary has committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At March 31, 2005, the maximum potential loss by subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:
Maximum Potential Loss | |
Subsidiary | | (in millions) | |
| APCo | | $ | 5 | |
| CSPCo | | | 2 | |
| I&M | | | 3 | |
| KPCo | | | 1 | |
| OPCo | | | 5 | |
| PSO | | | 4 | |
| SWEPCo | | | 4 | |
| TCC | | | 6 | |
| TNC | | | 3 | |
7. DISPOSITIONS AND ASSETS HELD FOR SALE
DISPOSITIONS ANTICIPATED BEING COMPLETED DURING 2005
Texas Plants - Oklaunion Power Station
In January 2004, TCC signed an agreement to sell its 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to an unrelated party. In May 2004, TCC received notice from the two nonaffiliated co-owners of the Oklaunion Power Station, announcing their decision to exercise their right of first refusal, with terms similar to the original agreement. In June 2004 and September 2004, TCC entered into sales agreements with both of its nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. These agreements are currently being challenged in Dallas County, Texas State District Court by the unrelated party with which TCC entered into the original sales agreement. The unrelated party alleges that one co-owner has exceeded its legal authority and that the second co-owner did not exercise its right of first refusal in a timely manner. The unrelated party has requested that the court declare the co-owners’ exercise of their rights of first refusal void. TCC cannot predict when these issues will be resolved. TCC does not expect the sale to have a significant effect on its results of operations. TCC’s assets and liabilities related to the Oklaunion Power Station have been classified as Assets Held for Sale - Texas Generation Plants and Liabilities Held for Sale - Texas Generation Plants, respectively, in TCC’s Consolidated Balance Sheets at March 31, 2005 and December 31, 2004.
Texas Plants - South Texas Project
In February 2004, TCC signed an agreement to sell its 25.2% share of the STP nuclear plant to an unrelated party for approximately $333 million, subject to closing adjustments. In June 2004, TCC received notice from co-owners of their decisions to exercise their rights of first refusal, with terms similar to the original agreement. In September 2004, TCC entered into sales agreements with two of its nonaffiliated co-owners for the sale of TCC’s 25.2% share of the STP nuclear plant. TCC expects the sale to close in the second quarter of 2005. TCC’s assets and liabilities related to STP have been classified as Assets Held for Sale - Texas Generation Plants and Liabilities Held for Sale - Texas Generation Plants, respectively, in TCC’s Consolidated Balance Sheets at March 31, 2005 and December 31, 2004.
The assets and liabilities of the TCC plants held for sale at March 31, 2005 and December 31, 2004 are as follows:
| | | Texas Plants | |
| | | March 31, 2005 | | December 31, 2004 | |
Assets: | | (in millions) | |
| Other Current Assets | | $ | 25 | | $ | 24 | |
| Property, Plant and Equipment, Net | | | 416 | | | 413 | |
| Regulatory Assets | | | 52 | | | 48 | |
| Nuclear Decommissioning Trust Fund | | | 143 | | | 143 | |
Total Assets Held for Sale - Texas Generation Plants | | $ | 636 | | $ | 628 | |
| | | | | | | | |
Liabilities: | | | | | | | |
| Regulatory Liabilities | | $ | 1 | | $ | 1 | |
| Asset Retirement Obligations | | | 254 | | | 249 | |
Total Liabilities Held for Sale - Texas Generation Plants | | $ | 255 | | $ | 250 | |
8. BENEFIT PLANS
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees in the U.S.
