By Sharryn Dotson, online editor
When it comes to natural gas-fired and coal-fired assets in North America, two subjects have taken over the headlines: The amount of natural gas available for electricity production in North America and regulations from the U.S. Environmental Protection Agency that are pending and have been passed. Specifically, 2012 is the year of the Cross State Air Pollution Rule (CSAPR), which takes effect on January 1.
Power and Emissions Outlook for 2012
Power producers have said the three-year timeframe from the publishing date of the rule is not enough time to comply, but the EPA and other companies, such as Exelon, have argued that power generators have enough time to fulfill the rules’ requirements.
According to the U.S. Energy Information Administration’s (EIA) recent Short Term Energy Outlook, coal is expected to fuel 41.9 percent of total generation in 2012, down from 43.5 percent in 2011. The share of generation from natural gas is expected to increase from 24.2 percent in 2011 to 25.5 percent in 2012.
Carbon dioxide (CO2) emissions from fossil fuel sources are expected to drop less than one percentage point in both 2011 and 2012 from 5.62 billion metric tons (MMT) in 2010. Coal is predicted to produce 1,960 MMT of CO2 emissions in 2011 and 1,876 MMT in 2012. Natural gas is expected to emit 1,308 MMT of CO2 emissions in 2011 and 1,334 MMT in 2012.
CSAPR and the resilience of coal
Coal-fired power plant operators must now further reduce sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions as part of CSAPR. In order for many plants to be in compliance with the rule, the installation of emission control technologies is necessary. Fortunately, according to Electric Power Research Institute’s (EPRI) George Offen, senior technical executive – generation, the technology is available, though figuring out which one works best at a given power plant is still an issue that some power generators are facing.
One thing that many power plant operators will have to do is combine environmental controls, such as selective catalytic reduction (SCR) for NOx and flue gas desulfurization (FGD), or scrubbers.
“Some are using a combination of SCR and FGD technologies to also get you the required mercury emission levels, but it doesn’t address other trace metals,” Offen said. “If you don’t have flue gas desulfurization and selective catalytic reduction, you probably don’t need one because you are able to deal with the Electric Generation Unit Maximum Achievable Control Technology (EGU MACT) rule, when promulgated in mid-December, in some other way. Most will likely look at activated carbon injection.”
“We need breakthrough technologies (for CO2). Most of the new technologies being considered are incremental improvements over current technology options,” Offen said. “The usual way to shorten the time span needed for these technologies is through money.”
|Ameren Energy installed two scrubbers at this coal-fired plant in Illinois.|
Emissions rules and the economy are expected to take its toll on coal use and production in the U.S. The EIA said U.S. coal consumption is expected to drop to 19 million short tons (MMst) in 2011 as generation growth is satisfied by increases in hydropower, wind and natural gas sources. In 2012, it is predicted to decrease to 17.53 MMst because of an increase in the use of nuclear power and natural gas and a decrease in energy use.
Coal production is predicted to be at nearly the same level in 2011 as it was in 2010. Production in the Western U.S. is expected to drop 1.4 percent in 2011, while the Appalachian and Interior regions are expected to increase production by 1.7 percent. EIA expects production to drop by a total of 4.1 percent in 2012 as domestic use and exports decrease. Nearly 24 million MMst will be withdrawn from inventories at power plants in 2011, and a slow down in 2012 is predicted as well.
Coal exports were 80 MMst for the first three quarters of 2011, and they are expected to reach 106 MMst. The number of exports is expected to decline to 97 MMst in 2012 as supply from other countries recovers from disruptions.
Coal prices have increased by 6.7 percent each year over the past ten years. The delivered coal price in the electric sector is predicted to be $2.41/MMBtu in 2011 and $2.42/MMBtu in 2012.
“Golden” age of gas
A report from the International Energy Agency (IEA) says that the world is entering a so-called golden age for gas. By 2035, gas is predicted to make up a quarter of the world’s energy mix, replacing coal, nuclear and some renewables like wind and solar. The U.S., according to the Energy Information Administration (EIA) said the U.S. has 750 trillion cu. ft. of shale gas resources in the Lower-48.
