When Will These 4-Star Utilities Power Up?
Despite their near-term challenges, we still see upside.
Second-quarter results highlighted the struggles still facing utilities with power market exposure in the Midwest and Texas. In the Midwest, Exelon (EXC) and Dynegy (DYN) continue to face near-term challenges at their nuclear and coal plant fleets because of weak power prices and unfavorable transmission congestion. In Texas, Calpine (CPN) reported headwinds from more normal weather and falling spark spreads. Despite the near-term challenges for these power producers in the Midwest and Texas, we continue to believe tightening reserve margins and more-volatile prices offer attractive upside for shareholders.
Exelon Still Fighting Power Market Weakness, but Wide Moat Intact
Exelon's leverage to the Midwest and Mid-Atlantic power markets gives it the most upside of any utility to our bullish outlook for power prices. But that upside remains fleeting in stubborn power markets. We would be worried about moat degradation as power markets and earnings languish, but Exelon's operating performance preserves its cost advantage and upside potential. Exelon's nuclear fleet continues to operate at world-class levels, on track to post a full-year capacity factor near 94% compared with an industry average below 90%. We estimate Exelon's nuclear fleet--the primary source of its wide moat--will continue producing double-digit returns on capital even with flat gross margins through 2015.
Our $42 fair value estimate and bullish long-term outlook remain intact even though our mark-to-market valuation is closer to $30 per share, near the current stock price. On a midcycle basis, we still think Exelon can earn more than $4 per share, but in the current market, we think Exelon will struggle to top $3 in earnings per share in 2015. The key near-term concern is the continued slide in Exelon Generation's hedged gross margin; the unit's 2013-15 hedged gross margin forecast has continued to fall with each subsequent quarter, apart from a brief jump up in March. The high end of management's gross margin sensitivity range also continues to fall, with the high-end 2015 estimate now down to $8.7 billion, from $11.05 billion when management first introduced the range in November.
Management maintains there is $2-$4 per megawatt hour upside in the power markets, in line with our thinking. We estimate a $3/MWh (10%) rise in power prices would yield $400 million of gross margin in 2015 ($0.30 consolidated EPS), even with 44% of its forecast output hedged. On a fully open basis, management said there was $550 million of gross margin upside (about $0.40 consolidated EPS). To preserve that upside, management has pulled back its hedging and was 8% below ratable in 2015 as of June 30. The open position relative to power prices is even larger, given the natural gas options management said it is using.
To combat top-line weakness, Exelon continues to do a commendable job managing operating expenses. Management said it will realize $305 million of cost synergies in 2013 and $550 million run rate in 2014 related to its Constellation acquisition last year. Management also said it will cut an additional $100 million of Exelon Generation operations and maintenance expense this year and targets flat Exelon Generation O&M through 2015. With flat gross margins likely through 2015, cost control will be critical to maintaining current EBITDA levels in the next few years.
Management expects to get $50 million-$70 million of savings from Constellation Energy Nuclear Group ($25 million-$35 million for Exelon based on its 50.01% share) out of its July 30 agreement with joint venture partner EDF to transfer operations of the three CENG nuclear plants to Exelon. The deal gives EDF a put option starting in 2016 to sell its 49.99% stake in CENG at a negotiated fair market value. If EDF exercises its put, Exelon would face what we estimate would be more than $1 billion of investment to add 2 gigawatts of capacity to its 17 GW nuclear fleet, net of its $400 million guaranteed distribution rights as part of the deal. The put option's 2016 effective date suggests EDF is willing to hold out for a rebound in power markets while Exelon strengthens its balance sheet to absorb an investment of that size. In addition, EDF will receive a $400 million cash distribution from a Generation-funded loan, and CENG subsequently will pay Exelon interest and principal on the loan.
We don't see any near-term threat to Exelon's dividend. Even if power markets remain at current levels the next three years, we estimate Exelon will be able to sustain at least a 60% payout ratio at its current $1.24 per share annualized dividend, in line with peers. We expect earnings from Exelon's three distribution utilities will easily cover the dividend, especially after ComEd and BG&E finish their rate cases. However, we don't see much, if any, dividend growth coming in at least the next two years.
On an operating basis, Exelon earned $1.23 per share during the first half of 2013, down from $1.44 in the first half of 2012 but on track to meet our forecast and management's $2.35-$2.65 guidance. Second-quarter adjusted EPS fell to $0.53 from $0.61 a year ago. One key year-over-year impact in the second quarter came from a 10% drop in realized margin at Exelon Generation's Midwest fleet.
Dynegy: Basis Differential Highlights MISO Transmission Constraints
We are maintaining our $26 fair value estimate and no-moat rating for Dynegy after the firm reported second-quarter adjusted EBITDA of $8 million compared with $11 million in the year-ago period. Management lowered its 2013 adjusted EBITDA forecast to $200 million-$225 million from $250 million-$275 million. It increased its free cash flow guidance to $190 million-$215 million from $140 million-$156 million because of the benefits of a recent debt refinancing. We've reduced our adjusted EBITDA forecast in line with management's new expectations but are maintaining our long-term forecasts, and our 2013 adjustment has no material impact on our fair value estimate.
