AMERICAN ELECTRIC POWER CO INC annual report, FY2013

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American Electric Power Company, Inc. — 2013 Form 10-K

Reporting period: Fiscal year ended December 31, 2013; filed February 25, 2014. This is a combined filing for AEP and five subsidiaries. Much of the consolidated financial discussion and statements is incorporated by reference to the 2013 Annual Reports, so the provided filing text does not include a clear consolidated revenue, net income, cash flow, debt or liquidity figure for AEP.

Business context

AEP is a regulated electric utility holding company serving customers across portions of 11 states, with generation, transmission and distribution operations, competitive generation and marketing, transmission investments, and river transportation. Its subsidiaries had 18,521 employees at year-end. Reporting segments were realigned in the fourth quarter following corporate separation and generation-asset transfers.

Financial performance and key metrics

  • Segment revenue: Vertically Integrated Utilities reported $9.992 billion in 2013, up from $9.418 billion in 2012 (about 6%). Transmission and Distribution Utilities reported $4.478 billion, down from $4.818 billion (about 7%). Generation & Marketing reported $3.665 billion, up from $3.467 billion (about 6%). These are segment figures, include affiliate activity, and should not be treated as consolidated revenue.
  • Parent-company earnings: AEP parent reported net income of $1.480 billion and diluted EPS of $3.04 in 2013, compared with $1.259 billion and $2.60 in 2012. Parent income was principally equity earnings from subsidiaries; these figures are not a substitute for consolidated results.
  • Parent cash flow: Operating cash flow was $632 million in 2013, down from $1.258 billion in 2012. Cash dividends received from subsidiaries were $1.027 billion, versus $1.294 billion. Year-end parent cash was $36 million, compared with $166 million a year earlier.
  • Parent debt and liquidity: At year-end, parent long-term debt was $840 million and commercial paper outstanding was $57 million; the filing states AEP was in compliance with debt covenants. Parent current assets were $594 million and current liabilities were $120 million. These parent-only amounts do not describe consolidated liquidity or obligations.
  • Margins and consolidated metrics: The supplied text does not provide clear consolidated operating margin, net margin, consolidated debt, or consolidated liquidity values.
  • Fuel and emissions: Coal and lignite supplied 75% of system fuel in 2013, natural gas 13%, and nuclear 11%. Fossil fuel costs increased about 9% per MMBtu from 2012, principally due to higher natural-gas prices. CO₂ emissions fell from approximately 122 million metric tons in 2012 to 114 million in 2013.

Material changes versus the prior comparable period

  • On December 31, 2013, Ohio Power transferred all generation assets and related liabilities to competitive affiliate AEP Generation Resources (AGR) at net book value. Some assets and liabilities were then transferred to Appalachian Power and Kentucky Power. AGR held 10,002 MW of generating capacity at year-end, with contractual rights to another 1,186 MW.
  • The Interconnection Agreement and related allowance agreement among AEP East utilities ended effective January 1, 2014. Segment realignment and this separation affect year-over-year comparability.
  • Transmission and Distribution Utilities segment revenue declined as Ohio retail commercial and industrial revenues fell; Vertically Integrated Utilities revenue increased. Generation & Marketing revenue increased.
  • Environmental investment rose to $415 million in 2013 from $235 million in 2012. AEP estimated environmental investment of $588 million in 2014, $644 million in 2015 and $447 million in 2016.

Outlook, risks and unusual items

  • AEP forecast approximately $3.8 billion of construction expenditures in 2014. AEPTCo had $991 million of transmission assets in service at year-end and planned nearly $2 billion of additional transmission assets through 2016.
  • Management expected emissions to decline over much of the remainder of the decade as older coal units retire and natural-gas utilization increases; near-term emissions increases, if any, were expected to be small. These are forward-looking expectations, not guarantees.
  • Key risks include regulatory delays or denials of rate recovery, environmental compliance costs and potential generation retirements, fuel and power-price volatility, market-based generation and PJM capacity-auction outcomes, extreme weather and river conditions, cyber incidents, and access to capital. Competitive generation costs may lack the regulated rate-recovery protection available to utility operations.
  • Several material rate matters remained pending or subject to appeal, including Ohio electric security plan and fuel-cost recovery issues, recovery of the Turk Plant investment in certain jurisdictions, and rate cases in Indiana, Texas and Oklahoma. The filing warns that unfavorable outcomes could reduce earnings and cash flow.
  • For the Cook nuclear plant, estimated decommissioning and low-level waste disposal costs were $1.3 billion to $1.7 billion in 2012 dollars; the trust fund balance was approximately $1.6 billion at year-end 2013. Actual ultimate costs may differ materially.
  • Management reported effective disclosure controls and internal control over financial reporting, with no material weaknesses as of December 31, 2013. The filing text refers investors to incorporated annual reports for full consolidated financial statements and detailed MD&A.

Important facts for investors to verify

  • Review the incorporated 2013 Annual Report for consolidated revenue, earnings, cash flow, balance-sheet liquidity, total debt, margins, and management’s reconciliation of earnings and cash flow.
  • Assess how the OPCo-to-AGR generation transfer and termination of the Interconnection Agreement affect future segment results and comparability.
  • Track outcomes of Ohio rate, fuel recovery and refund proceedings, and pending rate recovery matters in other jurisdictions.
  • Compare planned construction and environmental spending with actual expenditures, regulatory approvals, and recoverability through customer rates.
  • Evaluate AGR’s exposure to PJM capacity-auction pricing, wholesale power and fuel markets, and the resulting impact on competitive generation economics.