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.

Winds of Change Related to Interstate Emissions Trading Rule? Maybe…

The vacatur of the Cross State Air Pollution Rule (CSAPR) in August 2012 has complicated the transport rules that affected multiple states. With CSAPR now out of the picture, U.S. EPA was required to continue administration of the Clean Air Interstate Rule (CAIR) and raised the specter of how states and their upwind and downwind neighbors manage ambient air quality on a state and region-wide basis. Now, an October 2012 court order requiring U.S. EPA to formally find that 40 states have failed to submit air quality plans outlining how they will attain the 2008 ozone national ambient air quality standard (NAAQS) might be the first step toward the creation of a new interstate emissions trading rule. U.S. EPA now has until January 4, 2013 to issue the findings of the failure of the states to submit State Implementation Plans (SIPs) for meeting the ozone NAAQS. After such a finding, if a state does not submit a SIP that is subsequently approved by U.S. EPA, U.S. EPA has to issue a federal implementation plan (FIP) within two (2) years.

What happens next? Appeals by concerned entities are almost guaranteed. The issuance of FIPs could create tension between U.S. EPA and the affected states. Environmental groups are pushing for more stringent NAAQS, which only would further exacerbate the issue. Also, now that the Presidential election is over, we may see the current logjam of regulatory proposals ease and actually get a feel for how the results might impact future rulings. Whatever happens, ALL4 will be here to keep you up to date.

ALL4’s: Is That Your Final Answer?

Last Month’s Answer and Winner:

If you ever find yourself in a game of Trivial Pursuit and David Constant of ESSROC and Steve List and Scott Kirkpatrick of NewPage Corporation are there, just consider that you are playing for fourth place, because these three gentlemen know their trivia and answer very quickly.  All three identified Quaker Oats as being the breakfast cereal that originated in Akron, Ohio; however, since Steve and Scott are past winners, David is being credited for correctly answering our October “Is That Your Final Answer” question.  With our October question, we just have two more questions remaining that will enable you to qualify for our end-of-the-year drawing, when we will award a $250 American Express gift card to one of our 2012 “Is That Your Final Answer” winners.  So be prepared to answer our November question without delay.

Question:

As we enter the traditional “holiday” season, it is interesting to note that our federal holidays are regulated in Title V of the United States Code (5 U.S.C. § 6103).  These federal holidays are only binding on the federal workforce and the District of Columbia although most states observe the holidays.  The first four holidays established in 1870 were New Year’s Day, Independence Day, Thanksgiving Day, and Christmas Day.  The most recently established federal holiday honors Dr. Martin Luther King, Jr. and was first observed in 1986.  Including these five holidays there are six other federal holidays, all but two of which are legally designated to be observed on a Monday.  The November “Is That Your Final Answer” question asks you to name the two holidays, from the unidentified six federal holidays, that are not officially required to be observed on a Monday.  As a hint, one of the holidays will be celebrated next year but was not observed this year.  Good luck with this question. 

Answer: 

Please e-mail your answer to final.answer@all4inc.com.  Include in the e-mail your name, answer, and address (to receive your prize).

ALL4’s Final Answer is a monthly feature of our Blog Digest.  It is designed to test your knowledge across the environmental field, quiz you on the building blocks of air quality rules, stump you on ALL4 general trivia, and challenge you with brain teasers that have perplexed us.  The first correct answer e-mailed to us will qualify the respondent for free ALL4 gear and will enter the winner in our end-of-the year “Final Answer Championship.”  The subsequent month’s Final Answer will identify the winner and the correct answer from the previous month’s question.  You must be an active subscriber of ALL4’s Blog Digest to win a monthly prize and be eligible for the championship prize.  ALL4 employees and family members are not eligible to compete.  Hope you enjoy this feature and good luck!