The National Energy Board’s Short Term Natural Gas Deliverability Report said it expects shale production in Canada to nearly double from 0.24 billion cubic feet per day (Bcf/d) to 0.46 Bcf/d in 2012, said John Foran, director, Oil and Gas Division with Natural Resources Canada (NRCan). In Canada, the private sector determines investment, drilling and production of natural gas, while provinces own the resources and provincial regulators also have some control over the pace of resource development.
“Steady natural gas production levels in North America, combined with slight increases in demand, are resulting in stable natural gas prices, similar to those of last year,” Foran said.
A report from IHS Global Insight released in December said that producing natural gas from shale would support 870,000 U.S. jobs and add $118 billion to economic growth in the next four years. The report was commissioned by America’s Natural Gas Alliance. Gas from shale also accounts for 34 percent of U.S. output, the report said. Lower natural gas prices as shale boosts supply will cut U.S. electricity costs by an average of 10 percent, the report said, and raise industrial production 2.9 percent by 2017.
The EIA’s short-term outlook said that natural gas consumption is expected to increase 1.7 percent in 2012 to 68.4 billion cubic feet per day (Bcf/d), up from an expected 67.2 Bcf/d in 2011.
Gas production is expected to average 65.9 Bcf/d in 2011 and increase to 67.7 Bcf/d in 2012. Gas imports are expected to fall to 8.5 Bcf/d in 2011 and 8.2 Bcf/d in 2012. Pipeline exports to Mexico and Canada are expected to average 4.3 Bcf/d in 2011 and 4.4 Bcf/d in 2012.
Working natural gas inventories to total 1.8 trillion cubic feet (Tcf) by the end of March 2012.
The Henry Hub spot price predicted to be $4.02 per MMBtu for 2011 and $3.70/MMBtu due to domestic production and abundant storage supplies.
2012 Outlook for Nuclear Power
By Brian Wheeler, Associate Editor
At the end of 2010, adding more nuclear power in the U.S. was deemed a viable option to meet the nation’s growing thirst for electricity and cut power plant emissions.
Then the unexpected happened.
In March 2011, the meltdowns at the Fukushima Daiichi nuclear power plant in Japan diverted attention away from the pre-license nuclear construction activities taking place. Fukushima Daiichi and the safety of nuclear power stole the headlines.
But the events in Japan were not the only natural disasters that affected nuclear power in 2011.
|Aerial photograph taken in August 2011 of the Vogtle Unit 3 and 4 construction site. Photo courtesy of © Southern Company, Inc. All rights reserved.|
Flooding occurred in the Midwest region of the U.S., causing the 500-MW Fort Calhoun plant in Nebraska to enter an “Unusual Event” status with the Nuclear Regulatory Commission (NRC) in June. An “Unusual Event” is the lowest of four emergency classifications defined by the NRC. Fort Calhoun returned to service in August.
In April, a tornado outbreak across the Southeast prompted the Tennessee Valley Authority (TVA) to shut down all three reactors at the 3,400-MW Browns Ferry plant in Alabama. The tornadoes did not damage the plant, but did damage transmission lines used in the TVA system. TVA began re-powering those reactors in May.
In late-August, the eastern seaboard of the U.S. was hit with a Category 1 hurricane that forced several nuclear plants to shut down. No major damage was reported at any of the plants that were impacted by the storm. In that same timeframe, a 5.8 magnitude earthquake that occurred roughly 11 miles from the 1,806-MW Dominion-owned North Anna station in Virgina forced the utility to shut down both reactors.
“The earthquake shook the reactors more strongly than the plant’s design anticipated, so Dominion had to prove to us that the quake caused no functional damage to the reactors’ safety systems,” said Eric Leeds, director of the NRC’s Office of Nuclear Reactor Regulation.
In November, the NRC said Dominion could restart both reactors after both Dominion and NRC’s inspections showed only minor damage that did not affect North Anna’s safety systems.