Dynegy's coal segment performed poorly in the second quarter and was the main driver for the lower EBITDA guidance. The unit reported a $24 million adjusted EBITDA loss, compared with positive $5 million EBITDA during the same year-ago quarter. A widening of the basis differential between the Indy Hub and the locational marginal pricing compressed margins. Transmission outages and constraints, planned generation outages, and additional generation all stressed the basis differential higher.
Hedging the differential is complicated by an erosion of the correlation between the LMP and what is hedged at the more liquid Indy Hub. The break in the correlation resulted in lower prices received at Dynegy's local plants and also increases financial settlements on the Indy Hub hedges without a correspondingly higher price at Dynegy's plants. Management has mitigated the full-year basis effect by reducing Indy Hub hedges and purchasing firm transmission rights for the remainder of the year.
Management's initial guidance for the full-year basis differential between Indy Hub and Dynegy LMP was $4.36/MWh; management now expects $7.11/MWh. With an expected 22 million megawatt hours of coal segment generation, the increased differential results in a negative $60 million full-year impact. The Midcontinent Independent System Operator is working to relieve transmission congestion, with numerous transmission upgrades planned. Also hurting coal segment results were plant outages at Dynegy's Baldwin, Hennepin, and Havana facilities leading to lower gross margins and higher operating expenses.
The gas segment's adjusted EBITDA increased $21 million in the second quarter to $53 million, mainly benefiting from the absence of negative settlements relating to legacy put options. Plant capacity factors declined 28% because of lower spark spreads, the result of higher natural gas prices, at the Kendall, Independence, and Casco Bay facilities. Lower spark spreads make it less economic for the plants to run, particularly in off-peak hours.
In July, the Illinois Pollution Control Board denied Ameren's request to transfer the company's variance to Dynegy, which in March agreed to acquire Ameren Energy Resources for $622 million. In late July, Dynegy filed with the IPCB to rejustify the merits of the variance request. The company is also awaiting approval from the Federal Energy Regulatory Commission, with management targeting a fourth-quarter close. Dynegy increased its expected merger synergies from $60 million to $75 million as a result of additional opportunities from delivered coal reduction and further reduction in operating expenses. We have adjusted combined synergy savings in our discounted cash flow valuation, but this had no effect on our fair value estimate.
Calpine: Fundamentals Support Positive Moat Trend Despite Weaker 2013
We are reaffirming our $26 fair value estimate and no-moat rating for Calpine after incorporating first-half results. Calpine reported a 15% decline in second-quarter adjusted earnings, and management narrowed the top end of its 2013 adjusted EBITDA guidance to $1.8 billion-$1.85 billion from $1.8 billion-$1.96 billion. Management had increased the lower end in April. Weak performance was due to reduced generation output resulting from lower spark spreads, higher natural gas prices, and power plant sales. We have reduced our 2013 earnings estimate because of cooler-than-expected weather, but our long-term forecasts are intact.
Management reported that normalized Texas load grew 4%, supporting our view that supply/demand dynamics in the state should benefit low-cost operators like Calpine. We believe Calpine's industry-leading efficient fleet should benefit from contracting reserve margins in Texas and California. Also, our option-based model supports our view that the market is ignoring the full cash and option value of Calpine's fleet. The regulatory discussion remains fluid, with industry participants hoping for further clarity on proposed market incentives by the end of this year.
In the second quarter, Calpine's combined fleet generation fell 18% to 23 gigawatt hours with average capacity factors decreasing to 43.4% versus 51.0% in the same year-ago quarter. In 2012, the company sold two contracted assets in the North and Southeast regions, Riverside and Broad River, which run at higher capacity factors. Calpine replaced those assets with Texas capacity that runs less. Unfavorable mild weather, particularly at Calpine's Texas and North regions, and higher gas prices hurt year-over-year generation and earnings. We incorporated higher natural gas prices in our 2013 forecast and don't foresee a repeat of record 2012 generation levels in our five-year forecast. Second-half generation in the West region should increase when the Russell City and Los Esteros plants come on line in California. As of June 30, Calpine's updated hedged position leaves the company sufficiently open to a recovery in power prices.
During the first half of the year, management completed its $400 million stock-repurchase program. Cumulative repurchases are $1 billion since the program began. We believe management will buy back additional shares in the second half of the year, although it hasn't announced any additional repurchases. Given the stock's current discount to our fair value estimate, we think share buybacks would be value-accretive.
Travis Miller does not own (actual or beneficial) shares in any of the securities mentioned above. Find out about Morningstar’s editorial policies.