As The Biomass Turns…Greenhouse Gases from Biomass and Biogenic Sources

The regulatory community has become (for the most part) accustomed to the permitting requirements for greenhouse gases (GHGs). It has become second nature to include them in emission inventories; as part of Prevention of Significant Deterioration (PSD) applicability reviews; and Title V applications. To date, industry has been able to exempt emissions of GHGs from biomass and biogenic sources from permitting based on a U.S. EPA deferral. This deferral is scheduled to expire in 2014 and the obvious question is “what happens then?” Well, take note of this: last month, as reported in the October 11, 2012 Clean Air Report, the U.S. EPA’s Science Advisory Board (SAB) recently submitted its final report suggesting ways to improve U.S. EPA’s draft biomass accounting framework (BAF) for use in evaluating emissions of GHGs from biomass. The SAB’s report was essentially a full approval of its July 2012 report (with minor changes), and included an opinion from one member urging complete exemption for biomass GHGs from air permitting requirements (as an appendix to the final report). The U.S. EPA’s BAF has been railed for its complexity, uncertainties, data deficiencies, and implementation challenges.  The SAB report does not include a recommendation to sustain or eliminate the permitting exemption in 2014 and beyond.

U.S. EPA can consider the SAB report and make revisions to the BAF, or it can move forward with a rule to formalize the BAF and eliminate the permitting exemption. As reported in the Clean Air Report, the temporary exemption still faces legal challenges that are awaiting oral arguments. The National Alliance of Forest Owners (NAFO), which was the group that successfully petitioned the GHG biomass permitting deferral, proposes that U.S. EPA reject the SAB report since it “confuses rather than clarifies the path forward,” and supports the continued exclusion of biomass emissions in a GHG regulatory program “so long as forest carbon stocks in the U.S. are stable or increasing.”

Dissention between U.S. EPA and industry, between U.S. EPA and its own SAB, and retention of the political status-quo makes this one story worth watching.

Hazardous Waste Manifests – A Future Without Filing Cabinets?

On October 5, 2012 The Hazardous Waste Electronic Manifest Establishment Act (ACT) was signed into law by President Obama.  This ACT amends Subtitle C of the Solid Waste Disposal Act (42 U.S.C. 6921 et seq.) by adding Section 3024 – Hazardous Waste Electronic Manifest System.  This amendment requires U.S. EPA to promulgate regulations to carry out the ACT within one (1) year, and to have a hazardous waste electronic manifest system established within three (3) years.  Any regulation promulgated by U.S EPA under the ACT relating to electronic manifesting of hazardous waste will take effect in each State as of the effective date specified in the regulation, which means there will be no delays in applicability waiting for the Federal rule to be adopted by States into their hazardous waste programs.

As authorizing legislation, the ACT does not provide details on what the capabilities of the hazardous waste electronic manifest system will be, or how it might work.  Instead, the ACT anticipates that U.S. EPA will contract with information technology experts to develop and implement the electronic system.  It appears they will have their work cut out for them.  The ACT stipulates some specific requirements that the electronic manifest system must meet, to the same extent as paper manifests do.  These requirements include the following:

• The ability to track and maintain legal accountability of both the person that certifies that the information provided in the manifest is accurately described and the person that acknowledges receipt of the manifest.
• Access by State authorities to print out paper copies of a manifest from the system, if the manifest is electronically submitted.
• Access to all publicly available information contained in the manifest.
• Accommodation for the processing of data from paper manifests in the electronic manifest system, including a requirement that users of paper manifests submit to the system copies of the paper manifests for data processing purposes.    

As with any good authorizing legislation, the ACT also provides for the funding that will be necessary to pay for the hazardous waste electronic manifest system.  The ACT provides for the appropriation of “start-up” funding in the first three (3) years, which is to be offset by the collection of user fees.  The ACT further authorizes U.S. EPA to impose fees on users to pay the costs of developing, operating, maintaining, and upgrading the hazardous waste electronic manifest system, including any costs incurred in collecting and processing data from paper manifests submitted to the system after the date on which the system enters operation.  

