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As Gas Prices Fall, What to Expect in Energy Stocks


Independent power producers are severely exposed to the risk of falling prices due to the correlation of natural gas and electricity prices.

As Natural Gas (UNG) continues its spectacular flush below $3 and toward a tighter grip on the $2 handle, end users like households and restaurants will benefit from lower heating bills this year. Since settling at $3.096/MMBTU last Wednesday, the February contract for Henry Hub Natural Gas (NGG2) has tumbled almost 20% to $2.488/MMBTU (as of Tuesday's settle). Even in the wake of the jet stream that has shifted south and brought colder weather to the East Coast, albeit slightly behind regular schedule, there seems to be no end to the downtrend. Yet despite the numerous benefits from a demand perspective, some energy companies are not as lucky.

Independent power producers, especially those with generation portfolios that are heavily weighted toward coal-fired power plants, are severely exposed to the risk of falling natural gas prices. This is due to the correlation of natural gas and electricity prices. Although natural gas-fired power plants compose less than 25% of total US generation capacity, the fuel's role in serving demand at the margin (or peak load) leads to the correlation. Especially in the mid-Atlantic, where installed natural gas generation capacity is perched above the national average, the impact on electricity prices is highly evident. Within the Pennsylvania-Jersey-Maryland (or PJM) Interconnection wholesale electricity market, power prices at the West Hub point have fallen significantly from pre-recession levels. As power prices fall, energy generators see their gross margins shrink.

Specifically, FirstEnergy (FE) has 23,000 megawatts (or MW) in generation capacity, of which 64% is powered by coal and only 6% by natural gas. As a result of this concentration, it is a price-taker; thus, its revenues are effectively exposed to falling power prices, which are the result of falling natural gas prices. A company like GenOn (GEN), however, may have a comparatively stronger year. Of its 24,237 MW in generation capacity, only 31% is served by coal plants and 36% purely by natural gas. In addition, 27% of this total capacity is fueled by combined oil and gas. With many price-setting plants, GenOn stands to benefit in spite of declining power prices.

Despite the fact that the economics of coal-fired power plants are on thin ice, there is still a bit of support for the fossil fuel. As the United States Court of Appeals delayed implementation of the Cross-State Air Pollution Rule (CSPAR) with a court stay on December 30, 2011, energy companies need not concern themselves with enforcing emissions limitations; this would have resulted in shutting down coal-fired power plants across the nation. Early retirement of such plants would increase capital costs for many power producers. At the same time, perhaps finalization of CSPAR regulation in the future will prove to be a boon for natural gas demand and finally allow for an upswing on the price chart.

Baker Hughes reported, for the week ending January 13, that natural gas rig count was down 20 from the previous week to 791 total rigs. Year-over-year, the count is down more than 12% from 902. Still, while the rig count data suggests a bullish tone, the rate of production has not at all slowed. In fact, during the same time period, spot price natural gas has fallen more than 35.5%. In the end, it is the physical supply that impacts market analysis more than quantity of machines in play. As producers have steadily increased production per rig, natural gas in storage sits way above seasonal averages. Last Thursday, the weekly Energy Information Administration data release showed a net 95 billion cubic feet (Bcf) withdrawal from supplies. Although this figure was above the 86 to 90 Bcf range according to analyst estimates compiled by Platts, a provider of energy information, the five-year average of supply changes for the week is a 128 Bcf withdrawal. As a result, natural gas in storage sits at 3,377 Bcf, almost 500 Bcf over the five-year average and close to 400 Bcf higher than the level at the same time last year.

In the long-run, until terminals such as Cheniere Energy's (LNG) Sabine Pass LNG export terminal are up and running, we can expect the glut in supply to continue. This project is expected to allow for approximately 803 Bcf/year, or 2.2 Bcf/day, of LNG exports. Almost six months after receiving the Department of Energy (DoE) go-ahead for the Sabine Pass terminal, Cheniere Energy filed for approval of its proposed Corpus Christi LNG export terminal as well. This terminal is expected be completed in mid-2017.
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