This Stock Gets the Cold Shoulder From the Market

 Calpine is becoming a grandma stock. The market continues to ignore its consistent, growing free cash flow that management is dutifully returning to shareholders at a rate that exceeds grandmalike regulated utilities and pipeline partnerships. A competitively advantaged fleet, attractive markets, and management's smart capital allocation support continued cash flow generation and shareholder returns. Calpine offers investors an opportunity to pick up a consistent, cash-producing machine at a substantial discount to similar firms while offering the best upside and option value of any peer.

Calpine's reliable, growing free cash flow gets no love from the market. The stock trades at a 25% discount to our $28 fair value estimate and a significant discount to other utilities and pipeline operators. Based on our cash flow projections, Calpine currently trades at a 10 times price/cash flow multiple. This compares with much richer multiples for diversified and regulated utilities, independent power producers such as  NRG Energy (NRG), and pipeline master limited partnerships such as  Enterprise Products Partners (EPD) and  Magellan Midstream Partners .

Calpine Offers a 6% Effective Cash Yield With Growth
We think the market misunderstands Calpine's ability to produce steady, growing free cash flow. Management has returned $1.34 billion to shareholders through share buybacks since August 2011, an average of $536 million, or $1.20 per share, annually. At Calpine's current price, this represents a 6% cash return, well above the 3.6% average utilities sector dividend yield.

Calpine offers unmatched cash flow growth as well. In the past three years, it has produced 18% annual free cash flow growth, despite large swings in natural gas and power prices. We forecast 13% annual free cash flow growth for the next five years.

Free Cash Flow Estimates

In 2013, Calpine's adjusted EBITDA grew 5% to $1.83 billion, and free cash flow before growth investments grew 20% to $677 million, or $1.52 per share. Lower operating expenses, higher capacity payments, strong hedge performance, and new long-term contracts more than offset weak market conditions in Texas. In 2014, we estimate Calpine will earn $1.98 billion in EBITDA and $878 million in free cash flow before growth investments. This is in line with management's guidance for EBITDA ($1.9 billion-$2.0 billion) and free cash flow ($785 million-$885 million). Management recently raised both ranges $100 million to reflect benefits from the extreme winter weather and asset additions.

We expect Calpine's low-cost gas generation fleet and favorable market fundamentals will continue to support consistent, growing cash flow and higher returns on capital. The firm's competitive position supports dividendlike cash flows for three reasons.

Long-term offtake and tolling agreements support approximately 30% of Calpine's cash flow. These contracts typically have fuel pass-throughs and captive buyers. Many distribution utilities count on this contracted generation to maintain customer supply and grid reliability, so there is less risk associated with contract renewals.

Calpine benefits from rising and falling natural gas prices. When gas prices rise, Calpine's cost advantage to competing gas-fired power producers results in higher per-unit profit margins. Higher natural gas prices make other generation sources such as coal more competitive and could reduce Calpine's plant run times, but the higher margins offset the lower production volumes. If gas prices fall, Calpine benefits from higher run times that offset lower per-unit margins. During record-low natural gas prices in 2012, Calpine's generation volumes increased 22% from 2011 levels, keeping EBITDA flat despite lower margins.

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Capacity revenue currently contributes 25% of cash flow. That could double if Texas regulators decide to implement a formal capacity market. A recent report that the Brattle Group prepared for Texas grid operator ERCOT suggests the long-run equilibrium capacity price would be $107 per megawatt day if regulators adopt a traditional forward capacity auction framework. This is in part based on the Brattle Group's assertion that Texas must maintain a 14.1% reserve margin to prevent blackouts, up from ERCOT's current 13.75% target reserve margin. At $107/MW day, Calpine would realize an incremental $275 million of pretax margin, by our estimates. We continue to believe implementation of a capacity market is the most likely outcome, given that the majority of the Texas commissioners have shown modest support, but we currently don't incorporate any Texas capacity revenue in our fair value estimate or cash flow projections. In the Mid-Atlantic region, Calpine is set to collect $268 million of pretax margin from capacity revenue based on last year's capacity auction for 2016-17. Mid-Atlantic grid operator PJM will conduct the 2017-18 capacity auction in May.

Calpine Trades at a Discount to Net Asset Value
Our $28 fair value estimate implies a valuation of $725 per kilowatt for the company's natural gas fleet. This is approximately a 20% discount to recent new-build cost estimates for combined-cycle gas plants and a slight premium to recent transactions for less-efficient plants in Texas.

Our NAV bear case of $16 per share assumes Calpine's natural gas fleet is worth $550/kw, in line with recent market transactions for Calpine's own fleet. The company recently sold the 847 MW Broad River plant in South Carolina for $427 million ($504/kw), sold the 603 MW Riverside plant in Wisconsin for $392 million ($650/kw), and acquired the 1,050 Guadalupe plant in Texas for $625 million ($595/kw). However, many of its plants have much better economics than these three. Our NAV bull case of $40 per share values Calpine's fleet at new-build cost of $900/kw and assumes Texas implements a capacity market.