The following tables provide the components of AEP’s net periodic benefit cost for the plans for the three months ended March 31, 2005 and 2004:
| | | Pension Plans | | Other Postretirement Benefit Plans | |
| | | 2005 | | 2004 | | 2005 | | 2004 | |
| | | (in millions) | |
| Service Cost | | $ | 23 | | $ | 22 | | $ | 11 | | $ | 10 | |
| Interest Cost | | | 56 | | | 56 | | | 27 | | | 29 | |
| Expected Return on Plan Assets | | | (77 | ) | | (72 | ) | | (23 | ) | | (20 | ) |
| Amortization of Transition (Asset) Obligation | | | - | | | - | | | 7 | | | 7 | |
| Amortization of Net Actuarial Loss | | | 13 | | | 4 | | | 7 | | | 9 | |
Net Periodic Benefit Cost (Credit) | | $ | 15 | | $ | 10 | | $ | 29 | | $ | 35 | |
The following table provides the net periodic benefit cost (credit) for the plans by the following Registrant Subsidiaries for the three months ended March 31, 2005 and 2004:
| | | Pension Plans | | Other Postretirement Benefit Plans | |
| | | 2005 | | 2004 | | 2005 | | 2004 | |
| | | (in thousands) | |
| APCo | | $ | 1,848 | | $ | 318 | | $ | 5,345 | | $ | 6,462 | |
| CSPCo | | | 534 | | | (407 | ) | | 2,222 | | | 2,765 | |
| I&M | | | 2,365 | | | 1,114 | | | 3,631 | | | 4,313 | |
| KPCo | | | 376 | | | 144 | | | 603 | | | 742 | |
| OPCo | | | 1,206 | | | (105 | ) | | 3,827 | | | 4,801 | |
| PSO | | | 72 | | | 700 | | | 1,869 | | | 2,110 | |
| SWEPCo | | | 364 | | | 901 | | | 1,837 | | | 2,101 | |
| TCC | | | (219 | ) | | 746 | | | 2,008 | | | 2,535 | |
| TNC | | | 41 | | | 338 | | | 877 | | | 1,073 | |
9. BUSINESS SEGMENTS
All of AEP’s Registrant Subsidiaries have one reportable segment. The one reportable segment is a vertically integrated electricity generation, transmission and distribution business except AEGCo, an electricity generation business. All of the registrants’ other activities are insignificant. The registrant subsidiaries’ operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on the business process, cost structures and operating results.
10. FINANCING ACTIVITIES
Long-term debt and other securities issued, retired and principal payments made during the first three months of 2005 were:
Company | | Type of Debt | | Principal Amount | | Interest Rate | | Due Date |
| | | | | (in thousands) | | (%) | | |
Issuances: | | | | | | | | | |
| APCo | | Senior Unsecured Notes | | $ | 200,000 | | 4.95% | | 2015 |
| OPCo | | Installment Purchase Contracts | | | 54,500 | | Variable | | 2029 |
| OPCo | | Installment Purchase Contracts | | | 163,500 | | Variable | | 2028 |
| TCC | | Installment Purchase Contracts | | | 161,700 | | Variable | | 2030 |
Company | | Type of Debt | | Principal Amount | | Interest Rate | | Due Date |
| | | | | (in thousands) | | (%) | | |
Retirements and Principal Payments: | | | | | | | | | |
| APCo | | Other Debt | | $ | 2 | | 13.718% | | 2026 |
| OPCo | | Installment Purchase Contracts | | | 102,000 | | 6.375% | | 2029 |
| OPCo | | Installment Purchase Contracts | | | 80,000 | | Variable | | 2028 |
| OPCo | | Installment Purchase Contracts | | | 36,000 | | Variable | | 2029 |
| OPCo | | Notes Payable | | | 1,463 | | 6.81% | | 2008 |
| OPCo | | Notes Payable | | | 3,250 | | 6.27% | | 2009 |
| SWEPCo | | Notes Payable | | | 1,707 | | 4.47% | | 2011 |
| SWEPCo | | Notes Payable | | | 750 | | Variable | | 2008 |
| TCC | | Senior Unsecured Notes | | | 150,000 | | 3.00% | | 2005 |
| TCC | | Senior Unsecured Notes | | | 100,000 | | Variable | | 2005 |
| TCC | | Securitization Bonds | | | 29,386 | | 3.54% | | 2005 |
During the first quarter of 2005, there were no intercompany issuances and retirements of debt due to affiliates.