To anyone who currently has to keep track of the multiple copies of hazardous waste manifests and their attachments, making sure that each copy is filed where it is supposed to be, the idea of an electronic system that can eliminate all that paper surely sounds inviting.  However, some of the specific language in the ACT indicates that all the paper handling may not be going away.  That language also seems to imply that there could be an option to stick with using only paper manifests, but even that option will come with additional burdens of submitting to the electronic system and paying fees. 

We obviously need to wait and see what U.S. EPA and its information technology contractors come up with to implement the requirements of the ACT.  A hazardous waste electronic manifest system could mean a future in which the efforts necessary to comply with manifesting requirements are streamlined.  On the other hand, based on just some of the language in the ACT, such a future could bring additional burden and cost to hazardous waste generators, transporters, and owner/operators of a hazardous waste treatment, storage, recycling, or disposal facilities.

Since the ACT gives U.S. EPA only one (1) year to promulgate regulations, we should be seeing a proposed rule published in the first half of 2013.  Anyone who manages hazardous waste in the United States will be affected, and so all potentially affected facilities should fully understand the rule upon proposal and be prepared to submit comments during the public comment period, as appropriate.

EPA’s Aggregation Appeal Denied by Court of Appeals

The 6^th Circuit Court of Appeals rejected U.S. EPA’s appeal of the Court’s August 7^th, 2012 aggregation decision (see previous ALL4 4 The Record article here).  The August 7^th decision invalidated U.S. EPA’s method of considering the functional relationship of operations as an overriding factor for determining whether emissions from facilities should be aggregated.  In the specific case, natural gas wells located miles away from an energy company’s primary sweetening plant were being considered “adjacent” and thus U.S. EPA contended that the emissions from the wells should be combined with the sweetening plant, making the source major for air permitting under New Source Review (NSR).  U.S. EPA argued in their appeal that sources would now face uncertainty and even more burdensome air permitting requirements.  Given this ruling, some sources may face a degree of uncertainty.  However, the functional relatedness criteria always was a little difficult to interpret, and as for more burdensome air permitting requirements, the scenario presented by U.S. EPA is a low probability occurrence and furthermore nothing in the ruling precludes a facility from voluntarily aggregating sources should there be a strategic advantage to doing so.  Since there are no conflicting decisions involving the aggregation issue from other Circuit Courts, there is minimal likelihood that U.S. EPA would be successful appealing this decision to the Supreme Court.

Aggregation Appeal Denied

The 6th Circuit Court of Appeals rejected U.S. EPA’s appeal of the Court’s August 7th, 2012 aggregation decision (see previous ALL4 blog post here).  The August 7th decision invalidated U.S. EPA’s method of considering the functional relationship of operations as an overriding factor for determining whether emissions from facilities should be aggregated.  In the specific case, natural gas wells located miles away from an energy company’s primary sweetening plant were being considered “adjacent” and thus U.S. EPA contended that the emissions from the wells should be combined with the sweetening plant, making the source major for air permitting under New Source Review (NSR).  U.S. EPA argued in their appeal that sources would now face uncertainty and even more burdensome air permitting requirements.  Given this ruling, some sources may face a degree of uncertainty.  However, the functional relatedness criteria always was a little difficult to interpret, and as for more burdensome air permitting requirements, the scenario presented by U.S. EPA is a low probability occurrence and furthermore nothing in the ruling precludes a facility from voluntarily aggregating sources should there be a strategic advantage to doing so.  Since there are no conflicting decisions involving the aggregation issue from other Circuit Courts, there is minimal likelihood that U.S. EPA would be successful appealing this decision to the Supreme Court.

A Time For Different Thinking Related to PSD Permitting

U.S. EPA recently issued a New Source Review (NSR) memo on October 15^th that clarifies the timeline that an applicant can expect for “timely and consistent permit processing” of a Prevention of Significant Deterioration (PSD) air permit application by U.S. EPA Regional staff or PSD-delegated air agency.  Now, the remainder of this discussion is not intended to be a critical analysis of the time and degree of notification and review associated with obtaining an NSR PSD air permit; but rather to initiate the thinking process that there is a better way to permit a project.

