National gas forecast is flat
by Amy McCullough
Published: December 21,2009
After an attempt to keep updated natural gas price forecasts out of the upcoming Public Service Commission hearings regarding the proposed Kemper County plant, Mississippi Power Company has filed the data confidentially with the Commission. MPC has said high and volatile natural gas prices make the economic case for its proposed $2.4-billion lignite coal plant.
A week after the filing, the federal Energy Information Administration released its updated natural gas forecast Dec. 14. While ratepayers groaned when prices spiked to $9 per million Btu in 2000, in 2009 the average daily market price of gas has fallen below $4 per million Btu. The new report predicts prices will remain low for the next several years. The EIA predicts that gas will rise to more than $6 per million Btu in 2012; more than $7 per million Btu in 2026; more than $8 per million Btu in 2030; and $8.88 by 2035, where the forecast ends.
In a November motion, MPC said that the Commission’s request for additional natural gas price forecasts for the upcoming resource hearings was vague and unnecessary since the company had already submitted price scenarios. No response from the Commission was filed publicly. MPC submitted the data confidentially for proprietary reasons on the Dec. 7 deadline.
MPC has shown the potential cost savings of the lignite coal plant through a range of low and high natural gas forecast scenarios without revealing the actual numbers used.
Phase I hearings took place in October, and Phase II will occur in February, after which the Commission will determine the best solution for the new baseload energy need predicted for 2014, in the company’s service area of 23 counties in southeastern Mississippi. Baseload generation is the amount of power needed to meet a region’s continuous energy demand. Nationwide, energy from coal and nuclear energy are traditionally used for baseload generation. The Kemper plant would provide an effective capacity for 582 MW.
MPC’s data, along with proposals from independent power producers (IPPs) who own natural gas plants, were submitted to the Commission Dec. 7.
MPC argues that the Kemper plant would save its customers in the long run through the low cost of lignite coal, which will have lower and more stable costs for the future. Lignite is underground at the plant site, which would eliminate expensive transportation costs. If approved, the plant would operate commercially in May 2014.
But the gas market has changed dramatically in the past few years due to new technology enabling natural gas to be drilled from rock called shale. U.S. natural gas reserves and supplies are at record highs, and, despite historic volatility, many experts forecast low prices for the next 25 years.
Utilities such as Progress Energy in North Carolina are replacing coal-fired units with natural gas-fired facilities. Entergy Louisiana just stopped construction on a project converting an existing natural gas plant to a coal-burning plant, at a cost to ratepayers of $208 million; the company cited lower natural gas prices as a reason. Exxon Mobil, the world’s largest publicly-traded oil company, announced a $41-billion agreement this month to acquire XTO, a company that produces substantial amounts of gas from the Barnett shale region of Texas. The chief executive officer of BP, third-largest global energy company and fourth-largest company in the world, has said the United States is sitting on over 100 years of natural gas at the current rates of consumption.
MPC’s vice president of generation development, Thomas Anderson, said in a Mississippi Business Journal interview that he could not speculate about the reasons for other utilities’ decisions. Utilities rely on what is called a generation mix for reliability. Utility options include nuclear, gas, coal, hydro or other energy resources.
“Everybody has a different mix; everybody has a different load factor, so they have different economics,” Anderson said. “I would not expect every utility to come up with the same answer. If that was the case, we’d all be building the same kind of plant all the time…We do what is in the best interest of our customers,” he said.
Anderson said optimistic and negative views about natural gas as well as high and low possibilities for carbon taxes were taken into account in the 16 different price scenarios used in their docket filings. An optimistic view of natural gas would plan for an abundance of shale gas, gas coming from Arctic and Alaska, reliance on imported liquid natural gas (LNG) being unnecessary, favorable weather and speculator activity not affecting the market negatively, he said.
“We are not anti natural gas,” and MPC actively purchases of natural gas almost daily on the market, Anderson said. MPC doesn’t want a “disproportionate amount of natural gas in (its) mix,” he said.
Christopher Ross, vice president of global consulting company Charles River Associates (CRA), forecasted a range of low, moderate and high natural gas prices that MPC used in its evaluations. CRA advises investors, regulators and oil and gas companies.
In his Phase II testimony, Ross said, “Natural gas prices have historically been volatile and this is likely to continue.”
Ross said limited U.S. storage capacity along with potential cap-and-trade legislation and possible environmental restrictions on the new technologies for extracting gas from shale reserves make the long-term natural gas market uncertain. Factors contributing to historical natural gas price volatility are extreme weather conditions, destruction of facilities by hurricanes, speculators and the global trends of the LNG market.
Ross declined an interview with the Mississippi Business Journal.
