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Coal's dominance likely to decrease in Rockies, Southwest US: analysts


By Eunice Bridges and Patrick Badgley in Houston


February 28, 2013 - Coal is likely to remain the dominant fuel in the power generation mix in the US Rockies and Southwest going forward as the home of the cheapest coal in the country -- Powder River Basin -- continues to hold an immense price advantage over other fuels, even as aggressive regulations and state mandates ensure that natural gas and renewables will make considerable inroads.


But sources are divided as to how much switching will occur, with some only calling for a minimal amount, mostly pushed by environmental rules and regulations that encourage or mandate the closing of coal plants in the West.


Others, however, see more possibilities for gas in power generation, as an increasing amount of gas-fired plants come online and renewable sources of energy require it as a complementary fuel.


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Analysis continues below...


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Last year in the Rockies, the power mix was dominated by coal. In October, about 55% of electric power was fueled by sub-bituminous coal, 24% by bituminous coal, 6.5% from gas, 7% from wind and 5% from hydro, according to data from the Energy Information Administration.


In the Southwest, coal is used by a large margin in New Mexico, but is not as dominant in Arizona and Nevada. Together the three states used a fuel mix of 42% coal (28% sub-bituminous, 14%, bituminous), 37% gas, 12.6% nuclear, 3% hydro and 1.5% wind, according to the EIA data for October 2012. See a chart of the AZ-NV-NM fuel mix for power generation for 2012.


But that supply portfolio looks set to change.


In the Rockies — including Colorado, Wyoming, Montana and Utah — a total of 10,075.75 MW is scheduled to come online between 2013 and 2018, according to Platts data.


Gas projects make up about 2,082 MW, or 20.7%, of that total, second only to wind units which make up 5,530.5 MW or 54.9%. During the same time period, the Rockies will retire 540.45 MW, inclduing six bituminous coal units.


In the Southwest area, 4,186.7 MW will come online over the next five years, including three gas units that total 1,495.3 MW, or 35.72%, of the new builds. The region could also see 25 new solar units that will account for 2,200 MW or 52.6% of the total, according to Platts data.


Judging by the types of power generation units proposed over the next few years, gas and renewables look set to gain market share. See a list of proposed power plants in the US.


Teri Viswanath, director of commodity strategy at BNP Paribas, said the replacement of coal generation with gas in the Rockies and the Southwest region will continue and likely increase in the future.


Although the region has a plentiful supply of Powder River Basin coal, "it doesn't mean that it's immune from fuel switching," Viswanath said. "Even in areas of the country that we thought were relatively insolated against fuel switching, we are seeing fuel-switching occur."


Western coal supply is sourced 66% from the Powder River Basin and 34% from the Uinta Basin, according to Platts unit Bentek Energy.


Viswanath cited EIA data that shows the share of coal in power burn in several western states including Utah, New Mexico, Arizona and Nevada has dropped year-over-year, while the share of gas is on the rise.


Viswanath said the numbers show increased competition between coal and gas in the region and that this trend will likely continue as more gas plants are built, while coal plants are retiring. See a list of retiring power plants in the US.


"We've had a heck of a time attempting to site new coal projects," Viswanath said.


In the Rockies and the Southwest, coal prices have a major advantage to gas going forward, according to Platts price assessments. In the Rockies, that advantage is as wide as $15.60/MWh through 2015. In the Southwest, it is slightly lower, at $8.78/MWh through 2015.


Bentek said in a recent report that from a delivered cost and cost of generation, "gas is expected to price itself out of the marginal generation stack relative to PRB coal by 2013 and open a $20 premium by 2017."


Despite the price advantage, the Bentek report said there is reason to expect some coal-to-gas switching in the West, although not at the same levels as in the eastern part of the country, where Appalachian coal is more expensive and transportation costs are higher.


Bentek expects about 300,000 Mcf/d of coal displacement in the West by 2017, most of it occurring in the Southwest region.


Bentek also said regulations that incentivize or mandate the closure of coal-fired plants throughout the West could lead to additional upside for gas demand. In addition, renewable standards in several states could knock more coal out of the stack than expected, given the advantages of cycling gas plants.


Cameron Gingrich, an analyst with Ziff Energy, predicted coal-to-gas switching will continue in the Rockies at the same level as 2012, as power demand remains flat in the region.


Other analysts have different views. A Black & Veatch report released last week looks further down the line, predicting the generation mix of the Western Electricity Coordinating Council though 2037. WECC includes the Southwest and Rockies, as well as several other Western regions.


The share of gas in the WECC power generation mix will jump from 29% currently to 40%, in 2037 the report says. At present, gas makes up 251,454 GWh in the WECC region, and that will double to 520,102 GWh in 2037, Black & Veatch said.


During the same time, coal will drop from about 31% of the generation mix to 19%. The report also says the percent of generation mix by renewables will triple — from 5% to 15%.