In the October 15^th memo, U.S. EPA states that the goal for issuing your PSD permit is 10 months from when U.S. EPA determines that your application contains “all of the information necessary for processing the application.”  Except that even after a “careful completeness determination has been made” by U.S. EPA, it may be necessary to request more information to complete the review, and this can extend the issuance time for your permit beyond the stated 10 month goal, past the 1-year statutory decision clock contained in the Clean Air Act (CAA), and into a multi-year process.  If there is an issue that requires a public hearing or brings the Environmental Appeals Board (EAB) into the process, you can also expect delays in the 10 month permit issuance cycle.

Be aware that U.S. EPA is prepared to have other agencies weigh in on your PSD application.  For example, depending on your facility location, U.S. EPA may notify Canada about your project.  If your project could impact minority, low-income, or tribal populations, expect that Environmental Justice could be an issue to be considered.  U.S. EPA will consult with Tribal parties to determine if their interests are being affected as a result of your project.  The Federal Land Manager will likely receive a copy of your PSD application if there are visibility or air quality related impacts that potentially affect a Class I area.  Are there endangered species that could be affected by your project, what about Coastal Zone Management Act (CZMA) issues, does your project have the potential to adversely affect properties covered under the National Historic Preservation Act, and what about the Magnuson-Stevens Fishery Conservation and Management Act (really?). 

Now, I have been assisting clients with NSR/PSD permitting for almost 30 years, so these timelines and most of these agency notifications are really not news to me (except for the fish conservation act).  But after reading this guidance memo from U.S. EPA, it is abundantly clear to me that an alternative to PSD permitting is something I am going to discuss with my clients.  There is simply too long a review cycle and too extensive a list of stakeholder parties that can completely derail any certainty regarding when a PSD permit can be issued and thus when a facility can commence their project. So if after reading this posting, you find yourself saying “What can I do to avoid this situation?”, I recommend that you contact one of us at ALL4 as we are ready to apply some new and different strategic suggestions related to current and future air permitting projects at your facility.

Clarification – Pennsylvania Contemplating “RACT 2” Regulation

On September 12, 2012, the Pennsylvania Department of Environmental Protection (PADEP) presented a draft proposed rulemaking, “Additional RACT Requirements for Major Sources of NO_X and VOC” (referred to as “RACT 2”), to the Air Quality Technical Advisory Committee (AQTAC), a copy of which can be viewed here.  ALL4 initially blogged about RACT 2 on October 23, 2012. The draft proposed rulemaking includes the addition of several new definitions to §121.1 and several new sections to Chapter 129 (i.e., §129.96 through §129.100).  The original blog stated that the RACT 2 requirements would apply to a major NO_X or VOC emitting facility that was in existence on or before July 20, 2012 and would affect emissions units at such facilities for which no RACT requirement has been established.  For clarification, the term “has been established” pertains to specific limits as defined in §§129.51-129.52c, 129.54-129.69, 129.71-129.73, 129.77, 129.101-129.107, and 129.301-129.310 (i.e., Standards for Sources).

Conspicuously absent from this list are the “case-by-case” RACT requirements defined in §§129.91-129.95.  The draft proposed RACT 2 requirements would supersede the requirements of a RACT permit issued under §§129.91-129.95 (i.e., case-by-case RACT), except in cases where the RACT permit specifies more stringent requirements. Conversely, the draft proposed RACT 2 requirements would not supersede the requirements of §§129.201-129.205 or §§145.111-145.113, except where the draft proposed RACT 2 requirements are more stringent.   As mentioned previously, the draft proposed RACT 2 rule differs significantly from the §§129.91-129.95 case-by-case RACT rule as it includes “defined” unit specific RACT limits for most units. This is an important distinction because many existing units that were subject to a case-by-case RACT evaluation under §§129.91-129.95 may now be subject to a defined unit-specific NO_X limit (e.g., combustion units – lb/MMBtu, combustion turbines – ppmvd, internal combustion engines – grams/bhp-hr) under the draft proposed RACT 2.