“We cannot afford to proceed in a ‘business as usual’ manner,” said NRC Chairman Gregory B. Jaczko in a speech in November. “Given this year’s multiple natural disasters including the Japan earthquake and tsunami in March, which resulted in the nuclear emergency at Fukushima Daiichi; flooding in the Midwest in June; the earthquake on the East Coast in August; and other serious threats, such as hurricanes and tornadoes, nothing was usual about 2011.”
The earthquake and tsunami that exposed safety issues at the Fukushima plant prompted the NRC to launch a safety review of all existing nuclear power plants. The NRC developed a task force to recommend regulatory actions taken need to be taken by the NRC staff in response to lessons learned from Fukushima. Some near-term actions the NRC identified following Fukushima were seismic and flooding reevaluations, seismic and flood walk downs and station blackout actions.
NRC spokesperson Scott Burnell said the Commission will continue to follow up on recommendations from the Japan Lessons Learned Task Force in 2012.
“While the NRC staff has yet to finalize processes and acceptance criteria regarding several areas of analysis, it’s possible U.S. nuclear power plants will be required to start working on updated analyses later in the year,” he said.
North of the U.S. border, the Canadian Nuclear Safety Commission (CNSC) established an external advisory review committee to review the commission’s process and responses stemming from the Fukushima Daiichi accident. Speaking during the Power Engineering magazine Nuclear Power Executive Roundtable, Rob Oberth, president of the Organization of CANDU Industries, said there may be some tougher regulations coming along that could impact the capital costs of new plants in Canada.
New nuclear power construction in the U.S. is not as far along as other countries such as China and France. But projects are moving forward.
Although there are still challenges ahead, both from a financial and regulatory standpoint, there is tremendous opportunity in the U.S. for new nuclear power, said Clarence Ray, CEO of Shaw Power Group, speaking at the 3rd Annual Nuclear Power Construction Summit in November.
“Most people do not realize how much nuclear construction is already going on in the U.S.,” Ray said.
While Shaw is heavily involved in nuclear construction projects in China, the Louisiana-based company is assisting in the construction of two nuclear projects in the U.S.: Plant Vogtle Units 3 and 4 in Georgia and V.C. Summer Units 2 and 3 in South Carolina.
Preconstruction work is taking place at both sites. Both South Carolina Electric & Gas Co., principal subsidiary of SCANA Corp. and the majority owner of the V.C. Summer site, and Southern Co., the majority owner of the Vogtle site, are awaiting the NRC’s decision on issuance of a combined construction and operating license, both of which are expected to be issued soon. Once the license is received, safety-related construction work can begin.
At both construction sites, heavy lift derrick tracks have been assembled. The cranes being used on these tracks will lift and place the heaviest components. Testing of the cranes should commence in early 2012.
At Plant Vogtle, 21 million-cubic-yards of earth have been excavated to make way for the backfill for the nuclear island. Both Units 3 and 4 foundations are prepared for rebar placement. Once the COL is received, the first concrete pour will take place. Today, 1,700 workers are on-site in Georgia and when the COL is received, over 3,000 workers will be at Vogtle.
In early-December, Toshiba Corp. said it is shipping the condenser for Vogtle Unit 3, the first major component from Toshiba for a new nuclear plant in the U.S. The condenser, designed by Toshiba and manufactured by Korea engineering company BHI Co., Ltd., was shipped from BHI’s manufacturing plant on Nov. 14. Toshiba said the condenser was shipping from Seoul in early-December en route to the Port of Savannah, Ga.
Progress is similar at the V.C. Summer site, as is the date for COL issuance. Excavation and rock blasting is complete for both Units 2 and 3 and three of the four cooling tower foundations are under construction. Although the events at the Fukushima Daiichi plant could have slowed the delivery of needed materials, SCANA has not experienced any problems.
“We have not identified any supply chain issues for materials or equipment coming from Japanese suppliers,” said Rhonda Maree O’Banion, SCANA spokeswoman.
If COLs are not received by the end of 2011, both Southern Co. and SCANA could receive the COLs in early 2012. Once those licenses are granted, both sites can begin safety-related construction work and begin building the first new generation reactors in the U.S.
