Despite continued price volatility, natural gas is still the best short-term option for electric utilities looking to add new generation to meet growing electrical demand.
At least, that’s the way two state regulators see it.
“When you consider the (construction) lead time, the availability of the fuel, the fact that it’s cleaner than coal, and the fact that it doesn’t generate the societal concerns associated with nuclear power, right now gas is the primary choice,” says Edward S. Finley, Jr., chairman of the North Carolina Utilities Commission.
“Minnesota requires (utilities) to look at energy efficiency, demand response and renewable-energy options first. If that’s not sufficient to meet the forecasted demand, then they can consider generation options,” says Phyllis Reha of the Minnesota Public Utilities Commission. “Until carbon capture and other coal risks are worked out, natural gas looks to be the least-cost option.”
These are trying times for electric utilities attempting to cobble together resource plans for the next two decades. On the one hand, electrical demand in most parts of the country is rising and expected to increase further. On the other, the new administration is expected to institute green-house gas legislation that will limit carbon emissions and spur some degree of carbon-allowance trading.
That scenario, combined with still unproven carbon-capture concepts, has put at least a temporary kibosh on new coal-fired base-load units and pointed utilities towards gas-fired generation, which generally is viewed as the best way to meet short-term load growth and backstop less reliant renewable energy sources like wind and solar generation.
“We have a lot of wind energy in Minnesota and we have a wind mandate in place for power suppliers,” Reha says. “Natural gas is certainly the most compatible form of backup for renewable energy.”
Finally, while the much-discussed nuclear renaissance still is in play, it’s probably ten if not more years down the road, if it happens at all.
“It’s a tricky question to answer right now,” Finley concedes. “With gas, you’ve got price volatility and questions about the availability of supply. But all potential sources of generation can be criticized for one reason or another.”
One way for a utility to hedge its bets is to use natural gas to diversify its generation mix.
Duke Energy subsidiary, Duke Energy Carolinas, is adding more natural gas to a portfolio that relies heavily on coal and nuclear. With roughly 2.3 million electric customers in its 24,000-square-mile North and South Carolina service territory, the generation mix currently stands at 50-percent coal, 49-percent nuclear, 1-percent hydro or natural gas.
With the Carolinas drawing some 50,000 new residential customers per year, additional capacity is needed to meet the added demand and resolve transmission-system voltage concerns, especially in North Carolina. Despite historical price volatility, the utility says its modeling shows that adding significant natural gas-fired generation is the lowest-cost option when it comes to meeting new load demand.
Towards that end, Duke Carolinas is in the process of retiring two, 150-MW coal-fired units at its Buck Steam Station in Rowan County N.C., and two more 150-MW coal-fired units at the Dan River Steam Station in Rockingham County, N.C. It will re-power each plant with 620-MW gas-fired combined-cycle systems. The Buck Station re-powering will be completed by 2010, with Dan River scheduled to follow a year later.
“We obviously don’t have a high percentage of natural gas in our fuel mix,” explains Marilyn Lineberger, Duke Energy spokesperson. “The Buck plant was the first fossil-fired station built in the Carolinas and it will be the first to be re-powered to combined-cycle operation. Both installations will serve as intermediate units, i.e., they’ll run more often than a peaking unit, but less than a base-load unit.”
Other measures are afoot that will further change Duke Carolinas’ generation mix and, as a result, its overall carbon footprint.
In May, the company announced it will purchase the entire output of a photovoltaic solar farm to be built in Davidson County, N.C., north of Charlotte. Under agreements signed with SunEdison, the company will receive more than 16 MW of power from the solar farm beginning in late 2010. The agreements run for 20 years.
The utility is also in the process of shutting down four more coal-fired units (net output, approximately 200 MW) at its Cliffside plant on the Cleveland/Rutherford County line in North Carolina and replacing them with a more efficient $1.8 billion, 800-MW supercritical coal-fired unit. The utility says the supercritical unit will be completed by 2011 and lead to the eventual retirement of another 800 MW of coal-fired generation, making the new unit carbon neutral by 2018.
Finally, Lineberger says the utility plans to pursue a nuclear plant that would deliver another 2,200 MW to the service territory; as well as additional renewable, energy-efficiency, and smart-grid initiatives.
“Due to price fluctuation in fuel costs, we don’t want to put all of our eggs in one basket. We haven’t made any final decision on the nuclear plant yet, but we do have these combined-cycle plants,” Lineberger says. “It’s obviously going to take time to reduce our carbon emissions. We view these two natural gas systems as a bridge to a lower carbon future. But coal is still going to be part of our mix. The new technology at Cliffside will be as clean a coal-fired unit as is possible. And at the same time we’ll continue to retire older, less efficient coal units.”