Other Matters
On January 3, 2005, the following outstanding shares of preferred stock were redeemed:
Company | | Series | | Number of Shares Redeemed | | Amount | |
| | | | | | | (in millions) | |
| I&M | | 5.900% | | 132,000 | | $ | 13 | |
| I&M | | 6.250% | | 192,500 | | | 19 | |
| I&M | | 6.875% | | 157,500 | | | 16 | |
| I&M | | 6.300% | | 132,450 | | | 13 | |
| OPCo | | 5.900% | | 50,000 | | | 5 | |
| | | | | | | $ | 66 | |
Lines of Credit - AEP System
The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, the AEP System also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The AEP System Corporate Borrowing Program operates in accordance with the terms and conditions outlined by the SEC. AEP has authority from the SEC through March 31, 2007 for short-term borrowings sufficient to fund the Utility Money Pool and the Nonutility Money Pool as well as its own requirements in an amount not to exceed $7.2 billion. The Utility Money Pool participants’ money pool activity and corresponding SEC authorized limits for the quarter ended March 31, 2005 are described in the following table:
Company | | Maximum Borrowings from Utility Money Pool | | Maximum Loans to Utility Money Pool | | Average Borrowings from Utility Money Pool | | Average Loans to Utility Money Pool | | Loans (Borrowings) to/from Utility Money Pool as of March 31, 2005 | | SEC Authorized Short-Term Borrowing Limit | |
| | | (in thousands) | |
| AEGCo | | $ | 45,694 | | $ | - | | $ | 14,635 | | $ | - | | $ | (7,131 | ) | $ | 125,000 | |
| APCo | | | 236,798 | | | 43,410 | | | 98,844 | | | 20,228 | | | 29,054 | | | 600,000 | |
| CSPCo | | | - | | | 181,238 | | | - | | | 140,718 | | | 59,416 | | | 350,000 | |
| I&M | | | 96,437 | | | 11,768 | | | 29,964 | | | 5,797 | | | (95,967 | ) | | 500,000 | |
| KPCo | | | - | | | 35,779 | | | - | | | 24,411 | | | 24,734 | | | 200,000 | |
| OPCo | | | - | | | 182,495 | | | - | | | 115,400 | | | 41,407 | | | 600,000 | |
| PSO | | | 55,009 | | | - | | | 21,550 | | | - | | | (39,588 | ) | | 300,000 | |
| SWEPCo | | | - | | | 68,537 | | | - | | | 51,062 | | | 40,033 | | | 350,000 | |
| TCC | | | 238,693 | | | 120,937 | | | 78,646 | | | 49,350 | | | (238,693 | ) | | 600,000 | |
| TNC | | | - | | | 75,045 | | | - | | | 48,416 | | | 52,736 | | | 250,000 | |
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the quarter ended March 31, 2005 were 2.96% and 1.63%, respectively. The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the quarter ended March 31, 2005 are summarized for all Registrant Subsidiaries in the following table:
Company | | Average Interest Rate for Funds Borrowed from the Utility Money Pool | | Average Interest Rate for Funds Loaned to the Utility Money Pool | |
| | | (in percentages) | |
| AEGCo | | | 2.00 | | | - | |
| APCo | | | 1.96 | | | 2.15 | |
| CSPCo | | | - | | | 2.10 | |
| I&M | | | 2.14 | | | 2.12 | |
| KPCo | | | - | | | 2.15 | |
| OPCo | | | - | | | 2.14 | |
| PSO | | | 2.11 | | | - | |
| SWEPCo | | | - | | | 2.13 | |
| TCC | | | 2.27 | | | 2.12 | |
| TNC | | | - | | | 2.14 | |
COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a combined presentation of certain components of the management’s discussion and analysis of Registrant Subsidiaries. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and results of operations and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, and (iii) footnotes of each individual registrant. The Combined Management’s Discussion and Analysis of Registrants Subsidiaries section of the 2004 Annual Report should be read in conjunction with this report.
Significant Factors
FERC Order on Regional Through and Out Rates
A load-based transitional transmission rate mechanism called SECA became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. Billing statements from PJM for the first quarter of 2005 did not reflect any credits to AEP for SECA revenues. Based upon the SECA transition rate methodology approved by the FERC, AEP accrued $26 million of SECA revenue in the first quarter of 2005 and has a receivable for SECA revenues of $37 million at March 31, 2005. SECA billings by PJM crediting AEP for their SECA revenue are scheduled to begin in May 2005 with retroactive adjustments to be billed by PJM in June and July 2005.
