Five Reasons Why Now May Be the Time to Consider Converting Your Boiler to Natural Gas

A number of projects around here lately have involved the conversion of a boiler firing coal or another high-polluting fuel to natural gas.  Why the switch?  Boiler MACT and NAAQS compliance come to mind.  What other benefits are there from switching to natural gas?  Or drawbacks?  This article presents five reasons why now may be the time to consider that natural gas conversion project.

Please note that the purpose of this article is neither to imply that ALL4 advocates one fuel over another, nor to discuss the fine details of environmental programs; rather, it is to recognize that there may be benefits (e.g., environmental, regulatory, operational, etc.) associated with a natural gas conversion.

Boiler MACT

Although the December 23, 2011 proposed Boiler MACT rule has yet to be finalized, we know that the requirements applicable to a particular boiler will depend on the boiler’s subcategory, which is determined by the boiler’s design and fuel fired.  The more polluting the subcategory, the more stringent the requirements, including emission limitations, work practice standards, operating limits, stack testing, fuel sampling, monitoring, recordkeeping, and reporting.  For example, according to the December 23, 2011 proposed rule, an existing 300 MMBtu/hr boiler designed to burn pulverized coal at a major source of hazardous air pollutants (HAP) would be subject to requirements including, but not limited to, the following:

• Emission limitations for hydrogen chloride (HCl), mercury (Hg), carbon monoxide (CO), and filterable particulate matter (FPM) or total selected metals.
• Work practice standards to perform an annual tune-up, one-time energy assessment, O2 monitoring, and operator training for startup and shutdown procedures.
• Operating limits based on the method of demonstrating compliance (e.g., air pollution control equipment, fuel analysis, performance testing, etc.).
• Initial performance testing to demonstrate initial compliance with emission limitations.
• Stack testing or fuel sampling to demonstrate ongoing compliance with emission limitations.
• Use of a particulate matter (PM) continuous parametric monitoring system (CPMS) to demonstrate continuous compliance with emission limitations.

If that same boiler fired natural gas instead of coal, it would be subject only to the annual tune-up, one-time energy assessment, and operating limits identified above.  Pursuant to the preamble of the December 23, 2011 proposed rule, boilers firing natural gas (i.e., a “gas 1” fuel) is one of the three subcategories which “would be subject to work practice standards in lieu of emission limits for all pollutants.”  Most additional requirements are necessary to demonstrate compliance with applicable emission limitations, so in the absence of emission limitations, natural gas-fired boilers have limited additional requirements.

While there are certainly upfront costs to consider with respect to a fuel conversion project, from the engineering design and implementation to the environmental permitting, converting to a “cleaner” fuel may be an investment worth making if it results in fewer ongoing requirements to comply with, and therefore fewer ongoing costs.

National Ambient Air Quality Standards (NAAQS)

On February 9, 2010, U.S. EPA supplemented the annual NO2 National Ambient Air Quality Standard (NAAQS) of 53 parts per billion (ppb) by establishing a short-term, 1-hour NO2 standard of 100 ppb.  On June 22, 2010, U.S. EPA revoked the existing 24-hour and annual primary SO2 NAAQS of 140 ppb and 30 ppb, respectively, and replaced them with a short-term, 1-hour SO2 standard of 75 ppb.  As discussed in Colin McCall’s recent articles, area designations for the 1-hour NO2 NAAQS will be based on a new network of near roadway ambient monitors that are expected to be in place sometime in 2013, and U.S. EPA is still in the process of determining how the 1-hour SO2 NAAQS area designations will be implemented (i.e., dispersion modeling, monitoring, or a combination of both).  In the meantime, both standards are effective and here to stay.

Do you know where your facility stands with respect to the 1-hour SO2 and NO2 NAAQS?  How about the annual or 24-hour PM2.5 standard?  If you know that emissions of any or all of these pollutants could be a compliance issue for your facility if you were required to model (e.g., for New Source Review (NSR) permitting or NAAQS implementation purposes), converting your boiler to natural gas could help reduce those emissions, and potentially eliminate the problem altogether.  Based on U.S. EPA’s Compilation of Air Pollutant Emission Factors (AP-42), the NOX and SO2 emission factors for natural gas can be up to 82% and 99% lower than those for pulverized bituminous coal, respectively, on a heat input basis (based on a sulfur content of 1% and average heating value of 12,000 Btu/lb for bituminous coal, and 1,020 Btu/cf for natural gas).

