Southern's Moat Still Strong Despite Regulatory Concerns

 Southern Company (SO) offers investors an uncommon opportunity to own one of the highest-quality utilities at a discount to our fair value estimate, thanks to its recent beating from market fears that its best-in-class regulatory relationships might be deteriorating. Cost overruns at Southern's new Kemper facility in Mississippi and concerns about construction costs at its new nuclear plant in Georgia have turned investors away in 2013. Southern's near-5% dividend yield is one of the highest in the sector and yet remains well supported by cash flows. As Southern resolves its regulatory issues, we think it once again will demonstrate the resiliency of its business model and produce the sector-leading returns that support its narrow economic moat.

Regulatory Compact Supports Southern's Narrow Moat
Southern Company owns a difficult-to-replicate network of energy generation, transmission, and distribution assets with which it provides electricity to 4.4 million customers in four states in the Southeast. Its utilities in Alabama and Georgia produce the bulk of earnings. Southern also operates a conservative but growing merchant generation segment, Southern Power, which typically sells its power through long-term agreements that mostly insulate it from commodity risk.

At its regulated utilities, state and federal regulators grant Southern exclusive rights to charge customers rates that allow its utilities to earn a fair return on and return of the capital it invests to build, operate, and maintain its power plants and distribution networks. In exchange, state and federal regulators set returns at levels that aim to minimize customer costs while offering fair returns for capital providers.

This implicit contract between regulators and capital providers should, on balance, allow Southern to earn at least its costs of capital, though observable returns might vary in the short run based on demand trends, investment cycles, operating costs, and access to financing. Intuitively, Southern should have an economic moat based on efficient scale, but in most cases, regulation offsets this advantage, preventing excess returns on capital. The risk of adverse regulatory decisions precludes regulated utilities from earning wide economic moat ratings. However, the threat of material value destruction is low and normalized returns exceed costs of capital in most cases, leaving us comfortable assigning Southern a narrow moat.

Rate-Making Is Key to Achieving Good Returns for Investors
The regulatory framework in which Southern's utilities operate is similar to utility regulation worldwide. Regulators typically set rates based on a target cost of capital composed of a target capital structure, interest costs, and a theoretical fair return on equity. Regulators then set customer rates that allow Southern to earn that target return on the capital it invests in its network.

Each state and federal regulatory body puts its own twist on this framework, some making it easier for utilities to earn a fair return on investment and some making it more challenging. Below, we break down how constructive regulation in Alabama and Georgia sets Southern apart from other U.S. utilities.

Alabama Power. Alabama state utility regulation uses streamlined, annual formulaic rate adjustments, including the rate stabilization and equalization mechanism, which incorporates forward-looking operating cost and investment projections and adjusts rates annually to ensure Alabama Power earns its 13.0%-14.5% allowed return on equity. With these favorable rate-making mechanisms, Alabama Power has averaged a 13.1% realized ROE during the past five years, well above utility averages. The average allowed return regulators granted U.S. utilities in the second quarter was 9.8%, and most utilities can expect to earn 100-200 basis points less because of mismatches between costs incurred and customer rates.

Changes  to Alabama Power's RSE format will shift the focus away from allowed ROE with a set capital structure to a weighted average cost of equity mechanism that allows for balance sheet flexibility. Importantly, earned returns are unlikely to slide materially under the new formula. Intervenors had called for allowed ROEs as low as 9%. In proceedings, the Alabama Public Service Commission specifically rejected the connection between current capital market conditions and a fair return to Alabama Power's investors. This stands out among utility regulators who elsewhere have used low interest rates and lower computed equity risk premiums to justify rate cuts.

Alabama Power recovers its capital investment through an annual process called rate certificated new plant. This rate-making mechanism allows Southern to adjust customer rates based on its planned capital investment in new plants and environmental upgrades for the next 12 months--again, a critical element in avoiding regulatory lag on returns. Regulators then true up customer rates every year to ensure Alabama Power is earning its allowed return. This is about as good as it gets for electric utilities. Most other utilities may adjust customer rates only when capital investments go into service. Large projects can leave many utilities with diminished returns and cash flow for many years. CNP gives Alabama Power a better match between cash flows and noncash earnings.

