AMERICAN ELECTRIC POWER CO INC quarterly report, Q2 FY2011

American Electric Power Company, Inc. — Form 10-Q Summary

Reporting period: Quarter and six months ended June 30, 2011. Filed July 29, 2011. The combined filing also covers six AEP utility subsidiaries; figures below are primarily for AEP consolidated unless otherwise noted. Financial statements are unaudited.

Financial results and liquidity

Metric	Q2 2011	Q2 2010	Six months 2011	Six months 2010
Total revenue	$3.609 billion	$3.360 billion	$7.339 billion	$6.929 billion
Operating income	$717 million	$394 million	$1.549 billion	$1.152 billion
Net income	$353 million	$137 million	$708 million	$483 million
Earnings attributable to AEP common shareholders	$352 million; $0.73/share	$136 million; $0.28/share	$705 million; $1.46/share	$480 million; $1.00/share

Utility Operations gross margin was $2.159 billion in Q2, versus $2.101 billion; for the first half it was $4.386 billion, versus $4.280 billion. Management cited rate proceedings and higher off-system sales and transmission revenues, partly offset by Ohio customer switching and other factors.
Operating cash flow for the first half was $1.732 billion, compared with $582 million. Investing used $1.280 billion, including $1.113 billion of construction expenditures. Financing used $329 million; common dividends paid were $446 million.
At June 30, total debt was $18.274 billion: $16.635 billion long-term debt, including current maturities, and $1.639 billion short-term debt. Debt was 56.6% of total capitalization, compared with 57.0% at year-end 2010; AEP common equity was $13.939 billion.
Cash and cash equivalents were $417 million. Net available liquidity, including credit facilities and cash after commercial paper and letters of credit, was approximately $2.295 billion. AEP reported compliance with credit covenants; its contract-defined debt-to-capital ratio was 52.3% against a 67.5% limit.
The board declared a quarterly dividend of $0.46 per share in July 2011, up from $0.42 per share in the prior-year quarter.

Material changes and unusual items

Reported earnings rose substantially year over year, but the main driver was comparison with $293 million of cost-reduction charges in Q2 2010, equivalent to $185 million net of tax. The 2011 first-half results also include a $22 million after-tax loss from the February settlement of BOA/Enron litigation, despite a $51 million pretax settlement gain, principally due to a tax valuation allowance.
First-half operating cash flow increased by $1.150 billion year over year. The comparison is affected by 2010 accounting for securitized receivables, which included a $656 million increase in receivables under changed accounting guidance.
Ohio customer choice reduced generation-related gross margin by approximately $24 million in Q2 and $43 million in the first half versus 2010. Management expected to recover part of the lost margin through off-system sales, including PJM capacity revenues.
In July 2011, the Texas Supreme Court reversed the denial of TCC’s approximately $420 million capacity-auction true-up recovery, plus interest from 2002; recovery remains subject to a PUCT remand proceeding.

Outlook, regulation, risks and contingencies

No consolidated earnings or EPS guidance is provided in the supplied filing text. Management said results for the interim period are not necessarily indicative of full-year results.
Ohio’s 2012–May 2014 generation plan was pending. Proposed average base generation increases were 1.4% in 2012 and 2.7% in 2013. Separate distribution rate increases and recovery of regulatory assets were also requested. Outcomes could be affected by court and commission proceedings.
Ohio intervenors proposed reducing CSPCo/OPCo deferred fuel and other regulatory assets by up to $634 million, excluding carrying costs, and refunds or rate reductions of up to $153 million. Management disputed the proposals; hearings had occurred, but outcomes were unresolved.
SWEPCo’s 600 MW Turk coal plant was expected in service in 2012. A preliminary injunction restricting certain wetlands- and water-related work was upheld in July 2011; some litigation continued. Management expected completion, but inability to complete the project or recover its investment could materially affect earnings, cash flows and financial condition.
AEP estimated system-wide environmental compliance investment of approximately $6–$8 billion for 2012–2020. The company identified up to 5,856 MW of units that could retire before 2015, subject to changing rules and other assumptions. A separate estimate for proposed coal-combustion-residual requirements was as high as $3.9 billion system-wide under one regulatory alternative.
Other material uncertainties include recovery of Cook Plant Unit 1 repair costs (estimated up to $408 million; $203 million in NEIL insurance payments received through June), future nuclear safety requirements, fuel and rate proceedings, and environmental and other litigation. Management could not estimate reasonably possible losses for certain CO₂ claims.
In July 2011, AEP extended or replaced revolving credit facilities, and AEP Credit renewed its receivables securitization agreement. These post-quarter changes support liquidity but do not eliminate funding, refinancing or interest-rate risks.

Most important facts for investors to verify

How much of the earnings increase reflects sustainable rate and operating improvement versus the unusually large 2010 cost-reduction charge.
The outcome and potential financial impact of the Ohio ESP remand, proposed refunds, deferred fuel recovery and pending rate cases.
Whether the Turk plant can be completed on schedule and within recoverable cost limits, given the injunction and remaining permit challenges.
The timing, recoverability and funding implications of AEP’s environmental investment plans and potential generation retirements.
Whether the strong first-half operating cash flow is repeatable, considering working-capital movements and the prior-year receivables-accounting comparison.