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Is Calpine Developing a Moat?

Growing electricity demand in Texas, environmental legislation in California, federal emissions regulations, and increasing market uncertainty may help Calpine establish a moat.

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Fundamental changes in  Calpine’s (CPN) core Texas and California markets are creating opportunities for it to establish a moat in what we typically consider no-moat wholesale power markets. Above-average electricity demand growth in Texas, environmental legislation in California, federal emissions regulations, and increasing market uncertainty give Calpine’s low-cost flexible-generation fleet a growing competitive advantage and support our positive moat trend rating. We think the market fails to give Calpine full value for the cash flow benefits we think it can realize as power prices rise, plant run times increase, and grid operators offer power plant owners incentives to meet growing demand.

Calpine’s Low-Cost Advantage
Calpine is the largest natural gas power producer in the United States, with 2.5 GW of simple-cycle combustion turbines, 23.9 GW of combined-cycle combustion turbines, and 725 MW of California geothermal generation. Its natural gas generation portfolio is almost evenly split across Texas, California, the Southeast, and the North.

Calpine expanded aggressively in the early 2000s, buying and building high-efficiency natural gas power plants primarily in Texas and California, where low gas prices, deregulation, and power demand volatility offered attractive economics. By 2004, its gas-fired fleet had grown to 25 GW, up from 4.3 GW in 1999. But rising gas prices and industry overbuild sunk those economics in the mid-2000s, sending Calpine into bankruptcy in 2005 along with many of its peers.

Calpine emerged from bankruptcy in 2008 and now has the most concentrated exposure to natural gas generation among its large independent power producer peers  Dynegy (DYN) and  NRG Energy (NRG). This gives it much less downside than its peers to falling gas prices, which are a primary cost, but much less upside to rising gas prices, which tend to drive higher margins for coal and nuclear operators.

Calpine’s low-cost competitive advantage has several sources:

  • Its fleet is only 13 years old on average, compared with the national average of 18 years for gas plants and 36 years for coal plants.
  • Calpine has best-in-class maintenance that keeps its plants running even in high-demand periods. Its forced outage factor in 2012 was just 1.6%, among the lowest in the industry, and its maintenance expenses were flat in 2012 despite a 16% increase in generation.
  • Calpine’s average steam-adjusted heat rate of 7,300 btu/kwh makes the company’s peaker and intermediate natural gas fleet 25%-30% more efficient than the average fossil-fuel power plant and significantly more efficient than peers Dynegy and NRG.

Weighted Average Capacity IPP Heat Rates

Source: Morningstar, Company filings

Since grid operators call on the lowest-cost generators to meet electricity demand at any given time, Calpine’s low-cost fleet means it realizes higher plant run times and higher margins than its competitors during peak demand times. Calpine’s operating costs still are higher than most nuclear and coal plants, which rely on much cheaper fuel sources than natural gas. But when coal and nuclear plants can’t meet all of the demand in Calpine’s regions, its plants are among the first to provide that incremental power source.

Calpine’s cost advantage shows up in its industry-leading capacity factors. Its fleet has achieved capacity factors greater than 44% for the past three years, which compares favorably with a 29% national average capacity factor over the same time frame. As gas prices dropped below $3/mcf last year, Calpine’s high-efficiency natural gas plants became competitive with high-cost coal plants, and its capacity factors climbed to a record 54% for the full year.

Texas Power Market: Attractive Supply-Demand Dynamics
Texas faces significant capacity constraints due to predicted 2% generation demand growth, double the national average. Without any market changes, the Texas grid operator, ERCOT, predicts the state’s current generation capacity will fall short of its target 13.75% reserve margin by 2014 and won’t meet forecast peak demand starting in 2022 (see graph below).

ERCOT Falling Reserve Margin

Source: ERCOT

 

The key problem in Texas is the absence of a structure to incentivize new-build generation. Texas is an energy-only market, which means returns for new-build power generation depend entirely on hourly demand and power prices. For developers making long-term capital-intensive investments in new power plants, relying on volatile power prices alone adds significant risk that they won’t earn their costs of capital during the life of the investment.