James Sweeney, senior vice president of energy management at KGen Power, does not disagree with Ross’ testimony. KGen is an IPP that owns KGen Hinds, LLC, a natural gas-fired combined cycle plant in Jackson with a capacity of 520 MW.
There are various factors that can influence gas prices and make them volatile, Sweeney said. However, the question in light of all the new gas options — the new shale reserves, LNG, gas from the west via the REX pipeline, etc. — is whether gas prices are going to be as volatile going forward, he said. Many forecasts including EIA and NYMEX have materially reduced their future gas prices, he said.
“You need to evaluate risks, but you also need to evaluate spending a large amount of capital to hedge against the risk of high gas prices. An IGCC is a very large upfront hedge against gas by utilizing a new technology,” Sweeney said.
“If a utility is really concerned over gas volatility, it is possible to lock in long-term gas contracts. There are large players in the gas industry who are willing to enter into long-term contracts – 15 year contracts starting five years from now – which would lock in gas prices for 20 years. Isn’t that what MPC is doing with Kemper, but with a large upfront capital cost on risky technology?” Sweeney said.
“The proposed TRIG facility is nothing more than a standard natural gas combined cycle facility and a separate coal gasification facility. The gasifier would turn coal into a synthetic natural gas. If the TRIG technology doesn’t operate as expected, Kemper would be a $2.4-billion natural gas plant. If the gasifier doesn’t work, they will have to supplement it with natural gas from a pipeline, making it a very expensive natural gas combined cycle when there are several existing IPPs available,” Sweeney said.
The savings customers would receive from the Kemper lignite plant are proved in MPC’s filings through comparisons to a range of natural gas prices. Actual rate impact in dollar amounts is not given.
Dr. David Dismukes, director for the Center for Energy Studies at Louisiana State University, said this kind of comparison is normal. Dismukes has worked in consulting, academia and government service for 20 years and researches economic, statistical and public policy issues in energy and regulated industries.
Because a natural gas plant is the lowest cost new plant that can be developed, other new plants – even nuclear, wind or solar – are usually compared to that, Dismukes said.
While this “with or without” rate perspective is valid, said Dr. Craig Roach in his Phase I testimony, the lack of rate impact compared to current 2009 dollars does not answer the question of how the new plant would affect the need for power. Roach is the Commission’s independent consultant and president of Boston Pacific Co. He has more than 30 years of experience with energy policy and has consulted in electricity auctions for numerous states.
Roach questions whether the increase in rates could reduce the power demand that justified the need of the plant.
The Kemper plant would be “an expensive new facility and, if its costs were allowed to be put into rates, then MPC’s rates would increase substantially as compared to rates today. It is important that MPC ask whether the rate increase caused by the IGCC plant itself could actually reduce peak demand and energy use and, thereby, obviate the need for some or all of the plant,” Roach said.
MPC says customers can bank on the low, stable cost of lignite coal.
“Generally, lignite prices are always lower than other coal prices,” said Tres Tipton, general manager of Red Hills Mine, a lignite coal mine in Ackerman, owned by North American Coal Corp.
Red Hills Mine has been commercial since 2002, and has a 30-year contract with neighboring Red Hills Power Plant, which is run by Choctaw Generation Limited Partnership, a subsidiary of Suez Energy. All of Red Hills Power Plant’s power is sold to TVA, which serves Northeast Mississippi.
North American Coal has been negotiating with Mississippi Power for a potential contract for the proposed Kemper IGCC project. Tipton said if a North American contract were made with the company, it would be a long-term contract similar to the one made with the Ackerman mine.
The two factors that influence the price of bringing coal into the South are the price of coal from the mine and the transportation costs of the railroads, Tipton said. Railroad costs change with fluctuating fuel prices, and “the real price of coal is moving it, not mining it,” he said.
Lower quality coal, such as lignite, is more expensive to burn and thus has to be cheaper. Because of its lower quality, it is not transported. A lignite mine is generally located next to the power plant it serves and provides fuel to only one customer. Lignite is not sold on the open market, Tipton said. “You’re not competing against other coals and the marketplace,” he said.
Because lignite is not sold on the market, price forecasts for lignite are not available.
Dismukes said gas prices will have to be more than $8 per million Btu to make the Kemper plant a cost-effective alternative for its customers. The EIA says prices won’t reach $8 again until 2030. If approved by the Commission, the plant would go commercial in 2014.
“A $2.4-billion plant that has an effective capacity of 582 megawatts results in an effective installed unit cost of over $4,000 per kW. That is about three times more costly, on a per unit basis, than a brand new state-of-the-art natural gas generator. The difference in the capital costs would have to be made up with fuel savings, and in order for fuel savings to offset a capital cost differential of that magnitude, you’d have to see natural gas prices at a level over $8 per million Btu consistently for the next 30 years,” he said.
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