Polar Vortex Showcases Calpine's Option Value
This winter's severe cold weather in the Eastern United States led to spikes in power and gas prices and volatility, playing right into Calpine's hand. Calpine's option value grows when power and gas volatilities become less correlated. Volatility is Calpine's friend, but the market doesn't appreciate that optionality value. No other utility benefits as much as Calpine from increasing volatility.

The problem this winter has been gas supply shortages paired with record-setting electricity demand. New England, New York, and the Mid-Atlantic all realized record-setting power prices for a record-setting number of days in January. In Texas, electricity demand set a new winter record in January, with peak electricity use of 57.2 GW representing 96% of the state's generation capacity. Wholesale power prices in Texas reached the $5,000 per megawatt hour price cap Jan. 6. Calpine's 8.0 GW efficient Texas fleet was well positioned to benefit from these peak power prices.

Gas supply and electric grid reliability concerns have reached as far as Southern California, where the state's electricity grid operator on Feb. 6 asked residents to conserve gas and electricity because gas-fired power plants couldn't get enough gas to run. Several utilities, including Calpine, have told us they were burning kerosene and other oil-based products at times this winter because either they couldn't access natural gas, or the substitute fuels were cheaper than sky-high spot gas prices.

High and volatile gas prices combined with record-setting winter power demand to produce even more volatile power prices. Day-ahead prices hit nearly $1,000 per megawatt hour in the Mid-Atlantic region on Jan. 28 and six times hit $500/MWh or higher. This compares with average prices near $50/MWh. In Houston, day-ahead prices topped $200/MWh eight times on Feb. 6-7 when temperatures stayed below freezing for more than 48 hours. The Northeast and New York City also have seen abnormal electricity price spikes recently.

Power Markets Pricing In No Volatility
Forward power prices suggest all of this volatility will disappear. Forward curves in most Eastern U.S. markets are backwardated and suggest a substantial reduction in the spread between yearly high and low prices. There is a substantial drop in Mid-Atlantic region forward electricity price implied volatilities going out to 2015 and 2016 as of mid-February.

Implied Volatility of Mid-Atlantic Peak Power Prices

We think the market is significantly underpricing future volatility and, by association, Calpine's option value. Challenging economics and environmental regulations have led to 20 GW of coal plant closures since mid-2010, and we count another 38 GW of pending coal plant closures that utilities have announced. In all, closed and pending retirements will reduce the U.S. coal generation fleet about 18%. This will tighten supply/demand balances that already proved tight this winter during peak demand events. Proposed carbon emissions caps expected from the Obama administration later this year could bring another wave of plant retirements.

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Capacity markets also are reflecting expectations for more volatility. Bids into the recent 2017-18 forward capacity market auction in New England fell short of the grid operator's peak demand forecast, mostly due to planned plant retirements representing 10% of the region's generation supply. Prices doubled from recent New England capacity auctions and new plants will receive $15 per kilowatt month, nearly double the highest forward capacity prices we've seen in any forward capacity market auction in the U.S.

Power Market Reform Debate Continues in Texas
The Brattle Group recently released its final report proposing a 10.2% economically optimal reserve margin for the Texas power grid, well below grid operator ERCOT's current 13.75% target reserve margin. The economically optimal reserve margin weighs increasing capital costs against decreasing scarcity event costs. To meet the industry standard 1-in-10 loss of load event, the Brattle report suggests grid operators must maintain a 14.1% reserve margin. If regulators adopt a capacity market, Brattle estimates the long-run equilibrium capacity price would be $107/MW day, compared with our $130/MW day estimate. The total net impact on customer rates would be roughly 1% compared with the current energy-only market, Brattle estimates. This relatively low impact on customer bills should be appealing to regulators.

ERCOT also is reassessing its long-term demand forecasts, which are a critical input for any market reform analysis and will affect the timeline for generation needs. ERCOT recently reduced its 10-year annual peak demand growth forecast to 1.3%, from 2.5% in its previous forecasts. This is lower than the 1.8% load growth since 2009, according to Calpine management. The cut in forecast peak demand growth could reduce the urgency of implementing market reform in Texas and the need for new generation requirements, potentially delaying Calpine's upside. Regardless of the lower load growth expectations, new-build generation will be needed in Texas during the next decade, and current depressed wholesale power prices don't encourage developers to make 30-year investment decisions.

Calpine is aggressively allocating capital to Texas. Management recently acquired the 1,050 MW Guadalupe, Texas, natural gas-fired plant for $625 million ($595/kw). For $15 million, Calpine also acquired the rights to develop an additional 400 MW peaker plant, contingent on supporting market fundamentals.