“The pilot plants are going to pave the way, the Vogtle’s and VC Summer’s,” said Chris Tye, Fluor’s senior vice president for its nuclear power business line.
In Canada, Ontario Power Generation, owner and operator of both the 3,500-MW Darlington and the 3,100-MW Pickering nuclear stations, is planning on adding up to four additional reactors at the Darlington site. When completed, the four new CANDU reactors will add 4,800 MW to OPG’s power generation portfolio. In August 2011, a three-member Joint Review Panel (JRP) appointed by the Minister of the Environment and the president of the CNSC concluded that the Darlington project will not result in any significant adverse environmental effects given available mitigations. If OPG is granted a license to prepare the Darlington site for expansion, the next step is the license to construct and operate the plant.
“I don’t see any significant delay in the next project in Ontario (Darlington),” Oberth said. “It was held up for a variety of reasons such as an election and the restructure of AECL (Atomic Energy Canada Ltd). But I am optimistic that the Fukushima lessons learned will be implemented in the new build and it will proceed on a schedule, maybe a little bit slower, perhaps early 2012.”
2012 Outlook for Renewable Energy
Wind power has added 35 percent of all new generating capacity to the U.S. grid since 2007. That’s twice what coal and nuclear combined have added in the last five years, according to the American Wind Energy Association (AWEA).
And as U.S. developers take advantage of lucrative federal tax credits for renewables through the end of 2012, it’s possible that 2012 may result in the largest number of wind projects completed in one year.
As of the end of third quarter 2011, 8,400 MW of wind power capacity was under construction in the U.S. The amount of installed wind power megawatts stood at 3,360 at the end of third quarter 2011. This exceeds installations at the same time in 2010 by 75 percent.
The long-term future of onshore wind power may be unclear, but 2012 will be a time for several wind projects to be started and completed. Developers will continue to reap the benefits of the Production Tax Credit (PTC) for projects commenced by the end of 2012. While AWEA is pushing for a four-year extension of the PTC, Elizabeth Salerno, director of industry data and analysis for AWEA, said wind developments post-2012 have a “question mark over them” for the time being due to the lack of long-term federal policy.
As far as offshore wind power goes, research and development will likely hit an all-time high in 2012, but it’s unclear if any construction will take place in the U.S. In February, Secretary of the Interior Ken Salazar and Secretary of Energy Steven Chu unveiled a national offshore wind strategy that pursues the deployment of 10 GW of offshore wind capacity by 2020 and 54 GW by 2030.
Despite a large need for electricity in coastal regions that could be filled by offshore wind, permitting is slow-moving. For example, the Cape Wind Project, first announced in 2001, underwent more than a decade of efforts to gain permitting, a commercial lease from the Department of Interior and long-term power purchase agreements. However, there is more hope for offshore permitting momentum in 2012. During AWEA’s Offshore Windpower Conference, Secretary of the Interior Ken Salazar announced that five leases are expected to be issued for offshore wind projects in the Atlantic within the next year.
Hydropower advocates say the potential to make low-cost power from water has barely been tapped.
Of the existing dams in the U.S., only 3 percent, or around 2,400, are equipped to produce electricity. The Department of Energy estimates another 30,000 MW of hydropower capacity, including 17,000 MW at existing dams, could be developed in the U.S.
A study commissioned by the National Hydropower Association shows a greater potential for new development.
The technical potential for hydropower capacity in the U.S. is 400,000 MW, four times greater than the nation’s existing capacity of 100,000 MW, the study by Navigant Consulting shows. If the potential for new capacity is met, about 1.4 million jobs could be created by 2025, the study indicates.
In April 2011, the Department of Energy’s Oak Ridge National Laboratory released an eye-opening study that found the U.S. could add 12,600 MW of renewable power capacity to the grid by adding hydropower to 54,000 existing dams.
Most of the potential – 8,000 MW – is concentrated at 100 dams in the South and Midwest, said Brennan Smith, a water resources engineer at Oak Ridge.
“If we want to make a big bang, all we have to really do is look at 100 dams,” he said. “That’s a much more manageable program.”
