Southern Company — 2012 Form 10-K
Business context and reporting period. This combined Form 10-K covers the fiscal year ended December 31, 2012, with unaudited quarterly information. Southern Company is a regulated Southeastern electric utility holding company, with four traditional utilities and a wholesale generation business, Southern Power. The filing was signed February 27, 2013; certain outlook and event updates include information through that date.
Financial performance
| Metric | 2012 | 2011 | Change / context |
|---|---|---|---|
| Operating revenues | $16.537 billion | $17.657 billion | Down 6.3%; lower fuel-cost recovery, milder weather, and lower wholesale sales were key factors. |
| Operating income | $4.463 billion | $4.231 billion | Up $232 million; operating margin was approximately 27.0%, versus 24.0%. |
| Net income after subsidiary preferred and preference dividends | $2.350 billion | $2.203 billion | Up 6.7%. |
| Basic / diluted EPS | $2.70 / $2.67 | $2.57 / $2.55 | Basic EPS reached the top of management’s $2.58–$2.70 target range. |
| Operating cash flow | $4.898 billion | $5.903 billion | Down $1.005 billion, principally reflecting higher fossil fuel inventory and pension contributions. |
| Property additions | $4.809 billion cash outflow | $4.525 billion cash outflow | Investing cash outflow totaled $5.168 billion. |
| Cash and cash equivalents | $628 million | $1.315 billion | Down $687 million. |
| Long-term debt, excluding amounts due within one year | $19.274 billion | $18.647 billion | Balance-sheet securities due within one year were $2.335 billion; total long-term debt including that current portion was $21.609 billion. |
Net margin was approximately 14.2%, versus 12.5% in 2011. Lower fuel and purchased-power expense—down about $1.27 billion—more than offset lower revenues at the operating-income level. Most fuel-cost movements at the regulated utilities are recovered from customers and generally do not directly drive earnings.
Fourth quarter: unaudited operating revenues were $3.703 billion, operating income $814 million, and net income after subsidiary preferred and preference dividends $383 million. Quarterly results are seasonal and should not be read as a standalone run rate.
Material changes and shareholder returns
- Retail energy sales declined 2.3% and total energy sales declined 3.4%; milder weather was an important factor. Wholesale revenues fell $230 million, largely due to lower energy prices and customer demand.
- Generation shifted substantially toward gas: the reported generation mix was 42% gas and 38% coal in 2012, compared with 30% gas and 52% coal in 2011. Average generated fuel cost fell to 2.93 cents per net KWh from 3.43 cents.
- Southern Company’s annual common dividend rose to $1.9425 per share from $1.8725. Management reported a 71.9% payout ratio, targeting approximately 70%–75% of net income. The 2013 first-quarter dividend was declared at $0.49 per share.
- Southern Company repurchased 9.44 million shares in 2012 for approximately $430 million to partly offset shares issued under employee and director plans; it announced plans to continue the program through 2015.
- A $25 million insurance recovery, less approximately $6 million in related legal fees, reduced 2012 expense by $19 million. EPS excluding this item was $2.68, compared with reported basic EPS of $2.70.
Liquidity, debt and capital requirements
Management described financial condition as stable, but projected common dividends, capital expenditures and debt maturities for 2013–2015 to exceed operating cash flow. The company expected to fund the shortfall primarily through debt and equity issuance. Current liabilities exceeded current assets by approximately $852 million at year-end; management cited seasonal cash needs and short-term debt use as factors. Cash was $628 million, short-term borrowings were $820 million, and committed bank credit arrangements totaled $5.183 billion, of which $5.173 billion was unused. The company reported compliance with applicable debt covenants.
Long-term debt represented 49.9% of capitalization excluding amounts due within one year. The contractual-obligations schedule reported $74.6 billion in total obligations across debt principal and interest, purchase commitments, leases, benefit plans and other categories; this is a multiyear commitments measure, not debt alone.
System construction investment was estimated at approximately $5.5 billion in 2013, $5.8 billion in 2014 and $5.2 billion in 2015. Estimated environmental capital expenditures and compliance costs for existing requirements were about $3.6 billion over 2013–2015. Actual spending and recovery depend on project execution, regulatory decisions and final environmental rules.
Outlook, major projects and risks
- Kemper IGCC: Mississippi Power was building a 582-MW lignite gasification plant, then scheduled for service in May 2014. The current estimate was approximately $2.88 billion, net of a $245.3 million DOE grant and excluding the mine, CO₂ pipeline, financing costs and specified exceptions. The Mississippi PSC’s construction cost cap was up to $2.88 billion, with prudence and recovery decisions still required. Total spending through year-end 2012 was $2.51 billion, including mine and pipeline costs and other deferred costs. Further overruns or delay could lead to material charges if costs are disallowed or exceed permitted cap exceptions.
- A January 2013 settlement with the Mississippi PSC established a cost-recovery process. Mississippi Power filed for a 2013 annual revenue requirement not exceeding $172 million and proposed approximately $150 million annually for 2014–2020 for certain operating and rate-base costs. The proposals and prudence reviews remained subject to PSC action. Mississippi legislation signed February 26, 2013 authorized a multi-year rate plan and securitization as alternate financing; recovery was not assured.
- Plant Vogtle Units 3 and 4: Georgia Power’s 45.7% share of two new nuclear units faced revised estimated in-service capital costs of $4.8 billion and target service dates in the fourth quarters of 2017 and 2018. Associated construction-period financing costs were estimated at approximately $2.0 billion. Contractors asserted a cost adjustment attributable to Georgia Power of about $425 million (in 2008 dollars), which Georgia Power disputed; litigation and negotiations continued. A conditional DOE loan-guarantee commitment, potentially up to approximately $3.46 billion, was subject to final approval and was due to expire June 30, 2013 unless extended.
- Georgia Power filed a 2013 resource plan seeking decertification of 16 coal- and oil-fired units totaling 2,093 MW, citing environmental compliance costs, economic conditions and lower gas prices. PSC approval was pending. Alabama Power’s Rate RSE was unchanged for 2013; a potential 2014 increase was being discussed with its regulator.
- Environmental exposure includes MATS compliance, proposed water and coal-ash rules, greenhouse-gas regulation and ongoing Clean Air Act litigation. Management warned that costs, unit retirements and rate recovery remain uncertain. The EPA’s New Source Review case against Alabama Power remained in litigation; the Kivalina plaintiffs petitioned the U.S. Supreme Court in February 2013 after lower-court dismissal.
- A leveraged-lease investment was placed on nonaccrual after a lessee could not pay its December 2012 rent in full. A restructuring was being negotiated; a successful restructuring could require up to $17 million of lower lease income, while abandonment could result in an estimated $90 million after-tax impairment.
- Other risks cited include weather and economic demand, fuel availability and prices, construction delays and cost overruns, regulatory lag or disallowance, counterparty performance, interest rates, credit ratings, pension funding, and physical or cyber security. No formal 2013 earnings guidance is stated in the provided filing text.
Investor facts to verify
- Track Kemper’s final cost, schedule, cost-cap exceptions, independent-monitor assessments, PSC prudence findings and approved recovery or securitization terms.
- Confirm Vogtle’s revised cost and in-service estimates, contractor claim resolution, NRC license amendments, Georgia PSC approvals and DOE loan-guarantee status.
- Assess whether operating cash flow can support the construction program, dividends and maturities, and monitor actual borrowing, refinancing and credit-facility availability.
- Check final environmental rules, required coal-unit retirements or controls, and the regulators’ timely approval of cost recovery.
- Monitor the leveraged-lease restructuring and any resulting income reduction or impairment, as well as material legal and tax contingencies.