Minneapolis, Minn.-based Xcel Energy also is looking to alter its generation mix. By combining a number of gas-fired generation projects in its four service territories with renewable energy initiatives, the utility plans to reduce its carbon footprint and improve its ability to meet the anticipated federal climate policies.
Xcel Energy subsidiaries Northern States Power Co., Northern States Power Co.-Minnesota, Public Service Company of Colorado, and Southwest Public Service Co. operate in eight states, including Minnesota, Wisconsin, North and South Dakota, Colorado, New Mexico, Texas and Oklahoma.
Like other utilities, each is looking to build out its renewable energy portfolio. To support that effort, Xcel is increasing its gas-fired generation capacity, in part, to provide backup support. Even though it’s adding more gas-fired generation, Xcel says adding more renewable energy to its portfolio will allow it ultimately to decrease the amount of gas it consumes going forward.
In 2007, natural gas represented 31 percent of the utility’s overall generation, with coal producing 49 percent, and renewable energy 9 percent. By 2020, the utility projects natural gas usage will be reduced to 17 percent of its output, with coal decreasing slightly to 46 percent, and renewable energy increasing to 24 percent. The largest increase in renewables is expected to be in wind energy, from 2,700 MW in 2007, to a projected 7,400 MW in 2020.
“We’ve been investing in natural gas generation for years. But we’re investing more in wind and solar and we expect that to eventually reduce our reliance on gas overall,” says Kurt Haeger, managing director of wholesale planning. “By 2020 our gas-fired capacity will have increased, but we expect the amount of energy we produce from gas to drop. We expect to increase the efficiency of our gas consumption while increasing our reliance on gas for peak-day capacity.”
In its Minnesota territory, the company recently re-powered two coal-fired plants with natural gas combined-cycle systems that will reduce emissions and increase output. Both projects fall under the Minnesota Metro Emissions Reduction Project (MERP), a program developed by the state legislature that allows the utility to pass through construction costs for projects that improve emissions in the Twin Cities.
First, Xcel re-powered the oldest power plant in its system, the coal-fired High Bridge generating plant in St. Paul. The original plant was built in 1911 and provided roughly 200 MW of electricity to the city and surrounding communities. The new plant, which went on-line in May, employs a combined-cycle system capable of producing up to 570 MW of energy.
Over in Minneapolis, the utility is replacing two coal-fired units at its Riverside Plant that produce a combined 400 MW with a gas-fired combined-cycle system that will deliver roughly 475 MW of electricity. That project is scheduled to be completed in 2009.
“Those projects began as a way to address a regional environmental issue, not a national issue,” Haeger says. “But from a strategic standpoint, they will help us meet our carbon-reduction effort in Minnesota.”
Indeed, Xcel’s corporate portfolio must comply with an assortment of environmental policies that differ by state. Minnesota, for example, is requiring that NSP-Minnesota’s portfolio include 30-percent renewable energy by 2020 and a 30-percent carbon reduction by 2025. Colorado, on the other hand, calls for 20-percent renewable energy and a goal of 20- percent carbon reduction by 2020. New Mexico requires 20-percent renewable energy, but only a 10-percent carbon reduction by 2020. Wisconsin calls for 10-percent (12-percent for NSP–WI) renewable energy by 2015. Texas requires 5-percent renewable energy by 2015.
As a result, there’s an assortment of gas-fired initiatives under the Xcel Energy umbrella. Southwest Public Service (SPS), which covers parts of Texas, New Mexico and Oklahoma, is adding more efficient natural gas fired combined-cycle units and pushing the older and less efficient units higher in the dispatch stack.
SPS also is looking to purchase power from independent power producers (IPPs). The utility currently operates the natural gas fired Cunningham Station near Hobbs New Mexico that produces up to 487 MW of electricity. It also operates the nearby Maddox Station, which consists of three gas-fired units that produce a combined 193 MW.
Though neither of those plants will be retired, the utility is buying the entire output of the 600-MW Hobbs Generating Station, a new gas-fired combined-cycle plant developed by, and owned by, Boston, Mass.-based Lea Power Partners, under a long-term agreement. That plant went into operation in September.
“In that case we are the off-takers,” Haeger says. “Our units at Cunningham and Maddox aren’t as efficient. Those units will still be available though we’ve just moved them higher up in the (electricity delivery) stack.”
