American Electric Power Company, Inc. — 2012 Q2 Form 10-Q
Business context and period. AEP is an electric utility holding company whose principal business is generation, transmission and distribution. This combined, unaudited filing covers the quarter and six months ended June 30, 2012, and also includes separate financial information for five registered utility subsidiaries. Comparisons below are with the corresponding 2011 periods.
Key financial results
| Metric | Q2 2012 | Q2 2011 | Six months 2012 | Six months 2011 |
|---|---|---|---|---|
| Total revenue | $3.551 billion | $3.609 billion | $7.176 billion | $7.339 billion |
| Operating income | $741 million | $717 million | $1.495 billion | $1.549 billion |
| Net income | $363 million | $353 million | $753 million | $708 million |
| Net income attributable to AEP shareholders | $362 million | $352 million | $751 million | $706 million |
| Basic and diluted EPS | $0.75 | $0.73 | $1.55 | $1.46 |
| Cash dividends declared per share | $0.47 | $0.46 | $0.94 | $0.92 |
- Revenue declined about 2% year over year in both the quarter and first half. First-half operating income fell about 3%, while net income rose about 6%.
- Utility Operations gross margin was $2.162 billion in Q2 versus $2.158 billion; first-half gross margin was $4.278 billion versus $4.385 billion. The filing defines this measure as revenue less fuel and purchased electricity costs.
- Cash from operating activities was $1.713 billion for the first half, compared with $1.732 billion. Investing used $1.530 billion, including $1.371 billion of construction expenditures; financing used $107 million. Cash ended the period at $297 million, up from $221 million at year-end 2011.
- At June 30, total debt was $18.510 billion, compared with $18.166 billion at year-end 2011; debt was 55.2% of total capitalization, versus 55.3%. Long-term debt, including amounts due within one year, was $17.302 billion.
- Net available liquidity was approximately $2.830 billion, including $3.250 billion in credit facilities and $297 million of cash, less commercial paper and letters of credit. AEP reported compliance with its debt covenants.
Material changes and drivers
- Consolidated net income increased by $10 million in Q2 and $45 million for the first half. Lower operation and maintenance costs and favorable Ohio fuel-adjustment-related reversals contributed. The first-half comparison also benefited from reversal of a $35 million obligation after the PUCO rejected a prior Ohio stipulation.
- Ohio retail competition remained a material headwind: AEP reported 34% of its Ohio load had shifted to competitive suppliers. The company estimated lost gross margin of $56 million in Q2 and $99 million in the first half; subsidiary-level figures differ because of reporting scope.
- First-half utility gross margin declined primarily with Ohio customer switching, milder winter weather and the end of Ohio POLR charges. Transmission revenue and rate increases offset part of those effects. Lower maintenance and other operating expenses partly offset higher depreciation.
- Generation and Marketing reported a $5 million Q2 loss, versus $11 million income, and a $6 million first-half loss, versus $12 million income. Management cited expired wind production tax credits and lower trading margins.
Outlook, risks and unusual items
- Guidance: The filing does not provide a clear consolidated full-year earnings or revenue forecast. Management said interim results are not necessarily indicative of full-year results.
- Storm costs: Severe late-June and early-July storms were expected to cause about $230 million of AEP-system restoration costs in Q3, including $160 million of incremental operating and maintenance costs. AEP intended to defer most of those costs and seek recovery; recovery was not assured.
- Ohio regulation and restructuring: A new 2012–2015 Electric Security Plan was pending, with an August 2012 PUCO decision expected. A July capacity order directed OPCo to charge the low Reliability Pricing Model price and allowed limited deferral of unrecovered costs; OPCo sought rehearing. The proposed plan also seeks recovery of a $538 million net phase-in fuel deferral. OPCo’s proposed generation separation could expose generation earnings to market prices, and the Interconnection Agreement was scheduled for termination effective December 31, 2013, subject to FERC action.
- Rate cases and cost recovery: I&M sought a $149 million annual Indiana rate increase, with a decision expected in Q4 2012; SWEPCo filed in July for an $83 million annual Texas increase. West Virginia utilities planned to seek securitization of about $400 million of deferred energy costs. Regulatory decisions could affect recovery of fuel, capacity, storm, environmental and other costs.
- Capital projects and environmental exposure: System environmental investment was estimated at $6–$7 billion from 2012–2020. AEP had notified RTOs of intended retirements totaling about 4,606 MW by or during 2016. SWEPCo’s 600 MW Turk Plant was scheduled for Q4 2012 service, with substantial capital committed and recovery subject to regulatory caps and pending challenges. I&M’s proposed Cook Plant life-cycle project was estimated at $1.2 billion through 2018.
- Unusual items: AEP recorded a $13 million Q2 charge for the first phase of workforce reductions, covering about 170 positions; further savings and costs were not quantified. OPCo recorded a $30 million favorable Q2 adjustment related to the 2009 fuel audit. SWEPCo recorded a $13 million Q2 impairment charge for expected Turk Plant costs above the Texas capital-cost cap.
- Other significant risks: Environmental rules and litigation, potential coal-unit closures, nuclear safety and Cook Plant Unit 1 recovery, Ohio refunds and fuel-audit outcomes, and the ability to recover regulatory assets could adversely affect results and cash flows. Management could not quantify potential losses for certain legal and environmental matters.
Important facts for investors to verify
- Whether the PUCO approved OPCo’s proposed ESP and how the capacity-price order affects actual cost recovery and Ohio margins.
- Actual storm restoration spending, amounts deferred, and regulatory approval for recovery.
- Progress and final cost/recovery terms for Turk Plant, Cook Plant life-cycle investments, and environmental compliance spending.
- Whether Ohio customer switching, weather, and transmission revenues continue to offset or exacerbate utility margin pressure.
- Debt maturities, liquidity availability, and the cash-flow impact of construction spending, dividends, and securitizations.