The 10 largest non-powered dams identified in the Oak Ridge study could generate up to 3,000 MW of renewable power capacity, the study showed
Canadian utilities plan to spend more than C$50 billion on new hydropower projects in the next 10 to 15 years, adding more than 14,000 MW to Canada’s hydropower capacity.
“We can realistically more than double the amount of hydropower in Canada,” said Ed Wojczynski, chairman of the Canadian Hydropower Association and manager of project development for Manitoba Hydro. “We’re in the process of doing that already.”
Hydropower accounts for 60 percent of Canada’s electricity consumption. That number is sure to rise as construction of several new hydropower plants near completion while more coal-fired plants are shuttered in the name of clean air.
In the U.S., demand for cleaner energy is growing, there’s a big market for Canada’s hydropower resources. A handful of deals to export that power to the U.S. have already been made and more are looming.
The utility-scale solar market exploded in 2010 with 459 MW of photovoltaic (PV) and concentrating solar power (CSP) installations, according to the Interstate Renewable Energy Council (IREC). And it’s likely that 2011 will surpass those numbers. According to the Solar Electric Power Association (SEPA), as many as 50 utility-scale solar projects could be completed by the end of this year, totaling up to 831 MW.
But 2012 looks a bit hazy for solar PV. The 1603 Treasury Cash Grant Program extension is likely to expire on Dec. 31, 2011. Without more stability on a federal level, it’s likely that the solar industry will experience a dip in new project announcements in 2012.
It’s probable that modules will also face price hikes in 2012 as a result of an international PV manufacturing debacle. In October, SolarWorld and six unnamed solar panel manufacturers filed a complaint with the Department of Commerce and the U.S. International Trade Commission (ITC) alleging that Chinese solar panel makers and cell manufacturers are making it hard to compete in the U.S. market. The companies claim Chinese panel makers and cell manufacturers are receiving unfair subsidies from the Chinese government and dropping their prices to artificially low levels.
Meanwhile, more than two dozen solar companies formed the Coalition for Affordable Solar Energy (CASE) in response to SolarWorld’s filing. CASE asserts that the U.S. has benefitted from competitive PV prices from China, and that bringing an end to the U.S.-China solar relationship could be detrimental to the U.S. PV industry.
Modules from China prior to SolarWorld’s filing were on average 10 percent cheaper than modules assembled in the U.S. or Europe. If that relationship is permanently wounded, module assembly may move to Taiwan, Korea or Mexico. Either way, module prices are likely to see a steady incline in 2012.
While the technology behind concentrating solar power (CSP) moves ahead incrementally, it’s the partnerships that the industry builds that will likely lead to the biggest gains over the next year. CSP is enjoying broad government support in many regions and nations across the globe. In the U.S., however, 2011 may be remembered for the ground the industry lost to low-cost PV technology. Solar Millennium in October announced that it was shifting 2.25 GW of its CSP developments in the Southwestern United States to PV. So, how does CSP position itself as the most viable large-scale solar solution when PV prices show no indication that they will go up? The industry could theoretically reap some unintended benefits of higher PV prices resulting from a trade complaint filed against Chinese crystalline silicon panel makers. Barring that, though, CSP still has some financing hurdles to overcome in the U.S.
In October, the Department of Energy announced it would commit $60 million over three years specifically to improve CSP technologies. The money comes through the DOE’s SunShot Initiative, which aims to reduce the cost of solar by 75 percent by the end of the decade. The SunShot CSP program is focusing on performance breakthroughs that will improve efficiency and temperature ranges, as well as new design approaches for collectors, receivers and power cycle equipment.
To lure more projects to the U.S., and to keep more developers from scaling back their current plans, Jayesh Goyal, vice president of Sales for Areva, says the industry must work to encourage legislation that puts a premium on job creation. While large PV projects often rely on imported panels, CSP represents a much more intensive construction schedule that requires a larger share of local materials produced by a local workforce.
|SolFocus’s CPV installation at Victor Valley College in California. Courtesy SolFocus|
The third quarter of 2011 was the concentrating photovoltaic (CPV) industry’s best one yet, say analysts. Four MW of the technology, spread out over three projects, were installed mostly in the Southwestern U.S. More CPV is expected to go online by year’s end or early in 2012, including Cogentrix’s 30-MW Alamosa Solar Generating Project, which was awarded a U.S. $90 million loan guarantee in September 2011.
