Appendix 5A: Natural Gas Use in Industrial Boilers

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1 Appendix 5A: Natural Gas Use in Industrial Boilers Industrial boilers consumed 2.1 Tcf of natural gas in 2006, accounting for 36% of total natural gas in manufacturing. 1 In this appendix, we provide further detailed analysis of two potential drivers affecting demand for natural gas in boilers: modernization of the current natural gas boiler fleet with more efficient units, and replacement of coal boilers with new natural gas boilers. Figure 5A.1 shows that use of industrial boilers is concentrated in the energy-intensive industries, with the four largest applications in chemicals (39%); food processing (17%); paper (13%); and petroleum and coal products (13%). There is strong competition among boiler fuels in the energy-intensive industries, which employ larger boilers and have ready access to alternative fuel supplies. The EPA inventory shows, for example, 382 boilers greater than 100 MMBtu/hr, of which 68% were coal fired. Natural gas is the predominant boiler fuel in other manufacturing industries, which typically employ smaller boilers and do not have the same opportunities for use of by-product and waste fuels. The EPA data show 4,132 natural gas boilers, with an average size of 71 MMBtu/hr. 2 For purposes of our analysis, we used a boiler size of 100 MMBtu/hr as a benchmark. A 100 MMBtu/hr boiler is at the large end of the scale of natural gas boilers; over 95% of existing boilers (all types and all fuels) are less than this size, comprising about 60% of total fuel input capacity (all fuels). 3 A boiler size of 100 MMBtu/hr is comparable to many coal boilers, which typically have a larger average size than natural gas. As a sensitivity analysis, we also analyzed smaller size boilers (50 MMBtu/hr). Figure 5A.1 Use of Natural Gas Boilers in the U.S. Manufacturing Sector (Conventional and CHP/Cogeneration Boilers) Source: EIA MECS All Other 18% Chemicals 39% Food 17% Paper 13% Petroleum & Coal Products 13% All Other includes: Chapter 5 Appendices 1

2 Figure 5A.2 Age Distribution of U.S. Industrial Boilers (All Types and Fuels) 1,200,000 1,000,000 47% Capacity (MMBtu/hr) 800, , , ,000 29% 10% 8% 7% 0 Pre Source: Energy and Environmental Analysis, Inc. Vintage Modernization of the Natural Gas Industrial Boiler Fleet Boilers have long service lives; about 85% of U.S. boilers have been in operation for about 30 years, and almost half of all boilers are nearly 50 years old, as illustrated in Figure 5A.2. There are a variety of existing boiler types and sizes. The two common types of boilers are firetube boilers, which are used primarily for hot water applications, and watertube boilers, which are for larger-scale, steam-generation applications. Most existing natural gas boilers are typically non-condensing boilers, whose exhaust gases retain significant quantities of waste heat. These boilers typically have energy efficiencies in the range of 65% to 70%. 4 The waste heat in the exhaust gases consist of both the latent heat that can be recovered from condensing the water vapor into a liquid, as well as the sensible heat contained in the hot temperatures of the exhaust. Since the mid-1980s, new natural gas boilers have incorporated additional heat recovery systems (i.e., condensing technology) to capture the latent heat and a portion of the sensible heat in the exhaust gases. In addition, use of economizers allows for waste heat to be recovered by pre-heating the boiler feedwater. These improvements boost overall energy efficiency to the 80% to 85% level. In 2004, the DOE set minimum energy efficiency standards for new natural gas boilers in the range of 77% to 82%, depending upon boiler size and boiler technology. 5 Further technology advances have demonstrated efficiency levels in the range of 94% to 95%. DOE cost shared RD&D with the Gas Technology Institute (GTI) has led to the commercialization of a Super-Efficient boiler capable of achieving 94% efficiency in firetube boilers. 6 The super boiler employs a multi-stage combustion system to improve combustion efficiency and reduce NOx emissions. This technology also incorporates a combination of a Transport Membrane Condenser (TMC) and compact humidifying air heater to extract more of the sensible as well as latent heat content of the exhaust gas. 7 In addition, DOE and GTI have collaborated on RD&D on another technology, the Ultramizer System. 8 The Ultramizer consists of a TMC condenser combined with 2 MIT STUDY ON THE FUTURE OF NATURAL GAS

