American Electric Power Company, Inc. — 2012 Q3 Form 10-Q
Reporting period: Three and nine months ended September 30, 2012. This combined filing also reports five regulated utility subsidiaries; figures below primarily summarize AEP consolidated unless otherwise noted. Financial statements are unaudited.
Financial performance
| Metric | Q3 2012 | Q3 2011 | Nine months 2012 | Nine months 2011 |
|---|---|---|---|---|
| Total revenue | $4.156 billion | $4.333 billion | $11.332 billion | $11.672 billion |
| Operating income | $912 million | $890 million | $2.407 billion | $2.439 billion |
| Income before extraordinary item | $488 million | $657 million | $1.241 billion | $1.365 billion |
| Net income attributable to AEP shareholders | $487 million | $929 million | $1.238 billion | $1.635 billion |
| Basic EPS before extraordinary item | $1.00 | $1.35 | $2.55 | $2.82 |
| Utility Operations gross margin | $2.438 billion | $2.465 billion | $6.716 billion | $6.850 billion |
2011 net income included a $273 million after-tax extraordinary gain related to a Texas capacity-auction true-up. Excluding that item, AEP’s income before extraordinary item declined about 26% in Q3 and 9% for the first nine months. Lower Ohio retail margins, weaker weather-related usage and lower carrying-cost income were important pressures. Nine-month utility retail energy sales were 131.2 billion kWh, down from 134.6 billion kWh.
For the first nine months, net cash provided by operating activities was $2.912 billion, down from $3.338 billion. Investing activities used $2.281 billion, including $2.108 billion of construction expenditures; financing activities used $409 million. Cash and cash equivalents ended September at $443 million, versus $221 million at year-end 2011.
At September 30, total debt was $18.443 billion, including $17.227 billion of long-term debt and $1.216 billion of short-term debt. Debt-to-total capitalization was 54.6%, compared with 55.3% at December 31, 2011. AEP reported $3.041 billion of net available liquidity, including cash and committed credit facilities after commercial paper and letters of credit. Total assets were $53.843 billion and AEP common equity was $15.306 billion. The October 2012 declared quarterly dividend was $0.47 per share.
Material changes and operating drivers
- Ohio customer switching continued to weigh on results: about 48% of OPCo load had switched or initiated switching to competitive suppliers by September 30. AEP estimated lost Ohio gross margin of $67 million in Q3 and $165 million year to date, partly offset by capacity-related collections and riders.
- Utility Operations’ nine-month gross margin declined $134 million. Lower retail margins ($153 million) and off-system sales margins ($19 million) were partly offset by higher transmission revenues ($55 million). Lower operation and maintenance costs and fewer prior-year impairments partly offset the decline.
- AEP River Operations moved from $17 million of Q3 2011 income to a $1 million Q3 2012 loss, attributed primarily to drought-related reduced volumes and rates and a temporary Gulf shipping disruption from Hurricane Isaac.
- Transmission Operations income rose to $31 million for the first nine months from $19 million. Generation and Marketing income fell to $4 million from $20 million, mainly reflecting expired wind production tax credits and lower Oklaunion margins.
- AEP acquired BlueStar Energy for $70 million in March; it began operating as AEP Energy in June. AEP also recorded a $13 million pretax write-off related to Turk Plant costs subject to a Texas capital-cost cap.
Outlook, management commentary and key risks
- Ohio regulation: The PUCO approved a modified ESP through May 2015, including a Distribution Investment Rider capped at $366 million over the plan and a Retail Stability Rider intended to provide $508 million during the ESP period. Capacity-cost recovery and the ESP were subject to legal challenges and rehearing requests; failure to recover deferred capacity costs or approved rates could adversely affect earnings and cash flow.
- Ohio generation separation: In October 2012, the PUCO approved transferring OPCo generation assets and related liabilities to AEP Generation Resources at net book value. Further FERC action was expected. AEP also intended to seek FERC termination of the Interconnection Agreement, effective no earlier than December 31, 2013 absent another order. Market profitability and replacement arrangements remain uncertain.
- Capital projects and rates: The 600 MW Turk Plant was scheduled to enter service in Q4 2012; SWEPCo’s estimated share of generation costs was $1.3 billion, plus transmission costs, excluding AFUDC. Recovery is subject to regulatory conditions and disputes. SWEPCo sought an $83 million annual Texas rate increase; a decision was expected in Q2 2013. I&M’s proposed Cook Plant life-cycle projects were estimated at $1.2 billion through 2018, excluding AFUDC, with recovery proceedings pending.
- Environmental exposure: AEP estimated system environmental investment of approximately $6–7 billion during 2012–2020. The filing identified 4,606 MW of planned retirements before or during 2016, subject to regulatory and operating developments. Environmental rules, litigation, compliance costs and cost-recovery outcomes could affect asset recoverability, liquidity and earnings.
- Other contingencies: I&M’s Cook Plant Unit 1 repairs and replacement cost about $400 million; insurance and warranty recovery remained under review, with $64 million recorded as recoverable from NEIL. Ormet received approval for deferred payment of October and November 2012 bills; amounts above a permitted $20 million rate-recovery cap could reduce future income if unpaid. Litigation, regulatory proceedings, fuel recovery, weather, commodity prices, credit ratings and pension funding are additional risks.
- Guidance: The filing does not provide a clear consolidated full-year 2012 earnings or EPS forecast. Management cautions that interim results are not necessarily indicative of full-year results.
Important facts for investors to verify
- Whether Ohio’s ESP, capacity-cost recovery and related riders withstand rehearing and court challenges, and how much deferred capacity cost is ultimately collected.
- Progress and final cost, timing, regulatory approvals and customer cost recovery for Turk, Cook Plant life-cycle work and environmental compliance projects.
- Implementation of OPCo’s generation separation and termination or replacement of the Interconnection Agreement, including effects on power-market earnings.
- Underlying earnings and cash generation excluding the $273 million 2011 extraordinary gain, and the durability of lower operating costs amid declining utility sales and Ohio customer switching.
- Debt maturities, liquidity needs and financing capacity alongside planned construction spending, environmental investment and the dividend.