American Electric Power Company, Inc. — 2013 Q3 Form 10-Q
Reporting period: Quarter and nine months ended September 30, 2013. Financial statements are unaudited. This combined filing also includes separate reporting for five AEP utility subsidiaries; figures below are for AEP consolidated unless stated otherwise. Dollar amounts are in millions, except per-share data.
Financial performance and position
| Metric | Q3 2013 | Q3 2012 | Nine months 2013 | Nine months 2012 |
|---|---|---|---|---|
| Revenue | $4,176 | $4,156 | $11,584 | $11,332 |
| Operating income | $875 | $912 | $2,177 | $2,407 |
| Net income | $434 | $488 | $1,137 | $1,241 |
| Earnings attributable to AEP common shareholders | $433 | $487 | $1,134 | $1,238 |
| Diluted EPS | $0.89 | $1.00 | $2.33 | $2.55 |
| Utility Operations gross margin | $2,451 | $2,438 | $6,839 | $6,716 |
- Revenue rose 0.5% for the quarter and 2.2% year to date, while net income declined 11.1% and 8.4%, respectively. Operating income declined 4.1% for the quarter and 9.6% year to date.
- Calculated operating margin was approximately 21.0% for Q3 and 18.8% year to date, versus approximately 21.9% and 21.2%, respectively, in 2012.
- Cash from operations was $3,040 for the first nine months, up from $2,912. Investing used $2,520, including $2,481 of construction expenditures; financing used $652. Cash declined from $279 at year-end 2012 to $147. Cash from operations less construction expenditures was approximately $559, versus $804 in 2012; this is a simple comparison, not a company-defined free-cash-flow measure.
- Total debt was $18,786 at September 30, 2013, including $1,218 of short-term debt. Debt was 54.4% of total capitalization, down from 55.2% at year-end 2012. AEP reported $3,344 of net available liquidity under credit facilities and cash.
- Common equity was $15,762. The board declared a quarterly dividend of $0.50 per share in October; dividends declared during Q3 were $0.49 per share.
Material changes versus the prior comparable period
- Profit was pressured by lower weather-related usage, Ohio retail customer switching, reduced off-system sales margins, increased plant outages and $298 of year-to-date asset impairment charges. Q3 impairment charges were $144.
- The Q3 impairment charges included $111 pretax related to Turk Plant AFUDC disallowed under the Texas capital cost cap and $33 pretax related mainly to KPCo’s Big Sandy scrubber project. The year-to-date total also includes a $154 pretax impairment of OPCo’s Muskingum River Plant Unit 5.
- Ohio retail customer switching reduced Utility Operations retail margins by $223 year to date, partly offset by rate increases, transmission revenue, riders and deferred capacity costs. Across AEP, weather-normalized retail sales fell 1.5% for Q3 and 1.9% for the first nine months; industrial sales fell 3.9% and 5.1%.
- Utility Operations net income fell to $409 in Q3 from $471 and to $980 year to date from $1,220. Transmission Operations improved to $22 and $53, respectively. AEP River Operations posted a $12 year-to-date loss versus $11 of income in 2012, citing low water, later flooding and weaker grain and export-coal demand.
- A favorable U.K. Windfall Tax decision added $108 to year-to-date net income, including an $80 tax benefit and $43 pretax interest income; it did not generate cash in Q2. The benefit partially offset weaker operating results.
Outlook, management commentary, risks and contingencies
- Capital spending: AEP forecast approximately $3.6 billion of 2013 construction expenditures, excluding equity AFUDC and capitalized interest, and $3.8 billion annually for 2014 and 2015. Management expected funding from operating cash flow and financing. AEP estimated $3.5–$4.0 billion of system environmental investment for 2013–2020; the subsidiary-level estimates shown in the filing reflect expected plant transfers and are not directly additive to all system estimates.
- Regulatory changes and recovery: AEP planned corporate separation and transfer of approximately 9,200 MW of OPCo generation to AEPGenCo, with related plant transfers targeted for December 31, 2013. Regulatory approvals, rehearing requests and appeals remained pending. AEP warned that future generation results could depend materially on market conditions and that costs not recovered through rates or markets could reduce earnings and cash flows.
- Ohio proceedings: OPCo had $467 of net deferred fuel costs and $228 of deferred capacity costs at September 30. Appeals and regulatory proceedings could reduce recoverable balances; intervenor proposals could reduce projected OPCo revenue by up to approximately $155 for January 2014–May 2015. The PUCO also ordered a $7 pretax customer refund related to OPCo’s 2010 earnings test.
- Major project exposure: SWEPCo’s Texas base-rate order approved an annual increase of about $39, below its $83 request, and applied a capital cost cap to Turk Plant AFUDC, prompting the $111 impairment. Turk Plant investment recovery in Arkansas is not cost-based; Louisiana recovery remains subject to review. I&M’s Cook Plant life-cycle project was estimated at $1.2 billion through 2018, excluding AFUDC, with $285 incurred by September 30. Regulatory recovery of several projects and plant balances remained uncertain.
- Environmental and operating risks: AEP identified potentially material costs and operational effects from emissions, coal-ash and water rules, and climate regulation. Management intended to retire 6,533 MW of specified generating capacity before or during 2016, subject to regulatory and market factors. Failure to recover environmental costs or remaining plant values could impair earnings and cash flow.
- Other contingencies: Wilmington Trust sued AEGCo and I&M over obligations associated with Rockport Unit 2 after the lease ends in 2022; AEP said it could not estimate a reasonably possible loss range. Ormet shut down in October 2013; management said the lost load was not expected to materially affect future gross margin and expected certain unpaid amounts to be recoverable through a rider. AEP stated that it complied with credit-facility covenants; the contractual debt-to-capitalization measure was 50.9% against a 67.5% limit.
Most important facts for investors to verify
- Whether the planned OPCo separation, generation transfers and revised power coordination arrangements received final regulatory approval, and the market exposure of AEPGenCo after separation.
- Final outcomes of Ohio deferred fuel and capacity recovery proceedings, including appeals and the potential revenue impact of competitive-bid proposals.
- Whether Turk Plant costs, including AFUDC and transmission investment, and other environmental and generation investments will be recoverable through rates or markets.
- Whether retail demand, Ohio customer switching, weather-normalized sales and off-system margins stabilize or continue to pressure results.
- Execution and funding of the stated capital program, liquidity availability, debt refinancing needs and the effect of environmental rules and planned plant retirements.
- Resolution and financial exposure from the Rockport litigation and other material regulatory, environmental and litigation contingencies.