Finally, Xcel’s Colorado subsidiary, Public Service of Colorado (PSCo), is in the process of bidding some 1,400 MW of capacity in Colorado, as well as investing in wind and solar power projects. Further, PSCo is building its first new coal-fired electric generating unit in nearly 30 years.
At its Comanche Station near Pueblo, Colorado, PSCo is adding a new $1.3 billion, 750-MW supercritical pulverized coal-generating unit that will be combined with two existing units that generate 660 MW. Xcel says that when Comanche 3 is completed in 2009, the site will provide enough electricity for about one third of Colorado’s communities.
“In our resource plan, we expect Colorado will require roughly 1,400-MW in new capacity by the 2014-2015 timeframe. Some 800 to 900 MW of that involves existing gas-fired power-purchase agreements that are due to expire and will be re-bid, starting this fall,” Haeger says. “So gas will compete there too, along with wind and solar.”
Then there’s California.
Strict environmental standards have long ensured that natural gas is the fossil fuel of choice in California, for both investor-owned utilities (IOUs) and independent-power producers. Now the environmental bar is being raised even higher, and demand for natural gas fired generation should increase.
The state prohibits the nuclear option until the federal government finalizes its development of a waste-storage facility. Further, the state wants at least 20 percent of an electricity provider’s portfolio to be comprised of renewable generation by 2017.
While coal is all but prohibited in-state, the legislature in 2007 instituted new laws that effectively prohibit IOUs and municipal utilities from contracting for electricity generated by coal-fired stations outside the state. Under the SB 1368 Emission Performance Standard, IOUs and municipal utilities cannot establish new contracts for power from any source that emits more carbon dioxide than a new combined-cycle natural gas facility.
Finally, following the energy crisis in 2000, the state decided to allow IOUs once again to develop and own power plants. All of which has IOUs looking to develop both gas-fired and renewable power projects.
“Everybody is excited about renewable energy. But it’s often an expensive option because most projects are located in remote areas that lack the necessary transmission capacity,” says Richard Lauckhart, managing director of enterprise management solutions at Black & Veatch in Pasadena, Calif. “So the other option is gas-fired generation. The beauty of gas is it’s relatively clean, so you can permit it close to the load center.”
San Francisco-based PG&E Corporation is in the process of investing in both. In August, the utility announced it had entered into an agreement with Topaz Solar Farms LLC, a subsidiary of OptiSolar Inc., for 550 MW of thin-film PV solar power. The utility also signed a contract with High Plains Ranch II, LLC, a subsidiary of SunPower Corporation, for 250 MW of high-efficiency PV solar power.
At the same time, PG&E is investing more than $2 billion in four gas-fired plants, the first fossil projects it has developed in 20 years. The plants will, in total, bring the utility roughly 1,900 MW of new, gas-fired generating capacity.
“We’re allowed to build our own plant if we can demonstrate to the CPUC that it’s cheaper than buying the power from someone else,” says PG&E spokesperson Darlene Chiu. “Population growth, demand-response and energy-efficiency programs and renewable options are all part of the evaluation.”
PG&E’s $370 million, 530-megawatt, combined-cycle natural gas-fired Gateway Generating station is located near Antioch and will begin operations in 2009. The $239 million Humboldt Bay Repowering Project is located south of Eureka and will employ a gas-fired system to generate 163 MW, up from its original 105-MW rating. The $673 million Colusa Project near Maxwell will generate 660 MW of electricity and begin operations in 2010.
The fourth project is a proposed $850 million, natural gas fueled power plant in Alameda County, near Oakland. If approved by the CPUC in early 2009, PG&E says the 560-megawatt plant should begin commercial operation in late 2011, or early 2012.
The project, Chiu says, would be situated near the Altamont Pass Wind Resource Area, one of the world’s oldest and largest wind power farms, and near PG&E’s own Tesla substation. “Because the plant will be located near the wind farms, we would be able access the wind generation and operate the Tesla plant as a backup, if necessary.”
Lauckhart says Black & Veatch data indicates utilities and private developers have proposed more than 17,000 MW of gas-fired capacity for California. With a total peak load of 60,000 MW, plus another 15 percent for reserve capacity, he guesstimates roughly 9,000 MW actually might be built.
The final tally and rate of development will depend, of course, on the cost of natural gas and the amount of available renewable energy. “During the price spikes last summer, we had some renewable energy developers saying they might not need production tax credits anymore,” he says.