SOUTHERN CO quarterly report, Q2 FY2011

Business context and reporting period

Southern Company’s unaudited combined Form 10-Q covers the quarter and six months ended June 30, 2011, compared with the corresponding 2010 periods. The filing also reports separately on Alabama Power, Georgia Power, Gulf Power, Mississippi Power, and Southern Power. The system is primarily a regulated Southeastern electric utility, with Southern Power generating and selling electricity in wholesale markets.

Key financial results

Q2 revenue rose 7.4% and net income after subsidiary preferred dividends rose 18.2%; six-month revenue rose 2.0% and that net income rose 2.1%. Derived operating margins were approximately 25.1% versus 22.6% in Q2 and 23.3% versus 22.4% for the six-month periods. Derived net margins were approximately 13.4% versus 12.1% in Q2 and 12.0% in both six-month periods.

• Cash flow: First-half cash from operations was $2.389B, versus $1.415B; investing cash use was $2.064B, including $2.126B of property additions; financing cash use was $335M, versus $197M of financing cash provided in 2010. Ending cash was $437M.
• Debt and liquidity: At June 30, long-term debt was $18.554B; securities due within one year were $1.354B and notes payable were $857M. Current liabilities of $5.699B exceeded current assets of $5.502B. The company reported about $5.18B of unused committed bank credit and $852M of system short-term borrowings at a weighted average rate of 0.3%.
• Balance sheet and investment: Total assets were $56.023B, up from $55.032B at year-end 2010; property, plant, and equipment increased $1.28B. Common stockholders’ equity was $16.982B, versus $16.202B.

Material changes and operating drivers

• Q2 earnings growth was driven mainly by Georgia Power retail rate increases under its 2010 Alternate Rate Plan and nuclear construction cost recovery tariff, new Southern Power PPAs, and increased industrial sales. Georgia Power’s rate-plan increases took effect January 1, 2011.
• For the first half, wholesale revenues declined $59M, mainly because Alabama Power’s long-term unit power sales contracts expired in May 2010; higher Southern Power PPA revenues partly offset the decline. Weather was also a comparison factor: first-quarter 2010 was significantly colder.
• Depreciation and amortization rose $138M in the first half, primarily reflecting reduced amortization of a Georgia Power regulatory liability and additional plant in service. Fuel and purchased-power costs decreased $135M overall, but regulated fuel-cost recovery generally offsets these expenses and they do not materially affect earnings.
• Southern Power’s first-half net income increased to $82M from $46M, supported by new PPAs. Alabama Power’s first-half net income after preferred dividends decreased to $342M from $393M, while Gulf Power’s fell to $45M from $58M. Georgia Power rose to $515M from $476M and Mississippi Power to $40M from $30M.
• A Georgia tax-credit litigation settlement produced approximately $64M of additional tax benefits, offset in part by a $62M regulatory liability; Georgia Power also recorded a $23M reduction in related interest expense. The filing identifies this as a significant item in its results.

Outlook, risks, and unusual items

• The filing gives no consolidated earnings or EPS guidance. Management says future results depend on regulatory cost recovery, electricity demand, weather, economic conditions, fuel costs, competition, and wholesale contracts; it cautions that period results are not necessarily indicative of full-year results.
• Environmental compliance is a major capital and operating uncertainty. If proposed air, water, and coal-combustion rules were adopted as proposed, Southern Company preliminarily estimated $13B–$18B of traditional-utility capital costs through 2020; $686M was included in 2011–2013 base capital budgets in anticipation. Cost recovery, retirement decisions, construction capacity, and reliability are uncertain. The EPA’s final Cross-State Air Pollution Rule was signed July 6, 2011, with initial compliance beginning in 2012.
• Major projects include Plant Vogtle nuclear units 3 and 4 and Mississippi Power’s Kemper IGCC. Vogtle’s projected in-service cost was about $4.41B after expected financing-cost recovery; licensing, schedule, contractor disputes, and cost risks remain. Kemper expenditures totaled $488M through June 30, 2011; DOE grant and tax-credit benefits, regulatory approvals, litigation, and execution remain material dependencies.
• Mississippi Power gave notice in July 2011 that it intends to buy the Plant Daniel combined-cycle facility in October 2011, for about $84M cash and assumed debt with a $270M face value; estimated fair value of that debt was about $350M based on July rates. The accounting and regulatory treatment remained pending.
• Bonus depreciation could increase 2011 cash flow by an estimated $400M–$600M, but IRS guidance and application remained uncertain. Alabama Power storm repairs were estimated at $40M–$55M in operating costs and $135M–$165M in capital expenditures; recovery and reserve replenishment are relevant to future rates.
• Gulf Power requested a $93.5M annual retail rate increase and $38.5M interim relief; a Florida PSC decision was expected in early 2012. Southern Company also disclosed environmental litigation and regulatory proceedings; the Alabama Power NSR case was dismissed, but the EPA appealed. The Supreme Court displaced federal common-law claims in the New York greenhouse-gas case and remanded remaining state-law issues.
• Management reported effective disclosure controls and no material second-quarter change in internal control over financial reporting.

Important facts for investors to verify

• Whether Georgia Power’s rate recovery and the Georgia PSC’s decisions on its resource plan and capacity PPAs proceed as expected.
• Final environmental rules, legal challenges, compliance deadlines, required capital spending, and the extent to which costs can be recovered in rates.
• Vogtle and Kemper licensing, construction schedules, project costs, and availability of DOE financing or grant and tax-credit benefits.
• Progress on Gulf Power’s rate case, Alabama storm-cost recovery, and the Plant Daniel purchase and associated debt valuation.
• Underlying cash generation after construction spending, debt maturities and refinancing, credit availability, and sensitivity to weather, demand, and fuel costs.
• How the Georgia tax settlement, bonus-depreciation tax treatment, and other uncertain tax positions affect reported earnings and cash flow.