Western Energy Magazine — Due to market forces, renewable portfolio standards, and federal and state regulations, natural gas will fuel most of the new generating capacity to be installed in the next decade. This has raised questions about the sufficiency of pipeline capacity, permitting processes for expansion, and the delivery mechanisms and storage infrastructure to accommodate the growth trajectory in natural gas-fueled electric generation.
The Federal Energy Regulatory Commission (FERC) recently held a series of industry forums throughout the nation to listen to producers, pipelines, generators, industrial customers and other energy stakeholders. On August 28, 2012, FERC held a forum in Portland, Ore., on the Coordination Between Natural Gas and Electricity Markets. The meeting focused on the states of Oregon, Washington, California, Nevada, Idaho, Montana, Colorado, Utah, Wyoming, Arizona and New Mexico.“We are especially interested in the West in the sense that we’re seeing a real transition in our generation mix,” said FERC Chairman Jon Wellinghoff in his welcoming remarks. “With renewable portfolio standards, using gas for different purposes than used in the past, the impacts of EPA regulations, and reducing the amount of coal, we’re going to have a much different generation mix in the future.”
FERC Commissioner John Norris also weighed in. “With so much new variable resources coming on-line, when the wind blows and sun shines, it’s all good,” he said. “The same holds true with natural gas. What if the gas doesn’t flow? How much are we increasing our reliance on natural gas, and what does that represent for our electric grid? We believe it’s best to address any problems before they happen.”
Expected generation additions
According to FERC’s Office of Energy Projects, there are strong regional differences in fuel use between Western subregions. Coal-fired generation dominates in the basin, desert and the RMPA. Gas-fired generation dominates in California, and hydro dominates in Northwest Power Pool region. Geothermal is predominantly in California and Nevada.
In 2010, electric generation using coal was 32 percent and gas accounted for 30 percent of the power produced. Hydro continues to represent about 25 percent. This year, the use of coal to generate electricity is down almost 18 percent for the first seven months of 2012, compared with the same period in 2011, according to the U.S. Energy Information Administration. Natural gas for power generation use is up by 30 percent.
Looking to 2020, there is 27,750 MW in generation plants either under construction or in advanced stages of development: Renewables account for 54 percent, natural gas 38 percent and geothermal 2 percent. Fifty-eight percent of the projected capacity is in California. Another 64,678 MW of generation is in the early stages of development. Electric generation is the largest consumer of natural gas, with industrial and residential uses not far behind.
Transmission demands
Pipeline companies at the forum were confident in their ability to supply the growing demand.
“Utilities have done a good job of determining that there will be an increase in natural gas use in the Pacific Northwest – not only for renewables, but also in the drive to get off of the coal,” said Lee Hobbs, senior vice president of TransCanada U.S. Pipelines. “Hydro has its own seasonal variability, and you don’t know from one year to the next how much you’ll have. I believe the market will figure out what needs to be done and that infrastructure will be built. Our experience confirms that we don’t have curtailments, and the system has kept up with what’s required.”
“Lee and I have been promoting expansions to serve the additional generation,” agreed Ed Brewer, vice president of commercial operations, Williams – Northwest Pipeline. “We’re trying to build over the Cascades and we’re excited to serve new markets. And we have the capacity to serve existing markets.”
Clay Riding, director of natural gas resources at Puget Sound Energy, agrees that current infrastructure is adequate, but cautions that we need to build for the future. “In the Pacific Northwest, there’s a lot of resiliency in the region, and have been very few periods where you couldn’t find gas. But I get nervous when I see how much generation we’re adding. If the region adds another 3,000 MW to respond to new variable load, then how does the system respond? How will we optimally develop the infrastructure?”
In the Rocky Mountain States and Southwest Region, Kinder Morgan Pipelines is bullish on building storage to ensure adequate, uninterrupted supplies. “We’re working with our larger customers on infrastructure in the Rockies whether its new pipelines or storage,” said Will Brown, director-commercial of Kinder Morgan West Region Pipelines. “We completed a large project in the Rockies to provide 7 BCF of working inventory and 500 MCF of additional capacity from a liquid market.