3 high-temperature and low-temperature waste heat recovery systems that preheat the boiler feedwater and provide additional make-up water recovered from the exhaust gas. Boiler efficiencies of 95% are possible for both firetube and watertube boiler applications. 9 We compared the net present value costs, pre-tax, of potential replacement with either a high-efficiency or super-high-efficiency natural gas boiler for an existing 100 MMBtu/hr natural gas boiler. Our analysis employed equipment capital costs and energy efficiency assumptions provided by the GTI, 10 combined with the 2010 average natural gas price for industrial delivery of $5.19 per mcf. The results under these assumptions (Table 5A.1) show that replacement of current natural gas boilers with high-efficiency models would, at a 15% discount rate, yield a reduction of 8% in annualized costs on a pre-tax basis. Replacement with super-high-efficiency boilers would yield annualized savings of 20%. A sensitivity analysis comparing 50 MMBtu/hr natural gas boilers yielded similar results. The payback periods for these boiler replacements range from 1.8 to 3.6 years, based on 2010 actual industrial natural gas prices, and assuming no increase in natural gas prices over this period. Higher natural gas prices would improve the results; lower natural gas prices would reduce the projected annualized savings and extend the payback period. The addition to these equipment expenditures of soft costs (management, supervision, etc.) and expenses attending the change in particular installations will reduce these returns somewhat. Also, in particular instances the attractiveness of boiler modernization will depend on other factors such as the remaining book value of existing boilers that a firm might write off; the availability of investment capital; the return on investment in boiler modernization relative to other opportunities; and the availability of tax incentives, such as accelerated depreciation or investment tax credits. Considering all these factors, however, it appears that replacement will be cost-effective in many installations. Table 5A.1 Cost Comparison of Natural Gas Boiler Modernization Options Existing Natural Gas Boiler Parameter Units Base Case High Efficiency (80%) Assumptions Replacement Natural Gas Boiler Super High Efficiency (94%) Boiler Size MMBtu/hr Boiler Capital Cost $ million Natural Gas Fired Boiler % Efficiency 2010 Industrial Natural Gas $/MMBtu Price Economic Results Net Present Value of Costs $ Million Payback Period Years Impact on CO 2 Emissions CO 2 Emissions Tons CO 2 /yr 35,616 31,164 26,523 Reduction in CO 2 Emissions Tons CO 2 /yr 4,452 9,093 Source: MIT Chapter 5 Appendices 3

4 Two scenarios can provide an indication of the impact on natural gas consumption: (1) a replacement of 50% of current natural gas industrial boiler capacity with high-efficiency natural gas boilers would reduce demand for natural gas by 129 Bcf annually, while (2) a replacement of 50% of current natural gas boiler capacity with super-high-efficiency natural gas boilers would reduce demand by 263 Bcf annually. The reduction in CO 2 emissions ranges from about 4,500 to over 9,000 tons per year per boiler. These results show that replacement of existing industrial natural gas boilers with higher efficiency models could cost-effectively reduce natural gas demand and reduce GHG emissions, suggesting that the DOE should review the current energy efficiency standards for commercial and industrial natural gas boilers and assess the feasibility of setting a more stringent standard. Replacement of Existing Coal Industrial Boilers with Efficient Natural Gas Boilers A CO 2 emissions reduction requirement could lead to a significant level of replacement of existing coal boilers to natural gas. Absent a carbon constraint, a potential driver for fuel switching of coal boilers to natural gas is the establishment of National Emissions Standards for Hazardous Air Pollutants (NESHAPS) for boilers which could lead to a similar result. Our analysis is based on the EPA February 23, 2011, emissions standards for mercury, metals, dioxin, acid gases and other hazardous air pollutants emitted from industrial boilers and process heaters. On May 16, 2011, EPA Administrator Jackson stayed the implementation of the standards to provide for additional review; however, the February 23 standards, and the June 2010 proposed standards, provide a general benchmark for analysis of the trade-offs between retrofitting existing industrial coal boilers with post-combustion controls and replacement of existing industrial coal boilers with efficient, new natural gas boilers. The Clean Air Act requires that emissions reduction standards for each hazardous air pollutant be based upon the emissions reductions that can be attained through installation of the Maximum Achievable Control Technology (MACT), which is defined as the level of performance achieved by the top 12% performing facilities within the subcategory of facilities subject to the standards. The EPA defined 15 different subcategories of industrial boilers and process heaters, setting standards for 11 of the 15 subcategories; existing natural gas boilers (as well as boilers fueled with refinery gas and certain other types of clean gases) fall within the four subcategories for which there are no specific emissions standards. EPA estimates of the emissions reductions achievable from application of the proposed standards are shown in Table 5A.2. Table 5A.2 Estimated National Emissions Reductions from the February 2011 MACT Standards for Industrial Boilers and Process Heaters Hazardous Air Pollutant Annual Emissions Reductions (Tons/yr) Hydrogen Chloride 30,000 Mercury 1.4 Non-mercury Metals 2,700 Particulate Matter 47,000 Sulfur Dioxide 440,000 Volatile Organic Compounds 7,000 Source: EPA 4 MIT STUDY ON THE FUTURE OF NATURAL GAS

