Between now and November 2008, natural gas prices are expected to remain within a $5-10 band, according to Pace Global Energy Services. However, developments in the power and gas sectors suggest excursions from that trend could range from a low of $2.50 to a high of $20/MMBtu, said Art Holland, Pace director of power and forecasting. Such wide travel in prices is quite unlikely but possible, he said.
Speaking at GasMart 2007 in Chicago last week, Holland described gas and power markets whose futures are intertwined, with gas prices largely influenced by gas-fired generation demand, power largely influenced by gas prices, and both subject to the whims of Mother Nature.
“Energy prices are and increasingly will be volatile and highly uncertain, and any energy-related decision must incorporate and acknowledge that uncertainty,” he said.
Influencing the outlook for energy prices is a number of factors, including the potential for legislation to limit emissions of greenhouse gases (GHG); the development of clean coal technologies, such as integrated gasification combined-cycle (IGCC) generation and carbon capture and sequestration; the further development of renewable energy sources; and the market penetration of demand-side resources, e.g. load shedding.
Weather enters the picture on two fronts: temperature-driven demand for power (to run air conditioning) and weather’s effect on the level of gas in storage. And because of its influence on gas prices, the gas storage level indirectly influences price-sensitive demand for gas to fuel power generation.
“Finally, there is the issue of sectoral price elasticity of demand,” said Holland. “What I mean by that is while industrial consumers may have some options if gas prices go extremely high: they can change production schedules; they may have other fuel options. In the utility or power sector you may not have a choice because if the available supply that you have to meet load is gas-fired and the price of gas is very high, you don’t have the choice of changing your production schedule. You have the choice of serving your load or not serving your load. And as we saw back in the late ’90s, the value of lost load can drive that decision to drive prices up to the thousands of dollars per megawatt hour for a short period of time.”
As for new generation development, Pace is predicting a relatively balanced portfolio of fossil and renewable technologies. While nuclear, conventional coal, IGCC and natural gas are all very much in the running, gas is projected to account for about 34% of the generation mix in 2025, according to Pace. “Over the long-term and short-term, a good share of new generating capacity is expected to be gas-fired,” Holland said. “New gas-fired capacity is particularly important for urban areas, both for environmental reasons and because that is where the demand is emerging for new capacity.”
Holland highlighted Northern California, the southeastern part of the PJM Interconnection (the Baltimore Gas and Electric and PEPCO service territories), New York City and Houston as areas most in need of new generating capacity. “I don’t want to lead you to believe that the lights are going to go out in these regions,” he said. “I don’t think the lights will go out, but you will see some power price impacts of these shortages if new supplies aren’t brought on fairly soon.”
In Texas, for instance — where TXU Corp. has found that planning new coal plants and actually building them are two entirely different things — where one looks is what determines whether gas- or coal-fired generation is the most economically favorable. In the northern part of the Electric Reliability Council of Texas (ERCOT), TXU’s Dallas-area stomping ground, coal is clearly favored from an economic standpoint. In ERCOT gas-fired generation sets the marginal price for power and coal plants, with their lower relative fuel costs, can do quite well.
However, it’s the Houston area of ERCOT where new power generation is most needed, and Houston is a Clean Air Act nonattainment zone. So while economics favor coal-fired generation in northern ERCOT, “the reality of the environmental situation and the location of the need for new capacity in primarily urban areas means that a lot of that new capacity could in fact be gas-fired,” Holland said.
However, in northern Illinois, for example, where there is not a great demand for new generating capacity currently, the economics of coal- and gas-fired plants are about even, so Holland said the two could be developed in tandem in the coming years.
The addition of renewable resources is, to a certain degree, an alternative to new gas-fired generation, Holland said. However, renewables can be something of a wild card where energy prices are concerned. Most renewables, such as solar and wind, are intermittent, meaning backup power is required to carry the market through periods of darkness and windlessness, and this is a potential source of increased volatility.
Further adding to volatility is the profile of North American gas demand. The industrial sector, which has historically been baseload demand, is exhibiting flat or declining growth. “The increase that you’re going to see from the power generation sector is highly volatile demand, and it will become increasingly volatile as new renewable resources come into commercial operation,” Holland said.
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