We estimate that an average new natural gas plant requires at least a $55/MWh average realized price across a 30-year life to recover its investment and earn a fair market return. Calpine management estimates that its new natural gas plants require just $38/MWh to recover its investment. Rolling 12-month peak power prices in Texas have averaged just $35/MWh the past 24 months and topped $55/MWh only 40 days during the period that included the record-breaking August 2011 heat wave. Current forward curves remain flat, despite regulatory indications for future market incentives.

To incentivize new power generation development and retain existing generators, ERCOT is exploring the following five options.

1) Energy-only with market-based reserve margin

2) Energy-only with price-adders to support a target reserve margin

3) Energy-only with backstop procurement at a minimum acceptable reliability

4) Mandatory resource adequacy requirement for load-serving entities

5) Resource adequacy requirement with centralized forward capacity market

Independent consultant Brattle Group proposed options 4 or 5 as the best solution for Texas’ “missing money” problem, defined as the missing incentive in current power prices for developers to build new generation. Calpine management quantifies missing money as the difference between the cost of new-build generation ($900/kw) and current market values of CCGT generation in Texas based on recent transactions ($500-$550/kw).

In November 2012, state regulators began to show particular interest in implementing a dynamic operating reserve margin. Operating reserves are present in most energy markets to respond to unpredictable loss of generation, demand surges, or transmission line interruptions. In Texas, current operating reserves stand at 4,250 MW, or roughly 5% of total state generation supply. The state regulator, PUCT, is contemplating increasing its operating reserves by 2,000-4,000 MW. ERCOT, the state grid operator, back-tested the potential impact and indicated it would have increased weighted-average power prices $4/MWh-$15/MWh based on potential caps and operating reserves.

Ultimately, we believe a capacity market (option 5) offers the most efficient market signal to developers. Grid operators in New England, New York, and the Mid-Atlantic region operate robust capacity markets. The proposed Texas capacity market is similar to the Mid-Atlantic region Reliability Pricing Model, which sets prices that all load-serving entities must pay to power plant owners who make their generation capacity available at any given time. Each auction sets prices three years out, giving developers and existing generators at least three years of fixed cash flows regardless of what power prices do.

California Power Market: Tough Environmental Goals Create Problems
California’s grid operator, CAISO, also must address market forecasts that suggest there won’t be enough supply to meet demand in the coming years. Unlike Texas, where rising demand is the primary danger, California is struggling to find ways to maintain stable generation supply as it adds more variable renewable generation such as solar and wind power. When the wind stops blowing or the sun isn’t shining, California must have enough traditional generation capacity available to meet demand.

California’s problem stems from tough environmental regulations. State law AB 32, which was passed in 2006, mandates a return to 1990 levels of greenhouse gas emissions by 2020. To meet this goal, the state implemented a renewable portfolio standard and, in January, a carbon emissions cap-and-trade program. The renewable portfolio standard requires utilities to source 33% of their electricity from renewable energy by 2020, the fourth-toughest state renewable portfolio standard in the U.S.

In the cap-and-trade program, CAISO set the reserve carbon price at $10 per metric ton, and carbon credits currently trade in the mid-teens. Before AB 32 was delayed in late 2011, market expectations indicated that power prices could rise 5% from pre-AB 32 levels owing to the carbon caps.

Significant additions of renewable generation could saturate the market with off-peak supply, particularly from the state’s significant solar portfolio. This oversupply would depress prices during the day but also create premium value for peak supply to meet the ramp-up in on-peak demand.

Compounding the problems from AB 32, the California State Water Resources Control Board in October 2010 approved a once-through cooling, or OTC, policy, which limits the use of coastal waters for power plant cooling. Estimates suggest 16 power plants, representing 18.5 GW of capacity, will have to either make environmental modifications or retire. Given current market prices, we suspect most threatened plants will shutter, further limiting the supply of reliable generation to meet those peak periods of demand.

Market Not Realizing Calpine’s Long-Term Value
We think Calpine is worth $26 per share, an 18% discount to its market price as of late May. Its low-cost, high-efficiency fleet positions Calpine to benefit from favorable power market trends across its operating regions, particularly in Texas and California, where the company should benefit from tightening supply-demand conditions. We think the market is ignoring the long-term value and margin expansion it should be able to realize in its core regions during the next 3-4 years regardless of the direction natural gas prices take.

