The United States could cut projected 2030 emissions of greenhouse gases by between one-third to one-half at manageable costs to the economy and without requiring big changes in consumer lifestyles, according to a recently published report.
“Reducing U.S. Greenhouse Gas Emissions: How Much at What Cost?”, published jointly by McKinsey & Co., the management consulting firm, and The Conference Board, the business research organization, is based on detailed analysis of 250 opportunities for reducing emissions of carbon dioxide and other gases thought to contribute to global warming.
On the present path, annual U.S. greenhouse gas emissions will increase by 35 percent to reach 9.7 gigatons of carbon dioxide equivalent (CO2e) in 2030, according to an analysis of government forecasts. At this level, emissions would overshoot by 3.5 to 5.2 gigatons the targets implied by economy-wide climate change bills introduced in Congress. A gigaton equals one billion metric tons.
The report showed a reduction of 3.0 to 4.5 gigatons in 2030 is achievable at a manageable cost using proven and emerging high-potential technologies, but only if the United States pursues an array of options and moves quickly to capture gains from energy efficiency.
Almost 40 percent of the opportunity for greenhouse gas reduction identified comes from options that more than pay for themselves over their lifetimes, thereby creating net savings for the economy. For example, improving energy efficiency in buildings, appliances and industry could yield net savings while offsetting some 85 percent of the projected incremental demand for electricity in 2030.
However, the report said that private sector innovation and policy support will be necessary to unlock these and other opportunities.
Analysis focused on options likely to yield greenhouse gas reductions at a cost of less than $50 per ton of CO2e. Among the main findings:
- Opportunities to reduce greenhouse gas emissions are both highly fragmented and widely spread across the economy. The largest single option—carbon capture and storage (CCS) for coal-fired power plants—offers less than 11 percent of total potential identified. The largest sector, power generation, accounts for less than one third of the total.
- Reducing emissions by 3 gigatons of CO2e in 2030 would require $1.1 trillion of additional capital spending, or roughly 1.5 percent of the $77 trillion in real investment the U.S. economy is expected to make over this period.
- Investment would need to be higher in the early years to capture energy efficiency gains at lowest overall costs and accelerate the development of key technologies and would be highly concentrated in the power and transportation sectors.
- If pursued, such investment would likely put upward pressure on electricity prices and vehicle costs. Policymakers would need to weigh these added costs against the energy efficiency savings, opportunities for technological advances and other societal benefits.
- Five clusters of initiatives, pursued in unison, could create substantial progress towards the targets implied by bills currently before Congress. From least to highest average cost, they are: Improving energy efficiency in buildings and appliances (710 to 870 megatons); increasing fuel efficiency in vehicles and reducing carbon intensity of transportation fuels (340 to 660 megatons); pursing various options across energy-intensive portions of the industrial sector (620 to 770 megatons); expanding and enhancing carbon sinks, such as forests (440 to 590 megatons); and reducing the carbon intensity of electric power production (800 to 1,570 megatons.)
The report was written with DTE Energy, Environmental Defense, Honeywell, National Grid, Natural Resources Defense Council, PG&E and Shell.—David Wagman
Two Firms Pursue Solar Thermal Projects
Lockheed Martin and Starwood Energy Group (SEG) have teamed to pursue utility-scale solar generation projects in North America. Under the agreement, Lockheed Martin will be primarily responsible for engineering, procurement, manufacturing and systems integration. SEG will arrange long-term power purchase agreements, site selection, permitting and providing construction and financing. SEG will work with independent developers to put together the projects.
Chris Myers, Lockheed Martin vice president, said he sees significant growing demand for solar generation projects larger than 50 MW in the United States. Lockheed Martin and Starwood estimate that up to 10,000 MW of solar power could come on line in the next 10 years. At an expected installed cost of $3,000/kW, that would be a $30 billion market.
An affiliate of Starwood Capital Group Global, Starwood Energy Group focuses on energy infrastructure investment, including acquisition and development of power generation and transmission projects in North America. To date, the company and its affiliates have invested, or committed to invest, more than $200 million of equity capital in transactions representing more than $2.5 billion in potential total enterprise value when fully developed. The Lockheed Martin-Starwood team will initially focus on the utility-scale solar generation needs of California and the Southwestern United States.—Steve Blankinship
Growing Natural Gas Dependence a Security Risk?
Growing public opposition to new coal development, coupled with the prospective carbon dioxide (CO2) capture and sequestration (CCS) costs envisioned under numerous legislative scenarios makes the future of U.S. power generation uncertain. That assessment came from Art Holland, director of power and forecasting services of Pace Global Energy Services, which provides advisory and implementation services in energy intensive markets.