The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA transition rates was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be sufficient to replace the SECA transition rate revenues and whether the new rates will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, if AEP zonal rates are not sufficiently increased by the FERC after March 31, 2006, or if any increase in the AEP East companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.
Ohio Regulatory Activity
Ohio Restructuring
In January 26, 2005 the PUCO approved Rate Stabilization Plans for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for up to 4% of additional annual generation rate increases based on supporting the need for additional revenues. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM RTO costs from 2004 and 2005 related to their obligation as the Provider of Last Resort in Ohio’s customer choice program. First quarter of 2005 pretax earnings were increased by $13 million for CSPCo and $32 million for OPCo as a result of implementing this provision of the Rate Stabilization Plans. Of these amounts approximately $8 million for CSPCo and $21 for OPCo relate to 2004 environmental carrying costs and RTO costs.
IGCC Plant
On March 18, 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposes cost recovery associated with the IGCC plant in three phases. In Phase 1, the Ohio companies would recover approximately $18 million in pre-construction costs during 2006. In Phase 2, the Ohio companies would recover approximately $237 million in construction financing costs from 2007 through mid-2010 when the plant is projected to be placed in commercial operation. The proposed recoveries in Phases 1 and 2 will be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008, under their Rate Stabilization Plans. In Phase 3, which begins when the plant enters commercial operation, projected to be in mid-2010, the Ohio companies would recover the projected $1.0 billion cost of the plant and a return on the unrecovered cost over its operating life along with fuel, replacement power and operation and maintenance costs.
Litigation
Registrant Subsidiaries continue to be involved in various litigation matters as described in the “Significant Factors - Litigation” section of the Combined Management’s Discussion and Analysis of Registrant Subsidiaries in the 2004 Annual Report. The 2004 Annual Report should be read in conjunction with this report in order to understand other litigation matters that did not have significant changes in status since the issuance of the 2004 Annual Report, but may have a material impact on future results of operations, cash flows and financial condition. Other matters described in the 2004 Annual Report that did not have significant changes during the first quarter of 2005, that should be read in order to gain a full understanding of the current litigation include disclosure related to Coal Transportation Dispute and Potential Uninsured Losses.
Federal EPA Complaint and Notice of Violation
See discussion of New Source Review Litigation under “Environmental Matters”.
Enron Bankruptcy
In 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.
In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. AEP has asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. The parties are currently in nonbinding court-sponsored mediation.
In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding court-sponsored mediation.
The amounts expensed in prior years in connection with the Enron bankruptcy were based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged the offsetting of receivables and payables. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on results of operations, cash flows or financial condition.
Merger Litigation
In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.
On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and will file a petition for review of this Initial Decision. The SEC will review the Initial Decision.
Texas Commercial Energy, LLP Lawsuit
Texas Commercial Energy, LLP (TCE), a Texas Retail Electric Provider (REP), filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against AEP and four of its subsidiaries, including TCC and TNC, certain nonaffiliated energy companies and ERCOT. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against TCC and TNC, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as plaintiffs asserting similar claims. AEP and its subsidiaries filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. AEP and its subsidiaries filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against AEP and its subsidiaries. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit.
Environmental Matters
As discussed in the 2004 Annual Report, there are emerging environmental control requirements that management expects will result in substantial capital investments and operational costs. The sources of these future requirements include:
| · | Legislative and regulatory proposals to adopt stringent controls on sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from coal-fired power plants, |
| · | Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and |
| · | Possible future requirements to reduce carbon dioxide emissions to address concerns about global climatic change. |
This discussion updates certain events occurring in 2005. You should also read the “Significant Factors - Environmental Matters” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries in the 2004 Annual Report for a description of all environmental matters affecting us, including, but not limited to, (1) the current air quality regulatory framework, (2) estimated air quality environmental investments, (3) the Comprehensive Environmental Response Compensation and Liability Act (Superfund) and state remediation, (4) global climate change, (5) carbon dioxide public nuisance claims, (6) costs for spent nuclear fuel disposal and decommissioning, and (7) Clean Water Act regulation.