5 Three subcategories subject to new MACT standards are coal boilers utilizing different technologies stoker, fluidized bed and pulverized coal combustion. Achieving the emission standards for coal boilers will require the installation of wet scrubbers and fabric filters. Installation of activated carbon injection for control of mercury emissions also may be required, although the EPA noted that it is assuming that the units subject to the MACT calculations were able to achieve the standards for mercury emissions reductions through the use of fabric filters only. At that time of the initial proposed rules in June 2010, the EPA also analyzed fuel switching from coal to natural gas as a compliance option, 11 but concluded that this measure was uneconomical relative to the installation of post-combustion control technology at coal boilers. This EPA conclusion was heavily influenced by two assumptions that were disadvantageous to natural gas: (1) the analysis used the 2008 average natural gas price for industrial delivery of $9.58 per mcf, which represented a period of high natural gas prices relative to today and anticipated in the future (see Chapter 3); and (2) the analysis assumed that boiler owners would retrofit the burners on existing coal boilers to burn gas rather than replace the boilers entirely with new highefficiency boilers designed for natural gas. The EPA estimates that burner retrofit reduced boiler energy efficiency by 5%. We performed a similar analysis for a single 100 MMBtu/hr coal boiler, a relatively large boiler that can be deployed in a number of industry sectors. Four different options were analyzed and compared to a base case. The four options include: (1) retrofit of post-combustion controls (using EPA cost assumptions); (2) retrofit of natural gas burners within the existing coal boiler (using EPA efficiency assumptions); (3) replacement of the existing coal-fired boiler with a high-efficiency natural gas boiler; and (4) replacement of the existing coal boiler with one of the new, super-high-efficiency natural gas boiler technologies. Table 5A.3 Cost Comparison of Industrial Boiler MACT Compliance Options Existing Coal Boiler Parameter Units Base Case Post-Combustion Controls Retrofit Assumptions Natural Gas Burner Retrofit Replacement Natural Gas Boiler High Efficiency (80%) Super High Efficiency (94%) Boiler Size MMBtu/hr Boiler Capital Cost $ Million Coal-Fired Boiler Efficiency % Natural Gas Fired Boiler % Efficiency 2010 Industrial Coal Price $/MMBtu Industrial Natural Gas $/MMBtu Price Economic Results Net Present Value of Costs $ Million Impact on CO 2 Emissions CO 2 Emissions Tons CO 2 /yr 63,840 63,840 37,339 28,938 24,628 Reduction in CO 2 Emissions Tons CO 2 /yr ,501 34,902 39,212 Incremental Cost of CO 2 Reductions $/Tons CO Source: MIT Chapter 5 Appendices 5