Pace projects that more than 120 GW of new capacity additions will be required over the next 10 years. Holland said coal-fired capacity will be part of the generation mix, but that the actual amount will be dictated by near-term regulatory and legislative action. Only 12 GW of coal capacity is in advanced stages of development.
Pace also projects an additional 9 GW of coal-fired capacity in the near-term, but such proposals are now likely to face growing opposition from environmental groups and regulatory bodies. The recent Kansas Department of Health and Environment decision to deny the Holcomb coal-fired power plant its air permit because of concerns over CO2 emissions points to the obstacles coal-fired generation will need to overcome to play a “significant role” in meeting future electricity demand, said Holland.
Because coal is domestically abundant, Pace believes there will be continued efforts to expand the coal-fired generation base in the longer term. Depending on the timing and magnitude of legislated CO2 costs, cleaner coal-fired technology may be developed. However, such technology is still immature and requires significantly higher capital investment than traditional coal-fired options. In addition, the parasitic load and efficiency reductions associated with capturing and sequestering carbon will lead to a significantly greater amount of required capacity.
If expectations for additional coal-fired capacity are not met because of public opposition, legislative uncertainty or prohibitive capital costs, additional intermediate-term generation capacity will have to come primarily from gas-fired power plants, said Holland. This incremental gas-fired capacity will be in addition to the more than 50 GW that Pace already projects over the next eight years in its Power Market Outlook. “Gas prices have doubled in recent years and a nearly all-gas future for incremental electric capacity has implications” not only for electric prices but for the wider economy and—possibly—national security.
Holland said the need for an intelligent, comprehensive national energy policy has never been greater. “The growing opposition to traditional coal-fired power plants, combined with the vagaries of carbon policy, presents a very uncertain future for power generation. Increased generation from renewable technologies could fill the need for greater supplies of energy, but it is unclear how the current state-sponsored renewable portfolio standards will be met.”
He said additional transmission expansion, demand-side management programs and additional nuclear expansion might also alleviate some capacity requirements. These options, however, are unlikely to meet demand growth on their own. Gas will need to fill the gap. The competing objectives of emissions reductions, cost containment and security of supply are stumbling into what he called a “dangerous quagmire.”—Steve Blankinship
Alstom Plans Turbine Facility
Alstom said its Power Systems Sector will invest $200 million in a new manufacturing facility in Chattanooga, Tenn., where it intends to manufacture steam turbines, gas turbines, generators and related equipment for use in U.S. power generation facilities. This will include manufacturing new steam turbines for fossil and nuclear applications, as well as retrofitting existing steam turbines.
“This new facility will also enable Alstom to produce the large and very efficient ultra supercritical fossil steam turbines that are part of the response to the growing concerns regarding the green house gas emissions generated by burning coal,” said Guy Chardon, senior vice president of Turbo Machines.
Alstom currently employs 620 workers at an existing Chattanooga facility and 600 workers in Knoxville.—David Wagman
Exelon Nuclear Selects Texas Site for Possible Plant
Exelon Nuclear has selected Victoria County in southeast Texas as its site for a federal license application that would allow construction and operation of a new nuclear plant, should the company decide to build one. The company expects to submit the combined construction and operating license application (COLA) to the Nuclear Regulatory Commission this coming September.
Last June, Exelon announced that two Texas counties were being considered as possible sites for the license application. The preferred Victoria County site is an 11,500 acre tract.
Among the various conditions that Exelon has said must be resolved before any formal decision to build is made are a solution to used fuel disposal, broad public acceptance of a new nuclear plant and assurances that a new plant using new technology can be financially successful.
Exelon said it expects the license application to cost about $23 million. Submitting the application in 2008 allows the company to participate in nuclear production tax credits, financial risk insurance and federal loan guarantees specified in the 2005 Energy Policy Act.—Steve Blankinship
B&W Achieves Oxy-com Milestone
The Babcock & Wilcox Power Generation Group said it burned coal in full oxygen-combustion mode at a 30 MWth scale during recent testing at its Clean Environment Development Facility in Alliance, Ohio. The facility operated in full oxygen-coal combustion mode for over 250 hours as it burned more than 500 tons of bituminous coal.
B&W PGG’s oxygen-coal combustion process uses oxygen to fire coal, rather than traditional air used currently at coal-fired power plants. With oxygen combustion, the nitrogen component of air is eliminated, creating an oxygen stream to fire the coal. As a result, the exhaust gas from the oxygen-combustion process is relatively pure CO2, rather than being mixed with nitrogen and other emissions. The relatively pure CO2 exhaust gas results in less emissions volume, is easier to capture and—with further purification— is ready for long-term storage or for other purposes such as enhanced oil recovery applications.
B&W PGG worked on this project with American Air Liquide, which provided the oxygen, engineering and chemistry expertise related to its combustion, as well as equipment and sensors to handle the liquefied oxygen used during testing.