Texas
Texas accounts for 36% of projected 2013 EBITDA, rising to 43% of our normalized midcycle EBITDA estimate. This profit growth is due primarily to increased power prices and sustained output, partially offset by lower margins from increased input costs from higher natural gas prices.

Incorporating the market-incentive schemes that Texas regulators are considering offers significant upside to our EBITDA estimates and fair value estimate. For every $10/MW-day in capacity payments, we estimate Calpine would realize $27 million of annual pretax margin based on Calpine’s estimated 7,250 MW of available capacity payments after accounting for long-term PPA contracts. If capacity prices rose to $125/MW-day, in line with current eastern U.S. capacity prices, our fair value estimate would rise 35% to $35 per share. Incorporating a potential energy-only market incentive with a target operating reserve margin would raise our fair value estimate 10% to 50%.

Calpine management said it would like to add to its fleet in Texas, further positioning the company to benefit from the state’s supply constraints and proposed market incentives. Management is targeting plants it could buy for prices below its estimated new-build cost ($900/kw). In late 2012, Calpine acquired the 800 MW Bosque Energy Center in Texas for $432 million ($540/kw). Calpine is also adding 400 MW summer peaking capacity and increasing efficiency at its Deer Park and Channel Energy Centers, in service by 2014. The company also recently announced 300 MW of turbine modernizations and upgrades at its current Texas facilities, with an in-service target date of 2015-17. Energy Future Holdings’ pending bankruptcy could offer buying opportunities.

To free up capital, Calpine has begun divesting assets outside Texas. Last year, the company sold the 847 MW Broad River plant in South Carolina for $427 million ($504/kw) and the 603 MW Riverside plant in Wisconsin for $392 million ($650/kw).

California
Calpine’s contracts allow it to pass through to customers 65% of its cap-and-trade costs. For its uncontracted plants, we estimate that market heat rate expansion as a result of the cap’s impact on less efficient gas plants will offset Calpine’s carbon costs. For every 5% increase in our assumed market heat rates in California, our fair value estimate increases $2 per share.

If the state replaces its resource-adequacy market with a forward-capacity market, it would reward incumbent fleets with quick demand response capabilities like Calpine’s. Similar to Texas, a $125/MW-day capacity price increases our fair value estimate 31% to $34 per share.

As with Texas, Calpine continues to increase exposure to California. In 2013, the company’s 75% ownership in the 619 MW Russell City combined-cycle plant and the 120 MW Los Esteros plant will come on line under long-term contracts with PG&E.

Southeast, North Regions
Outside of Texas and California, Calpine stands to benefit primarily from tightening coal plant environmental regulations. Calpine has no coal plants in its fleet and needs no environmental upgrades to meet the new standards as it emits a significantly lower level of pollutants than the industry average. As coal plant closures reduce the generation supply in Calpine’s core regions, it should be able to capture significant margin expansion independent of natural gas prices.

Calpine also would benefit from the U.S. EPA’s recently proposed Greenhouse Gas Tailoring Rule, which sets carbon emissions caps for new power plants so low that they would virtually eliminate new-build coal generation and some new-build gas generation. If the EPA sets those same standards for existing power plants, it would significantly reduce the amount of coal generation, which account for 34% of total U.S. CO2 emissions, and increase the need for natural gas generation.

The EPA’s recent power plant emissions regulations are in response to a 2007 Supreme Court ruling that allowed the EPA to consider carbon dioxide as a hazardous pollutant under the Clean Air Act. The implication is open ended, with the potential for long delays, court challenges, and phase-in periods. Regardless of the time period, Calpine can only benefit. Its fleet average CO2 emission rates are currently 13% below the current 1,000 lb emission limit. If existing coal plants must close, Calpine’s incumbent, efficient fleet would benefit from higher run times and higher realized power prices at its plants in the Southeast and North regions.

Andrew Bischof does not own (actual or beneficial) shares in any of the securities mentioned above. Find out about Morningstar’s editorial policies.