Future Reduction Requirements for SO2, NOx, and Mercury
Regulatory Emissions Reductions
In January 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% each in emissions of SO2, NOx and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:
| · | The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce SO2 and NOx emissions across the Eastern United States (29 states and the District of Columbia) and make progress toward attainment of the new fine particulate matter and ground-level ozone national ambient air quality standards. These reductions could also satisfy these states’ obligations to make reasonable progress towards the national visibility goal under the regional haze program. |
| · | The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units. |
On March 14, 2005, the Administrator of the Federal EPA signed the final CAIR. The rule is slightly revised from the proposed version released in January 2004, and includes both a seasonal and annual NOx control program as well as an annual SO2 control program. All of the states in which theRegistrant Subsidiaries’ generating facilities are located will be subject to the regional and annual NOx control programs and the annual SO2 control program, except for Texas, Oklahoma and Arkansas. Texas will be subject to the annual programs only. Arkansas will be subject to the seasonal NOx control program only. Oklahoma is not affected by CAIR. In addition, the compliance deadline for Phase I for the NOx control program has been accelerated to 2009, and will replace any obligations imposed by the NOx State Implementation Plan (SIP) Call in 2009.
On March 15, 2005, the Administrator of the Federal EPA signed a final Clean Air Mercury Rule (CAMR) that will permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. The final CAMR imposes a national cap on mercury emissions from coal-fired power plants of 38 tons by 2010 and 15 tons by 2018.
The changes in the Federal EPA’s final CAIR and CAMR have not caused us to revise our estimates of the capital investments necessary to achieve compliance with these requirements. However, final rules give states substantial discretion in developing their rules to implement these cap-and-trade programs, and states will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. As a result, the ultimate requirements may not be known for several years and may depart significantly from the original proposed rules described here. If states elect not to participate in the federal cap-and-trade programs, or elect to impose additional requirements on individual units that are already subject to CAIR and/or the CAMR, our costs could increase significantly. The cost of compliance could have an adverse effect on future results of operations, cash flows and financial condition unless recovered from customers.
New Source Review Litigation
Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.
The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The Court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at the generating units over a 20-year period.
On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. The Federal EPA and the states each have filed an additional complaint alleging violations of the new source review requirements at units at the Amos and Conesville plants that were not allowed to be added to the pending case. These separate complaints have been assigned to the same judge in the Southern District Court.
In September 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA in the U.S. District Court for the Southern District of Ohio alleging that violations of the prevention of significant deterioration and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio SIP occurred at the J.M. Stuart Station, and seeking injunctive relief and civil penalties. Stuart Station is jointly owned by CSPCo (26%) and two nonaffiliated utilities. The owners have filed a motion to dismiss portions of the complaint, based primarily upon the federal statute of limitations. In March 2005, in an unrelated case alleging new source review permitting claims against the Tennessee Valley Authority (TVA), the court granted a motion to dismiss the claims against TVA on similar grounds. The owners have advised the court of this new decision. Management believes the allegations in the complaint are without merit, and intends to defend vigorously this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.
Management is unable to estimate the loss or range of loss related to any contingent liability the AEP subsidiaries might have for civil penalties under the CAA proceedings. Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If the AEP subsidiaries do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity.
SWEPCo Notice of Enforcement and Notice of Citizen Suit
On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and Pirkey plants. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo will file a response to the complaint in May.
On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of $228,312 against SWEPCo based on alleged violations of certain representations regarding heat input and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the references to a specific heat input value for each Welsh unit.
On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant.On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty $5,550 against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.
Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, cash flows or financial condition.
Emergency Release Reporting
Superfund requires immediate reporting to the Federal EPA for releases of hazardous substances to the environment above the identified reportable quantity (RQ). The Environmental Planning and Community Right-to-Know Act (EPCRA) requires immediate reporting of releases of hazardous substances that cross property boundaries of the releasing facility.
