AMERICAN ELECTRIC POWER CO INC quarterly report, Q3 FY2009

Business context and reporting period

American Electric Power Company, Inc. (AEP) filed this unaudited Form 10-Q for the quarter and nine months ended September 30, 2009. AEP is an electric utility holding company; regulated electric generation, transmission and distribution are its principal business. The combined filing also includes separate reports for six utility subsidiaries.

Key financial metrics

• Utility margins: Nine-month Utility Operations gross margin increased to $6.375 billion from $6.147 billion; segment income before discontinued operations and extraordinary loss rose to $1.121 billion from $1.036 billion.
• Cash and investment: Nine-month investing cash outflow was $2.097 billion, mainly reflecting $2.123 billion in construction expenditures. Financing provided $692 million. Cash and cash equivalents at September 30 were $877 million, up from $411 million at year-end 2008.
• Debt and capitalization: Total debt was $17.605 billion, versus $17.959 billion at December 31, 2008. Debt represented 57.3% of total capitalization, down from 62.5%, mainly following AEP’s April 2009 equity issuance and debt repayment.
• Liquidity: Net available liquidity was approximately $3.641 billion, including $3.581 billion of credit facilities, after commercial paper and letters of credit; AEP also reported $877 million of cash. The sale-of-receivables commitment was increased to $750 million and expires in July 2010.
• Margins: Nine-month utility revenue declined to $9.712 billion from $10.575 billion, while fuel and purchased-power costs fell to $3.337 billion from $4.428 billion. Utility gross margin therefore increased despite lower revenue.

Material changes versus the prior comparable period

• Third-quarter AEP shareholder earnings increased $69 million, while nine-month earnings declined $109 million. Nine-month EPS fell to $2.47 from $3.06, in part because the 2008 period included $164 million of after-tax income from the TEM litigation settlement.
• Utility Operations earnings improved year over year in both periods, principally due to rate increases and Ohio fuel-cost deferrals. These benefits were partly offset by lower retail volumes and weaker off-system sales margins.
• Off-system sales volumes fell 58% for the AEP System in the first nine months. Total system electricity sales were 147.590 billion KWH, down from 170.285 billion; retail sales fell to 125.357 billion from 134.381 billion. Industrial KWH sales declined 17%.
• Common shares outstanding increased following the April issuance of 69 million shares for $1.64 billion in net proceeds. The issuance helped repay borrowings and reduced the reported debt-to-capital ratio, but increased the weighted-average share count.
• Operating cash flow declined by $188 million, with management citing lower net income and cash tied up in higher fuel inventory and under-recovered fuel costs. Investing cash outflow was lower than in 2008, while construction spending remained substantial.

Outlook, management commentary, risks and unusual items

• Demand and pricing: Management described residential and commercial sales as relatively stable, but reported economic weakness in parts of the service territory, reduced industrial demand, lower wholesale power prices and weaker off-system sales margins. Ormet planned to continue operating at a reduced load of about 330 MW through year-end 2009.
• Rates and recovery: Ohio ESP rates run through 2011, with capped increases and fuel-cost deferrals recoverable through customer surcharges from 2012 to 2018. At September 30, the reported FAC deferrals were $36 million for CSPCo and $238 million for OPCo. Reviews, prudency audits, excessive-earnings tests and legal challenges could affect recovery.
• Projects and capital: AEP revised its 2010 Utility Operations capital budget to $1.993 billion, primarily due to expenditures shifted from 2009. SWEPCo’s 600 MW Turk coal plant was estimated to cost about $1.6 billion excluding AFUDC; construction faced Arkansas certification and air-permit appeals, as well as other permitting risks. Management expected completion, but cancellation or delayed approvals could materially affect results and cash flows. The 500 MW Stall gas unit was estimated at $435 million and expected in service in mid-2010.
• Pension funding: Estimated 2010 contributions to qualified and nonqualified pension plans fell to $62 million from a previously disclosed $453 million estimate; the 2011 estimate was $389 million. Management cautioned that these estimates can change materially.
• Cook Plant outage: I&M’s Cook Unit 1 remained out of service after a 2008 turbine failure and fire. Repair and replacement costs could reach about $330 million. I&M had recorded $122 million of insurance recoverables and received $72 million in property-insurance payments; it also recognized $145 million of accidental-outage insurance revenue in 2009, of which $59 million reduced customer bills. An unsuccessful repair, uncovered costs or adverse regulatory treatment could harm results.
• Regulatory and legal exposure: AEP disclosed climate-change nuisance litigation, multiple rate and fuel-recovery proceedings, environmental compliance spending, and other contingencies. AEP had recorded a $439 million liability related to the Bank of America litigation. Outcomes and additional exposures may differ from management estimates.
• Credit and counterparties: AEP reported $886 million of net risk-management credit exposure, with approximately 88% to investment-grade counterparties. AEP’s senior unsecured ratings were Baa2/BBB/BBB; Moody’s had placed AEP on negative outlook. A downgrade could increase funding costs or require collateral.
• Guidance: The filing does not provide a clear full-year earnings or EPS forecast. Management said typical near-term commodity-price movements were not expected to materially affect results based on its VaR analysis, while warning that actual market prices, counterparties and longer-dated contracts could produce materially different outcomes.

Important facts for investors to verify

• Whether reported earnings and EPS comparisons adequately distinguish recurring utility performance from the 2008 TEM settlement and 2009 outage-insurance and regulatory-deferral effects.
• Whether Ohio fuel-cost deferrals and other regulatory assets will be approved, recovered on schedule, and unaffected by audits, appeals or excessive-earnings reviews.
• The status, total expected cost, permit approvals, construction schedule and rate recovery for the Turk and Stall projects.
• Actual fuel inventories, under-recovered fuel balances and the related impact on operating cash flow as demand and coal deliveries adjust.
• Cook Unit 1’s return-to-service progress and the ultimate allocation of repair, replacement-power and insurance costs.
• 2010 debt maturities, refinancing plans, credit-rating developments, and the amount and timing of pension contributions.