Alabama's constructive regulatory environment contrasts with many regulatory jurisdictions where utilities go through lengthy litigated rate reviews and have adversarial relationships with regulators and other stakeholders. While other utilities faced intense scrutiny for any rate increase request the past 18 months, Alabama Power negotiated 2012 and 2013 rate RSE filings that resulted in no change to customer rates, but allowed the utility to stabilize cash returns and leave headroom on rates for 2014.

Georgia Power. In Georgia, Southern enjoys a different but still constructive rate-making environment, supporting the utility's average 11.7% earned returns on equity during the past five years. Unlike Alabama, where rates are adjusted annually on a formulaic basis, Georgia regulators require the utility to file formal rate cases. However, like Alabama, cases are based on forward-looking projections, reducing the time between costs incurred and costs recovered through customer rates. Georgia Power typically settles its cases, avoiding confrontational litigation and allowing more flexible rate mechanisms. Recently, Georgia Power has operated with three-year rate plans and precertification for large capital costs, providing increased cash flow certainty.

These settlements (or alternative rate plans) allow some creativity as well. Georgia Power's interim cost recovery tariff approved in 2010 allows the utility to time its collection of unrecovered costs from customers so that it earns its allowed return on equity. Another example is the 2009 accounting order that allowed Georgia Power to offset lower usage-related earnings during the recession with amortization of existing regulatory balance sheet liabilities. In the company's 2013 rate case filing, Georgia Power asked for a $280 million rate increase for 2014 and an extension of the ICR with another three-year rate plan that would result in a total $482 million. We forecast a $215 million rate increase in 2014 and $550 million over the three-year period. The outcome could affect our view of the depth of Southern's moat in Georgia.

Georgia's constructive regulatory environment was a key factor that led Southern to propose in 2008 building two new nuclear reactors at its Vogtle nuclear plant for an estimated $6.1 billion to come on line in 2017-18. The project, along with two new nuclear units that SCANA is building in South Carolina, represents the first new nuclear construction in the U.S. in three decades. The cost of financing the reactors is being recovered through a specific tariff that adjusts rates annually based on capital invested to date. Before this latest rate review period, Southern had to submit its realized costs for certification to Georgia regulators for a formal review twice a year. Given the amount of capital--equity and debt--that Southern will invest in the project and the time it will take to complete, investors are rightfully concerned about the firm's ability to recover its costs with a fair return.

Cost Issues at Vogtle Surmountable, Regulatory Support Remains Strong
The nuclear units now carry a revised $6.8 billion price tag for shareholders and won't be finished until 2017 and 2018 after delays due to construction design issues. The delays are the subject of a $900 million commercial dispute with Southern's construction partners, including Chicago Bridge & Iron. Southern's liability could be as much as $425 million based on its ownership share, but jurisdiction for the suit has been settled in Georgia. This could be a critical factor in the contractors' decision whether to settle outside of court. We assume a 75% chance that investors will be on the hook for $300 million of costs (roughly $0.25 per share), but given the decision to hear the case in Georgia (a material positive for Southern), this could prove conservative. The worst-case decision would cost Southern roughly $0.50 per share of equity value. Either way, management maintains that it has discussed legal costs with regulators and expects to recover these costs.

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In a filing earlier this year, Southern asked for regulators to approve the new $6.8 billion cost projection. However, during hearings this summer--when we assumed pushback on the increased costs could materialize--regulators and Southern agreed to delay until 2014 the latest construction monitoring filing, giving the firm some flexibility while the lawsuit progresses. In practice, this also moves the review of the overall project cost into whichever period the above-budget expenditures take place, which could be as late as 2016 or 2017. Thus, once costs are known and cash is going out the door, Southern should get quick recovery. When Southern presented costs that could provoke controversial debate and force a confrontation between the company and regulators, they delayed the discussion likely for several years, illustrative of a very positive working relationship.

We still think investors should consider the potential for much larger increases in forecast Vogtle costs. In a worst-case scenario, Southern could have to agree to limit recoveries from customers to costs well below actual projected costs. This is similar to Southern's experience in Mississippi with its Kemper power plant project, but with projects as large and complex as a nuclear plant, the impact on shareholders could be much more significant. We think the chance of a material impairment related to the project is small and the market is assigning too high a probability to that worst-case scenario.