On July 27, 2004, the Federal EPA Region 5 issued an Administrative Complaint related to alleged failure of I&M to immediately report under Superfund and EPCRA a November 2002 release of sodium hypochlorite from the Cook Plant. The Federal EPA's Complaint seeks an immaterial amount of civil penalties. I&M has requested a hearing and raised several defenses to the claim, including federally permitted release exemption from reporting. Negotiations on the penalty amount are continuing.
On December 21, 2004, the Federal EPA notified OPCo of its intent to file a Civil Administrative Complaint, alleging one violation of Superfund reporting obligations and two violations of EPCRA for failure to timely report a June 2004 release of an RQ amount of ammonia from OPCo’s Gavin Plant SCR system. The Federal EPA indicated its intent to seek civil penalties. In February 2005, OPCo provided relevant information that the Federal EPA should consider in advance of any filing.
CONTROLS AND PROCEDURES
During the first quarter of 2005, management, including the principal executive officer and principal financial officer of AEP, AEGCo, 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 Exchange 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 Exchange 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 March 31, 2005, 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.
There was no 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 first quarter of 2005 that materially affected, or is reasonably likely to materially affect, AEP’s internal controls over financial reporting.
PART II. OTHER INFORMATION
Item 1.Legal Proceedings
For a discussion of material legal proceedings, see Note 5,Commitments and Contingencies,incorporated herein by reference.
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases by AEP (or its publicly-traded subsidiaries) during the quarter ended March 31, 2005 of equity securities that are registered by AEP (or its publicly-traded subsidiaries) pursuant to Section 12 of the Exchange Act:
ISSUER PURCHASES OF EQUITY SECURITIES
Period | | Total Number of Shares Purchased (a) | | Average Price Paid per Share | | Total Number Of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs | |
| 01/01/05 - 01/31/05 | | | - | | $ | - | | | - | | $ | - | |
| 02/01/05 - 02/28/05 | | | - | | | - | | | - | | | (b | ) |
| 03/01/05 - 03/31/05 | | | 12,500,000 | | | 34.63 | | | 12,500,000 | | | - | |
Total | | | 12,500,000 | | $ | 34.63 | | | 12,500,000 | | $ | (b | ) |
| (a) | The repurchase was funded with available cash on hand. |
| (b) | In February 2005, AEP’s board of directors authorized the repurchase of outstanding common shares of AEP up to an aggregate purchase price of $500 million. |
On March 9, 2005, AEP announced the repurchase of 12.5 million shares of its outstanding common stock through an accelerated share repurchase agreement at an initial price of $34.63 per share, for a total of approximately $433 million. The 12.5 million shares repurchased under the program are subject to a future contingent purchase price adjustment based on the actual purchase prices paid for the common stock during the program period which ends in May 2005.
As of April 29, 2005, the counterparty to the agreement had repurchased 95.2% of the shares under the program at an average price per share of approximately $34.12. Assuming the counterparty repurchased the remaining shares at a price per share of $35.22, which was the closing price of AEP’s common stock on April 29, 2005, AEP would receive a payment of approximately $5.7 million from the counterparty (excluding expenses and related items). The settlement amount can increase or decrease depending upon the actual price paid for the shares repurchased by the counterparty under the program. The settlement is expected to occur in May 2005.
Item 5.Other Information
NONE
Item 6.Exhibits
AEP
4(a) - - Purchase Agreement dated as of March 8, 2005, between AEP and Merrill Lynch International.
10(b) - AEP Retainer Deferral Plan for Non-Employee Directors’ effective January 1, 2005, as amended March 10, 2005(previously known as AEP Deferred Compensation and Stock Plan for Non-Employee Directors).
31(a) - Certification of AEP Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(c) - Certification of AEP Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
AEP, APCo, OPCo
10(a) - Form of Restricted Stock Unit Agreement furnished to participants of the AEP System 2000 Long-term Incentive Plan, as amended.
AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
12 - Computation of Consolidated Ratio of Earnings to Fixed Charges.
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
31(b) - Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(d) - Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
32(a) - Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
32(b) - Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
AEP GENERATING COMPANY
AEP TEXAS CENTRAL COMPANY
AEP TEXAS NORTH COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: May 4, 2005