B&W PGG will next test sub-bituminous, lignite and Powder River Basin coals. When all test work is completed early this year, almost 4,000 tons of coal will have been consumed. Data will be used to design a large-scale reference plant to implement this technology at commercial scale.
B&W PGG said it is seeking parties to conduct further testing at a demonstration plant in which more than a million tons of CO2 could be captured in a single year.—Steve Blankinship
Business Briefs
The FutureGen Alliance selected a site in Illinois for an experimental $1.8 billion zero-emissions coal facility. However, Congress has placed the private-government research project under increasing scrutiny because of cost and long delays. The price tag is nearly double the $950 million originally projected, with three-fourths of the cost coming from taxpayers. The industry group selected Mattoon in southern Illinois over another Illinois site at Tuscola. Two locations in Texas (Odessa and Jewett) also were considered. All had received favorable environmental reviews in late 2007. The FutureGen Alliance, a consortium of 12 U.S. and foreign energy companies, hopes to have the facility, first proposed eight years ago, operating by 2012.
Xcel Energy told Minnesota state regulators it plans to control mercury emissions at Sherburne County (Sherco) Generating Plant Unit 3 and the Allen S. King Plant by installing and operating a sorbent injection system. The company estimates the systems will remove up to 90 percent of the mercury in the coal burned at King and Sherco Unit 3. The plans must be approved by state regulators before they can be implemented. Each system is expected to cost $4.5 million to install and $3.8 to $5.5 million annually to operate and maintain. If approved, Xcel Energy will implement mercury reductions by Dec. 31, 2009, at Sherco 3 and by Dec. 31, 2010, at King.
Bruce Power LP said the acquisition of a would-be nuclear firm in Alberta gives it a six- to nine-month head start on planning for commercial reactors in the province. Duncan Hawthorne, CEO, said the company was considering building a C$6 billion ($6 billion), 2,000 MWe twin-reactor complex in northern Alberta after it agreed to acquire Energy Alberta Corp. Bruce is a partnership that includes pipeline company TransCanada Corp., uranium producer Cameco Corp., BPC Generation Infrastructure Trust and two labor unions.
Dominion Resources Inc. is the third company to file a complete application to federal regulators to build a new nuclear reactor. Dominion’s application was submitted to the Nuclear Regulatory Commission in late November. The NRC had already approved an early site permit for a third nuclear reactor at Dominion’s North Anna Power Station in Louisa County, Va. That decision allowed the Richmond-based company to complete preliminary site work.
GE Energy expects to invest roughly $50 million to increase supply chain and engineering capacity and will more than double its global capabilities to meet global steam turbine demand, company officials said. Output will be expanded in steam turbine production and engineering centers in North America, Europe and Asia. Much of the demand for steam turbines is being driven by global interest in combined-cycle power. Over the past year, GE has received orders totaling more than $2 billion to supply equipment for combined-cycle projects in Europe and the Middle East.
Entergy’s board of directors approved a plan to separate its non-utility nuclear from its regulated utility businesses through a tax-free spin-off of the non-utility nuclear business. SpinCo, the term used to identify the new company yet to be named, will be an independent publicly-traded company. SpinCo and Entergy Corp. intend to enter into a nuclear services joint venture, with equal ownership. Entergy is targeting third quarter 2008 as the date for completing the spin-off and joint venture transactions.
The Nuclear Regulatory Commission docketed in late November NRG Energy’s combined construction and operating license application to build and operate two new nuclear units at the South Texas Project (STP) nuclear power station site. The application was filed by NRG, CPS Energy and South Texas Project Nuclear Operating Co. on September 24.
The Babcock & Wilcox Companies shortened its name to The Babcock & Wilcox Company (B&W) and reorganized its operations into four groups, including a new nuclear power group. A statement said the re-alignment will better support changing requirements of B&W customers and strengthen the company’s position in the nuclear and fossil power generation industry and in national security operations. B&W’s new unit, Babcock & Wilcox Nuclear Power Generation Group Inc., will offer nuclear power plant products, services and construction. B&W NPG’s capabilities include design engineering, manufacturing, field service and construction.
Projects & Contracts
The Indiana Utility Regulatory Commission granted Duke Energy permission to build a commercial-scale coal gasification power plant. The approximately $2 billion, 630 MW plant will use advanced integrated gasification combined cycle (IGCC) technology. An air permit is still needed from state environmental managers. If that permit is approved, Duke Energy could begin construction early this year on the Edwardsport facility and start producing power by early 2012. Plant cost would be offset by more than $460 million in local, state and federal tax incentives.