“Liquidity in the intraday markets means it’s important to have storage, so when the liquidity isn’t there, there’s storage to meet our needs. We’re ready to build what our customers need in the Southwest. We believe the FERC process and pipeline process is well documented and regulated, and that informational postings sends the right signals when infrastructure is needed.”
Justin Thompson, director of business support at Arizona Public Service, said that while he procures firm, long-term gas, if the company doesn’t schedule to use its firm capacity in time, it’s sold to interruptible customers who cannot be bumped after the gas starts flowing. “The volatility of gas burns will increase in the future, and being able to adjust intraday to our gas schedule will be a challenge. We procured gas storage in Texas, but if we can’t put gas into the pipeline intraday from Texas, then we’re out of gas.”
“When it’s very hot in the desert, our wind is virtually zero, and our gas burns rise dramatically. If we have a coal unit or other baseload unit go off, we need to be able to burn that gas. If we can’t make adjustments, it’s a major problem.”
Storage and renewables
Natural gas storage is part of a three-legged stool, according to Tina Burnett, senior energy analyst for The Boeing Corporation. “To us, reliability is critical. We can’t switch. We have pipeline transportation on NW Pipeline and I’m not opposed to additional intraday scheduling. But Boeing signed up for storage, with long-term contracts, and generators can do it too. Generators that don’t have storage are missing the boat.”
Liam Noailles, manager of market operations for Xcel Energy, agreed. “We’ve had issues in the past related to gas supply,” he said. “Storage is what’s saved us.”
NW Natural, a local distribution company in Oregon and Southwest Washington, continues to develop the potential of its Mist natural gas underground storage facility, discovered in 1979. “It is the only commercial gas facility in the Northwest, and we’ve been actively expanding it for the last 15 years,” said Randy Friedman, director of gas supply for NW Natural. “We’ve discovered 40 reservoirs and eight are in use as storage. So there’s plenty of potential.”
Commissioner Phillip Jones at the Washington Utilities and Transportation Commission points to numerous combined cycle generation plants sited for the Interstate 5 corridor between Portland and Seattle, as well as increased Renewable Portfolio Standards as factors spurring the need for answers.
“We’ve been asked to look at a coal or natural gas plant in the Centralia region,” Jones said. “But that would mean additional gas in the system. With additional storage, it seems we could we get more flexibility in the pipeline, but if we go to a Renewable Portfolio Standard of 25 percent in Oregon, 15 percent in Washington, and 33 percent in California, we’re looking at substantial variable generation, and something has to back that up.”
Balancing the system
Staying agile is part and parcel of managing today’s mix of resources in the West. “We see a future that leans heavily on wind and natural gas,” said Portland General Electric’s Jim Lobdell, vice president power operations and resource strategy.
“Given Oregon’s limitation on nuclear, and rules on coal-fired emissions, both coal and nuclear are pretty much off the table. Our commercial-scale choices are really limited.”
Lobdell said there was a need for the company to take on a greater role in balancing the system, as BPA’s hydro resources are spread more thinly and face increasing constraints.
“PGE is one of the few parties that schedule on the intra-hour basis — scheduling on 30-minute intervals,” he said. “BPA gives us a discount to participate in this market, but it’s challenging managing your position when you’re looking for a counterparty to trade with and there is no market liquidity. And regulators are pushing us to go even further, to 15-minute scheduling. At the same time we need to bring the infrastructure that delivers our fuel into alignment with our generation needs, and we need to build more communication and collaboration with the pipeline and other utilities to make this process work better.”
Deston S. Nokes, WE’s copy editor, is an independent consultant for the Western Energy Institute, the Western Electricity Coordinating Council, and has worked as a communications consultant and energy writer for Sustainable Industries Journal, BPA, PacifiCorp, North American Windpower and others. He can be reached at deston@destonnokes.com.