6 Table 5A.3 shows the results, including the net present value at a 15% discount rate and effects on CO 2 emissions. The capital cost shown in the table is the cost of equipment, and for the purposes of this comparison it is reasonable to assume that the soft costs and other costs attending the particular firm or installation are roughly the same. The option of retrofitting natural gas burners in existing coal boilers (i.e., the option analyzed by the EPA) was the highest cost option on a net present value basis. 12 The reason is that there is a small energyefficiency penalty from retrofitting natural gas burners, and thus total fuel costs are higher. This finding is consistent with the EPA regulatory analysis. Replacement of the existing coal boilers with high-efficiency natural gas boilers (i.e., 80% efficiency) is slightly more expensive than installing post-combustion controls, but boiler replacement with a super-high-efficiency (i.e., 94% efficiency) natural gas boiler is more cost-effective. A sensitivity analysis comparing smaller size boilers (50 MMBtu/hr) yielded similar results. This cost comparison is dependent upon two assumptions: (1) the estimates of capital equipment cost for retrofitting post-combustion controls for coal; and (2) the relative prices of coal and natural gas. Our analysis uses the EPA capital cost assumptions for installation of post-combustion controls at coal boilers, consisting of wet scrubbers and fabric filters, but without activated carbon injection. For coal boilers that may require additional controls to achieve MACT limits for mercury emissions, costs would increase substantially, making the options for replacement with natural gas boilers much more cost-effective. The comparative results also are sensitive to natural gas prices. The price differential between coal and natural gas used in our analysis was $2.31/MMBtu, based on actual average delivered prices in A lower price differential (i.e., a smaller price spread between natural gas and coal) would make conversion to natural gas more attractive. The potential impact of replacing industrial coal boilers with new, high-efficiency natural gas boilers is significant. The EIA MECS data show that industrial coal boilers and process heaters currently use 892 trillion Btu (0.9 quads) of coal each year. Conversion of this capacity to natural gas would increase demand for natural gas by 0.87 Tcf per year. The actual rate of market penetration would be dependent upon individual facility analyses. Replacement of existing coal boilers with new efficient natural gas boilers in order to meet NESHAPS requirements could reduce annual CO 2 emissions by 52,000 to 57,000 tons per year per boiler. Assuming that high-efficiency (i.e., 80%) natural gas boilers are installed, the net present value cost is slightly higher than installing post-combustion controls. If this incremental cost is assigned solely to CO 2 reduction (ignoring the benefits from further reductions of other pollutants), the incremental cost to achieve the CO 2 reductions is about $5/ton. 6 MIT STUDY ON THE FUTURE OF NATURAL GAS

7 NOTES 1 U.S. Energy Information Administration, 2008 Manufacturing Energy Consumption Survey. 2 U.S. EPA Industrial/Commercial Boiler Survey. 3 Energy and Environmental Analysis, Inc., Characterization of the U.S. Industrial Boiler Population, Report prepared for Oak Ridge National Laboratory, May Energy Efficiency in boilers is measured as AFUE or Average Fuel Use Efficiency. 5 The DOE Energy Efficiency Standards can be found at 10 CFR Part DOE Webcast: GTI Super Boiler Technology, by Dennis Chojnacki, Senior Engineer and Curt Bermel, Business Development Manager R&D, Gas Technology Institute, November 20, U.S. Department of Energy, Industrial Technologies Program, Super Boiler, June See 9 GTI licensed its patented Transport Membrane Condenser (TMC) to Cannon Boiler Works on October 6, Cannon Boiler Works announced plans to release the Ultramizer technology to the public around the end of See 10 Ron Edelstein, Gas Technology Institute, personal communication. 11 The EPA analysis was summarized in an April 10, 2010 Memorandum from Graham Gibson, ERG, to Jim Eddinger, U.S. EPA. 12 The analysis in Table 5A.3 is drawn from a variety of data, including the ERG Memorandum of April 10, 2010; the GTI data; the EPA regulatory analysis, which can be found at boilerpg.html; coal and natural gas prices can be found at The net present value estimates are based on a discount rate of 15%, representing a typical internal rate of return for analysis of corporate capital investments. Chapter 5 Appendices Context 7