Unconventional Natural Gas Resources

Let’s face it, the advances in drilling technology that allow for the development of unconventional natural gas resources has resulted in a fuel renaissance in the United States.  The Energy Information Administration (EIA) has even gone so far as to predict that the United States will be a net energy exporter by 2020 and will be totally energy self sufficient by 2035.  Assuming that your facility already has an appropriately sized natural gas pipeline in place, a natural gas conversion could result in a net decrease in operating costs.

With such low emission rates of particulate matter, imagine not having to operate that fabric filter, electrostatic precipitator (ESP), or cyclone for particulate matter control anymore, and picture how much less fugitive particulate matter will be emitted from delivery, storage, and preparation operations.  Think about what you’ll save when it comes to Boiler MACT compliance.  If the conversion requires the boiler to be replaced, imagine the cost savings from improved energy efficiency.  As of August 2012, the price of natural gas in the industrial sector was $3.77 per thousand cubic feet, compared to nearly twice that at $6.72 five years ago in August 2007. With the price of natural gas projected to remain low for the next five to 10 years, fuel cost savings are apparent.  While the price for coal on a heat input basis is currently lower than the spot market price for natural gas, there are likely additional significant operational cost savings (and reduced liability) associated with using natural gas in lieu of coal that include, but are not limited to:

• Elimination of particulate matter control devices (e.g., fabric filter, ESP, multi-clones, etc.).
• Elimination of SO2 control devices (e.g., dry or wet flue gas desulfurization).
• Elimination of disposal costs associated with coal combustion residue (CCR).
• Elimination of coal storage, handling, and preparation equipment.
• Significantly reduced maintenance costs.

While not quantified herein, when the capital and operational costs associated with using pulverized coal compared to natural gas are considered along with the inherent increase of efficiency with a new, modern natural gas-fired boiler, it is reasonable to conclude that natural gas may ultimately be more cost effective.

Emission Reduction Credits (ERCs)

If your facility is located in an area designated as nonattainment for a NAAQS, then you may be familiar with Emission Reduction Credits (ERCs).  In particular, you may know that an increase in emissions of a nonattainment pollutant that exceeds the major modification threshold during a Nonattainment New Source Review (NNSR) permitting applicability analysis is required to be offset by generating or purchasing ERCs.  How are ERCs generated and made available for purchase?  Facilities that reduce their emissions of a nonattainment pollutant (e.g., by shutting down an emissions unit, installing air pollution controls, or converting to a lesser polluting fuel) can take credit for the emissions reduction by accepting a federally enforceable limit on the new, lower emission rate.  Considering that the conversion of a 300 MMBtu/hr boiler from pulverized coal to natural gas could reduce emissions of SO2 from more than 2,000 tons per year to less than 1 ton per year, a facility has the potential to generate a significant amount of ERCs.

Although area designations for the new 1-hour SO2 NAAQS discussed above cannot be made until the procedure for doing so has been finalized, it’s clear that the stringent new standard will result in many more nonattainment areas than currently exist.  If the location of your facility isn’t designated as nonattainment with the SO2 NAAQS now, it may be in the future.  And let’s not forget that SO2 is also a precursor pollutant for PM2.5 and presently must be considered by major sources of SO2 in PM2.5 nonattainment areas.  ERCs for PM2.5 are practically non-existent.  If any of your industrial neighbors need to offset increases in emissions of SO2 or PM2.5, you could be in a position to generate revenue for your facility by selling them your SO2 ERCs.  Depending on the pollutant, the price per ton of ERCs can be a multiple of $10,000.

The other benefit to generating emission reductions at your facility is the option to “net out” of a significant emissions increase due to a future project.  During a Prevention of Significant Deterioration (PSD) or NNSR permitting applicability analysis, a significant emissions increase is calculated using a two step process.  The facility must first determine whether the project, by itself, causes a significant emissions increase.  If it does, the facility must determine whether there is a significant net emissions increase by including creditable emissions increases and decreases that have occurred during a five year contemporaneous period.  For example, the significance threshold for SO2 is 40 tons per year for a facility that is already a major source of SO2.  If a project causes an increase in SO2 emissions of 50 tons per year, but the facility generated 20 tons of creditable SO2 emission reductions within the last five years or contemporaneous with the completion of the project, the project can “net out” of triggering the applicable NSR permitting requirements.

