SOUTHERN CO quarterly report, Q3 FY2010

Southern Company — Q3 2010 Form 10-Q Summary

Reporting period: Quarter and nine months ended September 30, 2010; filed November 5, 2010. The combined filing covers Southern Company and its utility and generation subsidiaries. Financial amounts below are consolidated Southern Company unless otherwise noted; unaudited.

Financial performance and position

Metric	Q3 2010	Q3 2009	Nine months 2010	Nine months 2009
Operating revenue	$5.320 billion	$4.681 billion	$13.685 billion	$12.233 billion
Operating income	$1.459 billion	$1.415 billion	$3.332 billion	$2.791 billion
Net income after subsidiary preferred dividends	$817 million	$790 million	$1.822 billion	$1.394 billion
Diluted EPS	$0.97	$0.99	$2.19	$1.76
Cash dividends per common share	$0.4550	$0.4375	$1.3475	$1.2950

Revenue increased 13.6% in Q3 and 11.9% year to date. Retail revenue growth reflected weather, rate changes, fuel-cost recovery, and stronger industrial sales; fuel recovery generally offsets fuel expense and does not materially increase earnings.
Net income after subsidiary preferred dividends rose 3.5% in Q3 but diluted EPS declined from $0.99 to $0.97, alongside higher average shares outstanding. Year-to-date earnings rose 30.7%, primarily because 2009 included a $202 million MC Asset Recovery settlement charge, as well as weather, rate and sales effects.
Operating margin was approximately 27.4% in Q3 versus 30.2% a year earlier, and 24.3% year to date versus 22.8%. Higher fuel, operations and maintenance, and depreciation costs affected quarterly results.
For the first nine months, operating cash flow was $3.527 billion, investing cash outflow was $3.006 billion, and financing cash inflow was $48 million. Property additions were $2.894 billion. Cash and cash equivalents ended September at $1.259 billion.
At September 30, total current assets were $6.609 billion and current liabilities $5.994 billion. Long-term debt was $18.198 billion; securities due within one year were $1.984 billion and notes payable were $348 million.
Southern Company reported $4.780 billion of unused committed bank credit and approximately $1.3 billion of cash and cash equivalents. Management described financial condition as stable and said working-capital needs could be met with cash, credit lines and commercial paper.

Material changes and management commentary

Year-to-date earnings benefited significantly from the absence of the prior-year $202 million settlement charge. Other reported drivers included warmer second- and third-quarter weather, colder first-quarter weather, Alabama rate increases, and higher industrial sales.
Weather-adjusted retail energy sales increased 1.4% in Q3 and 2.5% year to date. Industrial sales were stronger, while commercial sales declined modestly.
Operations and maintenance expense rose $200 million in Q3 and $324 million year to date. The Q3 increase included a $40 million additional Alabama Power natural-disaster reserve accrual. Depreciation and amortization rose $95 million in Q3, partly reflecting added plant and lower Georgia Power cost-of-removal liability amortization.
Southern Company issued $610 million of common stock in the first nine months and $2.796 billion of long-term debt, while redeeming $1.871 billion of long-term debt. Approximately $2 billion was expected to be needed through September 2011 for debt maturities and announced repurchases or redemptions.
Moody’s downgraded Southern Company’s senior unsecured rating to Baa1 from A3 and its short-term rating to P-2 from P-1; Fitch revised Southern Company’s outlook to negative. Management noted that a downgrade could affect capital-market access and, under specified ratings, collateral requirements.

Outlook, significant projects and risks

The filing gives no specific consolidated earnings or EPS guidance. Management emphasized uncertainty around economic recovery, electricity demand, weather, fuel costs, regulatory cost recovery, capital-market access and construction spending.
Georgia Power requested a $615 million annual base-rate increase effective January 2011, based on a proposed 11.95% retail return on equity. Georgia PSC Staff proposed a $436 million increase using a 10.5% return and opposed several proposed recovery tariffs. The final outcome was pending; the Commission’s order was scheduled for December 21, 2010.
Georgia Power filed for an approximately $218 million annual tariff increase, effective January 2011, to recover financing costs for Plant Vogtle Units 3 and 4. Construction, licensing and legal challenges remain; management said known design-review concerns were not then expected to alter projected commercial-operation dates.
Mississippi Power’s Kemper IGCC project received state certification, with a construction cost cap of up to $2.88 billion subject to prudence review for costs above $2.4 billion and specified exemptions. The company reported $195.5 million spent through September 30. DOE grants total $270 million, and the IRS allocated $279 million in Phase II tax credits; eligibility depends on project timing and other requirements, including capturing and sequestering at least 65% of carbon dioxide. Appeals, permitting and cost-recovery issues remain unresolved.
Environmental regulation could require substantial additional compliance spending, including rules concerning air emissions, greenhouse gases and coal-combustion byproducts. Management warned that unrecovered costs could affect earnings, cash flow, financial condition and generation decisions.
EPA New Source Review litigation against Alabama Power narrowed to three remaining claims, with any trial set for October 2011. Other carbon-dioxide litigation and tax matters also remain unresolved. The filing states that outcomes and potential effects are uncertain.
Tax timing items include an estimated $243 million positive 2010 cash-flow effect from a repair-cost tax accounting change, subject to IRS review, and an estimated $309 million reduction in 2010 tax payments from bonus depreciation. The filing records an unrecognized tax benefit for the repair-cost method change.
Alabama Power’s approved change to nuclear-outage accounting is expected to reduce reported 2011 outage expense by approximately $50 million, with deferred costs amortized in later periods.

Important facts for investors to verify

Whether Georgia Power’s requested rate increase and proposed cost-recovery mechanisms are approved, and the resulting customer, earnings and cash-flow effects.
Kemper IGCC and Plant Vogtle final costs, construction schedules, cost recovery, financing, grant and tax-credit conditions, and legal or regulatory outcomes.
How much earnings growth reflects recurring operations versus weather, regulatory accounting and the prior-year settlement comparison; also monitor share dilution and EPS.
Environmental compliance exposure and the ability of subsidiaries to recover prudent costs through rates.
Debt maturities, rating developments, available credit facilities and potential collateral needs; assess liquidity alongside the large construction program.
IRS review and ultimate realization of repair-method tax benefits, bonus depreciation and disputed Georgia state tax credits.