Siemens Power Generation received a $170 million order from Tennessee Valley Authority to refurbish and upgrade the turbine island of the 1,200 MW Watts Bar 2 Nuclear Plant in Spring City, Tenn. The Siemens scope of supply includes one new high-pressure turbine; three new low-pressure turbines; complete modernization of the generator, including a RIGI-FLEX rewind of the stator and new retaining rings; exciter rotor refurbishment; six moisture separator reheaters; plus multiple components and more than 40,000 individual replacement parts. The HP turbine is planned for delivery in August 2009 and the three LP turbines in June 2010.
Nevada Power Co. plans to build a 500 MW natural gas-fired combined cycle plant as an expansion to its Harry Allen Generating Station. The facility, subject to approval by the Public Utilities Commission of Nevada, is expected to enter service by the summer of 2011. The decision to move forward with the expansion was largely based on uncertainties over to the timing of the company’s proposed 2,500 MW coal-fired Ely Energy Center in eastern Nevada. The natural gas plant had been slated to be built after the Ely Energy Center was fully operational. Ely’s current timing now requires the company to speed up plans for the gas-powered plant.
Dominion will buy a power station development project in central Virginia from Tenaska. When built, the natural gas-fired station will generate about 600 MW of electricity. The project has air and water permits for a combined-cycle, natural gas-fired power station. Dominion plans a 2-on-1 unit, in which two gas turbines generate electricity and exhaust heat produces steam to generate additional electricity.
NRG Energy, Inc. and Powerspan Corp. plan to demonstrate at commercial scale a technology for carbon dioxide capture from conventional coal-fueled, electric power plants. Powerspan’s ECO2 technology is a post-combustion, regenerative process that uses an ammonia-based solution to capture CO2 from flue gas and release it in a form ready for transportation and permanent geological storage. This carbon capture and sequestration (CCS) demonstration will be conducted at NRG’s WA Parish plant near Sugar Land, Texas, on flue gas equal in quantity to a 125 MW unit. It is expected to capture and sequester about one million tons of CO2 annually.
The Babcock & Wilcox Co. has been awarded a contract by FirstEnergy Nuclear Operation Co. to design, fabricate and deliver two replacement once-through steam generators for the Davis-Besse Nuclear Power Station, an 873 MW pressurized light water reactor in Ohio. Delivery is scheduled for 2013.
Washington State regulators stopped the permit application for a $1.5 billion, 793 MW coal-fired power plant in southwest Washington until Energy Northwest, the builder, meets requirements of a new state climate change law.
Texas public utility regulators approved plans for a $60 million transmission-line project in South Texas. AEP Texas plans to build a 21-mile line and switching stations to interconnect the two wind farms in Kenedy County, Texas. The expected $1 billion wind farms are being developed by Babcock & Brown Ltd. of Australia and PPM Energy of Portland, Ore. The projects could be commercially available next year.
Xcel Energy Inc. is delaying plans for a 600 MW IGCC plant in Colorado due to cost concerns and a desire to find project partners. A spokeswoman said, “We’re not abandoning the project” and Xcel still has “confidence in the technology” for IGCC. Xcel may not propose the plant to Colorado regulators until 2009 or later. Xcel also pushed back the planned completion date to 2016 and said it will continue to study IGCC.
Siemens Power Generation will supply 86 wind turbines with a capacity of 2.3 MW each for the Wolfe Island Wind project, near Kingston in Eastern Ontario, Canada. The purchaser is a unit of Canadian Hydro Developers Inc. The 200 MW wind farm is scheduled to be operational in fall 2008.
NorthWestern Corp. has completed the purchase from SGE, a unit of General Electric Capital Corp., of a 143 MW interest in the 740 MW Colstrip Unit 4 coal-fired steam electric generating unit near Colstrip, Mont. The purchase price was approximately $133.4 million, or around $933/kW.
People & Personnel
NiSource Inc. said that Eileen O’Neill Odum has been named to the new position of executive vice president and group CEO for NiSource’s Indiana business segment, which includes Northern Indiana Public Service Co. Odum joins NiSource after holding senior leadership roles at GTE Corp., Verizon Communications and Commonwealth Telephone Enterprises.
Richard E. Reimels, former president of Babcock & Wilcox Canada Ltd., was named president of B&W NPG.
Dynegy Inc. said Stephen Furbacher, president and chief operating officer, would retire at the end of 2007. The Houston electric provider said Bruce Williamson would continue as chairman and CEO and would re-assume the position of president of Dynegy. Other executive management team members will handle Dynegy’s financial, operational and commercial components.
Southern California Edison’s board of directors elected Ross Ridenoure to vice president where he will oversee operations and regulatory affairs at the San Onofre Nuclear Generating Station. Ridenoure comes to Edison from Omaha Public Power District, where he was vice president and chief nuclear officer with responsibility for the Fort Calhoun Nuclear Station. He earlier served on nuclear-powered submarines as part of the Navy’s nuclear power program.