Carbon Footprint

Reducing emissions of greenhouse gases (GHGs) continues to be one of U.S. EPA’s priorities.  The GHG Monitoring and Reporting Rule at 40 CFR Part 98 requires certain facilities to report their GHG emissions on an annual basis and maintain a Monitoring Plan that details how data is maintained and how calculations are performed and quality assured.  The GHG Tailoring Rule, which became effective on August 2, 2010, sets the timing and establishes thresholds for addressing GHG emissions from stationary sources under the PSD and Title V permitting programs.  Most recently being considered is a carbon tax on high emitters of GHGs.

At the state level, a facility may have a financial incentive to reduce its GHG emissions.  For example, California recently implemented the first phase of its Carbon Cap-and-Trade Program, part of the State’s Global Warming Solutions Act (AB 32).  Under the Program, GHG emissions in the State will be “capped” at a level that will be reduced over time.  GHG allowances will be distributed by the California Air Resources Board (CARB) through auction and will then be available for trade between facilities.  The first auction was held on November 14, 2012.  Facilities that reduce their GHG emissions will be able to generate carbon credits that can be sold to other facilities.

Reductions in GHG emissions may impact the applicability of these GHG programs to a facility.  To reduce emissions of GHGs, a natural gas conversion is a viable option.  Even when taking Global Warming Potentials (GWPs) for other GHGs into consideration (such as methane (CH4), with a GWP of 21, and nitrous oxide (N2O), with a GWP of 310), carbon dioxide (CO2) is the primary contributor to a combustion source’s GHG emissions on a CO2 equivalent (CO2e) basis.  Based on Table C-1 to 40 CFR Part 98, Subpart C, the CO2 emission factor for natural gas is approximately 43% lower than for bituminous coal.  However, coal isn’t the only fuel with high CO2 emissions.  Solid biomass fuels, such as wood and wood residuals and agricultural byproducts, can emit more CO2 than coal.  And while we’re at it, gaseous biomass fuel (i.e., captured methane), petroleum products, and liquid biomass fuels (e.g., ethanol and biodiesel) all emit CO2 at rates less than coal.

Other Considerations

It’s clear that there are a number of benefits to converting your boiler to natural gas.  And because natural gas is a cleaner fuel with fewer emissions, one would think that minimal air quality permitting would be needed to have the conversion approved.  But as with most air quality permitting projects, it’s not as simple as it sounds.  Based on AP-42, emissions of carbon monoxide (CO) and volatile organic compounds (VOC) could potentially increase as a result of switching from coal to natural gas.  Since a fuel conversion qualifies as a modification with respect to NSR permitting requirements, major facilities will need to determine whether the emissions increases are significant by evaluating the difference between their projected future actual and baseline actual emission rates.  Although 40 CFR §52.21(b)(41)(ii)(c) states that projected actual emissions “shall exclude … that portion of the unit’s emissions following the project that an existing unit could have accommodated,” emissions from natural gas could not have been accommodated by a boiler that has never been able to fire natural gas in the past.  Refer to John Slade’s blog post on this topic from earlier this year for more information.

If the natural gas conversion does cause a significant increase in emissions of CO or VOC, the facility would need to determine the Best Available Control Technology (BACT) for those pollutants.  However, most add-on controls for CO and VOC (such as oxidation catalysts and thermal oxidizers, respectively) have not been applied to natural gas-fired boilers in practice, or result in costs that are sufficiently high to justify exclusion of the technology, and, depending on the boiler, can often be eliminated as technically or economically feasible options during a top-down BACT evaluation.

Of course, the projected future of natural gas is just that, a projection.  Some facilities may decide that eliminating the ability to fire coal is too risky given the inherent uncertainties with five- and 10-year projections.  In that case, a facility may simply consider the addition of natural gas burners to allow a boiler the flexibility of firing natural gas or coal.  The permitting implications for the addition of natural gas would differ from the complete conversion to natural gas, with the primary difference being the inability to take credit for emissions reductions resulting from the removal of coal.  However, this difference can make it more difficult to avoid NSR permitting while achieving the desired peak operational levels for the project.  Regardless of whether a facility chooses to convert a boiler to natural gas or to simply add the ability to fire natural gas, the benefits of firing a cleaner fuel are there, but careful planning is critical.  It will be interesting to see how many more natural gas projects get underway in 2013.