American Electric Power Company, Inc. — Q1 2012 Form 10-Q
Reporting period: Three months ended March 31, 2012; unaudited. The combined filing also includes separate reports for five AEP utility subsidiaries. Comparisons below are to Q1 2011 unless otherwise noted.
Financial results
| Metric | Q1 2012 | Q1 2011 |
|---|---|---|
| Total revenue | $3.625 billion | $3.730 billion |
| Operating income | $754 million | $832 million |
| Net income | $390 million | $355 million |
| Net income attributable to AEP common shareholders | $389 million | $353 million |
| Diluted EPS | $0.80 | $0.73 |
| Operating cash flow | $876 million | $830 million |
| Cash and cash equivalents at quarter-end | $286 million | $625 million |
| Capital expenditures for construction | $741 million | $540 million |
Utility Operations gross margin—revenues less fuel and purchased power—was $2.116 billion, down from $2.227 billion. Total utility energy sales fell to 50.345 billion kWh from 52.798 billion kWh. No consolidated gross-profit margin percentage is presented in the filing.
At March 31, total debt was $18.370 billion, comprising $17.320 billion of long-term debt including amounts due within one year and $1.050 billion of short-term debt. Debt-to-total capitalization was 55.3%, unchanged from year-end 2011. Net available liquidity was approximately $2.962 billion, including $3.25 billion of credit facilities and $286 million of cash, less commercial paper and letters of credit. AEP reported compliance with its credit-facility covenants.
Material changes and drivers
- Consolidated net income rose $35 million despite lower revenue and operating income. Management cited reduced operation and maintenance costs, successful rate proceedings, a $35 million reversal of an Ohio contribution obligation, lower interest expense and higher transmission earnings. Lower tax expense also supported results.
- Utility Operations gross margin declined $111 million. Retail margins fell $98 million, including an $87 million weather-related decline and a $54 million decline attributed to Ohio customer switching; rate increases partly offset these pressures. Heating degree days were down 32% in the East and 50% in the West.
- Lower O&M expense included prior-year costs and write-offs not repeated in 2012, as well as current-year savings. The $35 million reversal followed the Ohio regulator’s rejection of a modified stipulation. These factors make the earnings comparison partly dependent on regulatory and period-specific items.
- Operating cash flow increased $46 million, while investing cash use rose to $792 million from $613 million, primarily because construction expenditures increased. AEP spent $70 million to acquire BlueStar Energy in March.
- AEP completed an $800 million Texas securitization financing. Long-term debt outstanding increased from $16.516 billion at December 31, 2011.
Outlook, regulatory matters and risks
- Ohio rates and competition: OPCo filed a proposed June 2012–May 2015 Electric Security Plan (ESP), including capacity pricing, a phase-in recovery rider, a distribution investment rider and a retail stability rider. Approval and timing remained pending. The PUCO had set a temporary $255/MW-day capacity billing rate for certain competitive suppliers through May 2012; the proposed ESP and related capacity proceedings could materially affect recovery and generation economics.
- Ohio deferred fuel costs: OPCo reported a net Phase-In Recovery Rider deferral of $499 million at quarter-end, excluding unrecognized equity carrying costs. Full recovery was uncertain. Following an April rehearing order, OPCo expected to record an approximately $30 million favorable effect in Q2 2012 from a coal-settlement credit.
- Generation separation and system arrangements: OPCo filed a plan to separate its generation assets, subject to regulatory approval. AEP also expected to pursue termination of the Interconnection Agreement, effective December 31, 2013 or another date ordered by FERC. Changes could affect power costs, revenues and asset recovery.
- Environmental investment and retirements: AEP estimated $6–$7 billion of system environmental investment from 2012 through 2020, including conversion of 1,055 MW of coal capacity to natural gas. The company had notified applicable grid operators of planned retirements totaling approximately 4,606 MW by or during 2015. Estimates and plans depend on final rules, technology, demand and regulatory cost recovery. An April agreement in principle on PSO’s Northeastern Station could reduce PSO’s estimated environmental investment by about $400 million if finalized and approved.
- Major projects: SWEPCo’s 600 MW Turk Plant was targeted for service in Q4 2012; the project estimate was $1.8 billion plus $122 million for transmission, excluding AFUDC. Recovery limits and appeals remained important uncertainties. I&M proposed a $1.2 billion Cook Plant life-cycle project through 2018, subject to approval and cost recovery.
- Other contingencies: APCo recorded a $334 million West Virginia ENEC under-recovery regulatory asset, with securitization contemplated under new state legislation. I&M continued pursuing warranty, insurance and regulatory recovery of costs from the Cook Unit 1 incident; the repairs and replacement cost about $400 million, and insurance payments received totaled $388 million. Ohio rate appeals, fuel audits and earnings-refund proceedings also remained pending.
- Management initiated an employee repositioning and efficiency process in April, expected to conclude by year-end 2012. The filing gives no consolidated full-year earnings or EPS guidance; management cautions that Q1 results are not necessarily indicative of full-year results.
Most important facts for investors to verify
- How the PUCO resolves OPCo’s proposed ESP, capacity pricing, the $499 million fuel deferral and related recovery requests.
- Whether Ohio customer switching and unusually mild weather continue to pressure utility sales and margins, and whether new rates offset those effects.
- Whether AEP can recover its planned environmental spending and avoid or manage the financial effects of announced generation retirements and new emissions rules.
- Whether Turk Plant and Cook Plant project costs, schedules and regulatory recovery remain consistent with management’s estimates.
- Whether operating cash flow and liquidity remain adequate as construction spending and debt requirements rise; quarter-end net available liquidity was about $2.962 billion.
- How pending litigation, regulatory proceedings and insurance claims—including Cook Unit 1 and Ohio refund matters—are ultimately resolved.