Kemper Cost Write-Off a Pain, but Storm has Passed
The Kemper integrated gasification combined cycle facility, also known as Plant Ratcliffe, is a coal plant initially proposed in 2008. It will use a first-of-its-kind technology (on an operational basis) to capture carbon dioxide emissions from burning cheap and local Mississippi coal. The facility will sell the captured CO2 and includes an on-site coal mine. Boosters for IGCC believe that when completed, the facility could demonstrate a place for coal in an emissions-compliance constrained world, but it has been a controversial project, to say the least. Given the complexity of the project, initial cost estimates proved too low and three times this year Southern has taken write-offs on the plant, together totaling $1.14 billion, anticipating it won't be able to recover forecast costs exceeding the budget regulators had approved for recovery through customer rates. The total projected cost for the plant is now $5 billion, of which about $550 million pertains to items such as the onsite mine and the CO2 pipeline that are not affected by the cost cap that Southern agreed to with Mississippi regulators earlier this year. These will be rate-based and earn full returns. Total relevant costs for the cap are $4 billion.

A primary driver of the cost overruns at Kemper was engineering that didn't take into account the complexity of completing a first-generation power plant. This required a major overhaul of how much piping would be needed to handle the project. Given the potential for a further delay from revamping the plant design, Southern has elected to employ extra shifts to speed completion of the project, which must go into service in 2014 to qualify for tax credits that drive material value for investors and defray costs for ratepayers. Southern's inability to recover cost overruns will hurt shareholder returns, but fears that the increasing costs of the plant have seriously harmed Mississippi Power's regulatory environment are overblown.

Much attention has focused on the $2.4 billion cap, but it's a misleading term as far as shareholders are concerned. Costs between $2.4 billion and $2.88 billion plus about $320 million in capitalized financing costs will be securitized, meaning Mississippi Power will recover the costs but will not earn a return on that capital. This means shareholders only bear the financing costs related to this capital while it amortizes those costs through customer rates. In addition, Mississippi Power will sell a portion of the project to SMEPA, an electric co-op in Mississippi, which cuts about $400 million off the rate-based cost Mississippi Power customers will bear. Adding the $530 million of approved costs related to the mine and CO2 pipeline brings the total bill for Mississippi Power customers to approximately $2.5 billion.

Even as costs come in over budget, customer rates go up, and shareholders bear a portion of the cost overruns, we think Southern's core relationship with regulators and customers remains constructive.

• Retail customers will pay for only 70% of the $2.5 billion approved for recovery, with the remainder recovered through Federal Energy Regulatory Commission-regulated wholesale rates with large customers. Retail customers are much more publicly vocal about rate increases, making it more difficult to pass along large, disputed costs.
• Mississippi regulators approved an increase in customer bills of 1.9% earlier this year following the utility's traditional rate-making process and a 15% increase in rates pertaining to Kemper, proving the regulatory process is far from broken. The utility was able to offset the 15% jump in retail rates related to previous Kemper costs with a 5% reduction in fuel costs due to lower natural gas, coal, and power prices. Low and falling energy prices soften the blow from higher infrastructure rates that Southern collects to earn its return of and return on investment, because more than two thirds of the average customer utility bill comprises energy costs that Southern passes directly to customers with no margin.
• Mississippi regulators are likely to approve a seven-year rate plan that will allow Mississippi Power to recover costs from customers at a fixed rate while amortizing its regulatory liability recorded at the beginning of 2013 to offset those costs to customers.

These rate mechanisms, which reduce the net impact on customer bills, make it easier for Mississippi Power to recover Kemper costs that shareholders otherwise would have to bear.

Dividend Is Attractive and Safe
We think Southern offers attractive cash returns and capital appreciation upside for income investors. We anticipate the company will increase its dividend 4% annually in the near term, largely in line with management's projections. We think Southern's growth potential combined with its near-5% yield offers more attractive returns than other regulated utilities that on average yield 4.2% with similar growth outlooks.

We also think the quality of Southern's utilities and regulatory environments makes it one of the safest dividends in the sector. Our cash flow analysis shows that even with as much as $1 billion of unrecovered cost overruns at Vogtle, Southern's dividend is well covered. Absent the overruns, Southern's dividend cash coverage in 2015 and 2016 would be 1.4 times, highlighting the jump in available cash as the large Kemper project is finished. Even amid the heaviest spending on the Kemper project in 2013, Southern's cash coverage is healthy.