Most company executives know that CPV costs still need to come down in order for the technology to compete with PV. Soitec is working to reduce the cost of its technology through lighter, easier to install components. At Solar Power International, it unveiled a new configuration of its Concentrix system, which the company said makes installs faster and cheaper.
Soitec currently has a 305-MW pipeline of projects in California and plans to build a 200-MW factory also in California in the near future.
The long-awaited construction of four major biomass plants will make 2012 pivotal in the expansion of the wood-fired power industry. Three coal-to-biomass plant conversions awaiting permits in Virginia could also set the stage for a boom in local use of pelletized fuel. That could lead to a European-style scaling of biomass power if the EPA blesses the industry with friendly regulations.
For now, biomass developers are still beset with the EPA’s regulatory uncertainty and plenty of NIMBY opposition. Growth is likely to be limited to projects nearing completion after years of development. The industry, however, stands to benefit from 2012 construction that could bring hundreds of jobs to Florida, Michigan, New Hampshire, Texas and Virginia. “We’ll see gains for big projects where you have a combination of local fuel supply and strong political support,” said Bob Cleaves of the Biomass Power Association. “At the same time, the weak economy, lack of demand for power and plummeting natural gas prices make it difficult to continue operations of smaller plants without long-term PPAs.”
Before the new year begins, the industry hopes for a reprieve from the EPA’s proposed regulations on carbon dioxide and particulate emissions. The U.S. Senate is expected to vote soon on legislation requiring the EPA to revise strict standards under the Boiler Maximum Achievable Control Technology (Boiler MACT). A similar bill passed the House in October.
The U.S. geothermal market adds new projects to its development pipeline each year, and 2012 will be no different. The industry will enter January with billions of dollars in planned investments. In 2005, geothermal energy became a qualifying renewable for the production tax credit (PTC), sparking new developments. By early 2011, U.S. capacity had swollen to 3,102 MW. Up to 5,745 MW are now in development. In May 2011, Terra-Gen Power and TAS Energy added 2 MW to the 17-MW Beowawe, Nev. plant — the first geothermal project supported by the American Recovery and Reinvestment Act (ARRA) to begin operations.
Although many U.S. decision-makers have expressed their desire to have renewables in the energy mix, geothermal is still overlooked in Congress. Lou Capuano, founder of geothermal drillers ThermaSource says, “Even though most of California’s renewables are actually geothermal, it is still the poor stepchild.”
Further, the PTC, which gives developers a tax credit of $0.022 per kWh of geothermal power generated over 10 years, is set to expire at the end of 2013. Congressional committees in both wings are considering extension bills. This will be on the industry’s watch list in 2012.
Many developing projects could meet the 2012 deadline. Ormat Technologies has two projects in Nevada: Tuscarora and McGinness Hills, which are expected to reach commercial operation in 2012. Ormat expects these two projects and others to qualify for the cash grant option in lieu of the PTC, including the 29-MW Mammoth Complex, where the generating capacity will expand to up to 70 MW.
Boise’s US Geothermal is working toward completion on the 23-MW Neal Hot Springs, in eastern Oregon. In addition, its re-powered San Emidio plant near Reno is scheduled to start up in 2011. Gradient Resources’ Patua, Nev. project is in advanced stages, with commercial operation also expected to begin in 2012. EnergySource’s Hudson Ranch, Calif. project will be the first flash plant to go online in the U.S. since the 1990s – most recent designs have been binary or binary-flash.
Lindsay Morris, Associate Editor; Russell Ray, Managing Editor; Jennifer Runyon, Managing Editor, Renewable Energy World North America; Steve Leone, Associate Editor, Renewable Energy World North America; Leslie Blodgett, Geothermal Energy Association; and Robert Crowe, contributing editor, contributed to this report.
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