A western trader said the upcoming coal retirements will take several years to have a major impact on gas markets in the region, but added that "coal, especially in the West, is dying a slow death with emissions issues and haze rules."


Western utilities say state and federal environmental regulations and renewables mandates make it difficult to predict how their fuel mix will change in the next two years.


Wes Reeves, a spokesman for Xcel Energy, said its New Mexico and Texas fuel mix in 2012 was 52.9% coal, 36.9% gas, 6.3% wind, 0.5% solar and 3.5% other.


Reeves was hesitant to make predictions on future changes in the fuel mix in part because of a host of environmental laws, including the Mercury and Air Toxics Standard rule and the Clean Air Interstate Rule.


In addition, he cited the upcoming replacement for the Cross-State Air Pollution Rule, any updates to the National Ambient Air Quality Standards for ozone, sulfur dioxide, particulate matter, carbon monoxide and lead, the potential greenhouse gas/carbon rules for existing units, and the Combustion Residual Rule for fly ash production.


Under the Environmental Protection Agency's Mercury and Air Toxics Standards, existing generation sources generally will have up to four years if needed to comply. That includes three years provided to all sources by the Clean Air Act — which EPA says will be sufficient time for most sources to comply — plus the additional year that state-permitting authorities can grant as needed for technology installation. The ruling went into effect April 16.


Jeff Hymas, a spokesman for Rocky Mountain Power, said the company expects the use of gas and renewables to "slightly increase" in 2013 and 2014, spurred in part by the addition of a combined cycle gas-fueled power plant in 2014. Still, the company will remain heavily dependent on coal.


Hymas said final data on the company's fuel mix was not available for 2012. In 2011, the mix consisted of about 60% coal, 12% gas, 8.4% hydro, 8% wind and about 10% other sources.


A spokeswoman for NorthWestern Energy, which provides electricity in western Montana and eastern South Dakota, said its Montana utility was subject to deregulation for a number of years and did not own generation.


"We are now able to own generation, but still rely largely on market purchases," said Claudia Rapkoch.


The company now owns 222 MW of baseload coal generation, a 150-MW gas station used for transmission balancing and a 40 MW wind farm.


"We have contracts for wind, hydro and coal generation but can’t quantify exactly. We are on course to meet our 15% RPS by 2015," she said, referring to the renewable portfolio standard.


Rapkoch also said the fuel mix in Montana could potentially change in upcoming years because the utility will be replacing power contracts "but has not determined yet how or with what source."


As states become more dependent on wind and solar energy, they will need gas for load following, ramping and quick starts in the short term until other technologies can mature.


In Arizona, for example, the Arizona Corporation Commission approved the Renewable Energy Standard and Tariff in 2006. These rules require that regulated electric utilities must generate 15% of their energy from renewable resources by 2025.


Colorado's renewable mandate dictates a 30% renewable portfolio by 2020 and New Mexico's requires 20% by 2020.


Despite the predictions for continuing fuel switching in the West in the coming years, some analysts are skeptical.


Shiyang Wang, an analyst at Barclays, said coal displacement will be strongly driven by price over the next two years as a significant amount of permanent coal displacement by gas is unlikely to set in until 2015.


The gas market would only need about 3 Bcf/d of coal displacement in 2013 and 2.2 Bcf/d in 2014 to balance, she said.


As such, "there is unlikely to be any coal displacement taking place in the Rockies" or areas that use mainly PRB. "Coal displacement should be an eastern phenomenon only," she said.


But as gas-fired generation looks set to increase in the Rockies and Southwest over the next few years, the question then becomes whether the gas pipeline grid is ready for the added demand.


While the Rockies is well-supplied and well-piped — in fact, several pipes are currently fairly underutilized — the Southwest presents an interesting conundrum: most of the new pipeline builds or expansions are centered around moving gas supplies away from Southwestern demand centers and to Mexico.


About 650,000 Mcf/d of additional capacity to move gas into Mexico is coming online in 2013 and another 1.2 Bcf/d in 2014, according to a recent report by Goldman Sachs.


The projects include several on Kinder Morgan's El Paso system, including the El Paso Norte Crossing Project which will run from an interconnection with El Paso's Samalayuca Lateral in El Paso County, Texas, to an interconnection in Mexico underneath the Rio Grande River.


In addition, several pipeline projects in Mexico are coming online to move gas from the border area to demand centers. These projects will add a net capacity of 850,000 Mcf/d in 2013 and 2.8 Bcf/d in 2014, Goldman Sachs said.


Anders Hyde, an analyst at Bentek, said there should be enough pipeline capacity in the Southwest to serve the new gas-fired power plants.


There will be a combination of new builds and retirements and the newer plants will both be more efficient and may not necessarily be utilized at 100%, he said. See a map of retiring and planned plants in the Western US.


In addition, Hyde said there is about 1.9 Bcf/d of spare capacity into the Southwest market based on the past 365 days of flows, most of it on the El Paso system.


Table: Proposed power plants





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