FIRSTENERGY CORP annual report, FY2012

Business context and reporting period

FirstEnergy Corp. filed this combined Form 10-K for the fiscal year ended December 31, 2012; it also covers FirstEnergy Solutions (FES), Ohio Edison (OE), and Jersey Central Power & Light (JCP&L). FirstEnergy is a regulated electric distribution and transmission utility holding company with competitive generation and retail energy businesses. The 2011 comparison includes Allegheny results for only ten months, versus twelve months in 2012.

Key financial metrics

Operating margin was approximately 14.2%, versus 10.5% in 2011; net margin was approximately 5.0%, versus 5.4%. FirstEnergy reported $3.157bn of net cash used for investing and $807m provided by financing in 2012. The company declared $2.20 per share in dividends and paid $920m in common dividends.

At December 31, 2012, FirstEnergy reported $15.179bn of long-term debt and other long-term obligations, $1.999bn of currently payable long-term debt, and $1.969bn of short-term borrowings. The filing reported $3.279bn of available revolving credit and $61m cash as of January 31, 2013, or $3.340bn total available liquidity. Management said existing liquidity was expected to be sufficient. Total equity plus long-term debt and other long-term obligations was $28.272bn.

The 2012 fourth quarter included a $148m net loss attributable to FirstEnergy, versus $98m of earnings in fourth-quarter 2011. The filing records a $609m annual pension and OPEB mark-to-market expense in 2012; the annual adjustment is recognized in the fourth quarter.

Material changes versus the prior comparable period

• Revenue and EPS declined despite higher operating income. Earnings in 2011 included a $569m pretax gain on the partial sale of Signal Peak; 2012 earnings also reflected weaker competitive power economics and a $609m pension and OPEB mark-to-market charge.
• Regulated Distribution earnings rose $52m and Regulated Transmission earnings rose $32m; Competitive Energy Services earnings fell $162m, to $215m, in part because the 2011 Signal Peak gain did not recur. Segment reporting was reorganized in 2012, moving certain utility transmission assets into the Regulated Transmission segment.
• Cash from operations fell to $2.320bn, including a $600m pension contribution, while storm-related costs, milder weather and lower customer collections affected cash flows. Net investing outflows rose to $3.157bn, partly reflecting higher property additions and nuclear fuel spending and the absence of 2011 asset-sale proceeds and merger cash.
• FirstEnergy deactivated sixteen coal-fired generating units effective September 1, 2012; five more units were to remain in service under PJM reliability-must-run arrangements until anticipated deactivation in spring 2015.

Outlook, management commentary, risks and unusual items

• Management forecast 2013 capital expenditures of approximately $2.38bn, excluding nuclear fuel, plus $205m for nuclear fuel. It expected $75m–$85m of operation and maintenance expense reductions versus 2012 and a 38%–38.5% effective income tax rate.
• Management anticipated 2013 Regulated Distribution sales of 148.5 million MWh, Competitive Energy Services generation output of 93 million MWh, and a $160m reduction in competitive capacity revenue versus 2012. It expected regulated transmission revenue to decrease approximately $35m. These are forecasts, not results.
• Management cited weak power prices, soft demand, efficiency mandates and environmental costs as pressures on competitive margins. The company said it expected approximately $975m in MATS compliance spending over several years. It also described a proposed West Virginia generation transfer intended to add 1,476 MW net to regulated MP and reduce competitive-segment debt; approvals remained pending.
• Hurricane Sandy restoration costs were approximately $860m in 2012, including $485m capitalized, $198m of asset removal, $177m of O&M and $356m deferred for future recovery. The filing reports $19m net expense after regulatory accounting. A separate June 2012 derecho caused approximately $137m of costs.
• Key regulatory and legal exposures include the JCP&L rate case and recovery of Sandy costs; Pennsylvania transmission-loss recovery litigation involving approximately $254m; contested PJM/MISO transmission cost allocations; coal transportation shortfall penalties estimated at $60m subject to force-majeure disputes; and multiple Clean Air Act and water matters. The filing does not provide clear loss estimates for several proceedings.
• Coal ash impoundment closure and disposal obligations are material: the LBR feasibility study estimated a $78m–$224m cost range for viable final-cap options, with closure taking 6–16 years. Probable environmental remediation liabilities accrued were approximately $124m at year-end.
• Nuclear operations face regulatory oversight and potential upgrade costs. Perry remained in NRC Action Matrix Column 3, with further inspections and possible escalation; Davis-Besse shield-building commitments were reported completed. FirstEnergy held approximately $2.2bn in nuclear decommissioning trusts.
• Other significant risks include commodity and wholesale power-price volatility, weather and outages, environmental rules, pension funding and market-sensitive trust assets, counterparty credit, collateral calls and access to capital. Potential additional collateral obligations under specified credit downgrades were up to $773m.

Most important facts for investors to verify

• Whether competitive generation margins and capacity revenues stabilize, and whether the forecast $160m capacity-revenue decline materializes.
• Execution and financing of the proposed West Virginia asset transfer and the intended competitive-segment debt reduction.
• Regulatory approval and recovery timing for Hurricane Sandy restoration costs, including the filing’s JCP&L rate-case request; the filing cites $603m of Sandy costs and an updated total revenue request of approximately $112m, figures that should be reconciled with the rate-case documents.
• Actual MATS compliance spending and the resulting generation deactivations, reliability arrangements and coal-contract exposure.
• Outcomes of major transmission allocation, environmental, coal-supply and nuclear regulatory proceedings, including potential cash costs or customer recovery.
• Liquidity and refinancing needs: year-end short-term borrowings were $1.969bn, while stated available liquidity was measured at January 31, 2013; also monitor credit ratings, collateral requirements and the dividend’s coverage by cash generation.
• The fourth-quarter pension and OPEB mark-to-market charge and the sensitivity of future earnings and funding needs to discount rates, asset returns and actuarial assumptions.