Please note that the November 13, 2012 AQTAC meeting has been cancelled and the draft proposed RACT 2 rule will now be on the agenda for the December 13, 2012 AQTAC meeting.  This is a rule that will affect numerous facilities in Pennsylvania and all potentially affected facilities should fully understand the rule upon proposal and be prepared to submit comments during the public comment period.

Decision 2012: Where Has the Environment Gone?

Strikingly absent from either candidate’s discourse in the past months, the environment has seemingly taken a back seat to the economy in this election.  Indeed, environmental issues have been outright avoided by both President Obama and Governor Romney except when related to green jobs and energy.  In fact, the candidates seem incapable of discussing environmental topics without relating it back to the economy; a fact which is made blatantly obvious by the lack of a true environmental section on either candidate’s election websites.  More than a little bit perplexed by these omissions, we here at ALL4 have taken it upon ourselves to summarize what the candidates have brought to the table.

President Barack Obama

While more in depth than Governor Romney’s, President Barack Obama’s environmental policy plans are absent from his official campaign website, www.barackobama.com.  Instead, policy topics outlined by his administration may be found on the White House’s website at https://obamawhitehouse.archives.gov/issues.  The administration’s policy issues are divided into three broad topic areas: Securing American Energy; Climate Change; and Our Environment.  The remainder of this section will synthesize the basis of each of these sections as they appear on the White House’s website.

Securing American Energy

A central theme to both candidates’ platforms, methods for securing American energy are discussed in depth.  A multi-step process, the Obama administration’s energy policy consists of three main tenants: domestic oil and gas production, energy efficient consumer goods, and clean energy innovation.  In regards to domestic oil and gas production, Obama stands for decreasing net imports through increasing production in the United States.  The White House’s website reports that “[i]n 2010, the United States imported less than half of all oil consumed – a first in 13 years.”  In regards to consumer choice, President Obama supports the development of energy efficient goods.  To do so, the administration believes that investments in advanced vehicle fuel technologies, public transit, and high speed rail must be made.  In regards to clean energy innovations, the administration identifies government funded organizations and projects, such as the Advanced Research Project Agency-Energy (ARPA-E) and innovation hubs, that it believes must be provided further government support.

Climate Change

The President’s plan to tackle climate change is divided into four topic areas: reducing emissions through clean energy investments and standards, monitoring emissions, climate change adaptation, and climate change science and education.  Repeating some of the ideas from the previous section on securing American energy, the administration identifies the comprehensive cataloguing of greenhouse gas emissions as an important initial step toward “measurable and transparent reductions in carbon emissions.”   In the past years, President Obama backed the reduction of greenhouse gas emissions from Federal Government sources, such as building energy use and fuel consumption, by 28 percent by 2020.  Likewise, he also backed the reduction of Federal Agencies’ greenhouse gas emissions from indirect sources, such as those from employee commuting, by 13 percent by 2020.

Our Environment

The Obama administration identifies the protection of our oceans, conservation of lands, prioritization of clean water, reduction of mountaintop coal mining, reduction of air pollution, restoration of ecosystems, promotion of environmental justice, advancement of sustainable communities, modernization of the National Environmental Policy Act, and Reduction of global mercury emissions as priorities.  A wide and diverse array of topics, the administration sites the passing of the controversial Recovery Act in 2009 as Obama’s landmark environmental contribution.  A polarizing subject, the Recovery Act included funding for programs overseen by the U.S. EPA and the Department of Interior; approximately $11 billion in Recovery Act money have been passed along to these two organizations alone.

Governor Mitt Romney

Just as is the case for President Obama, an environmental section is missing from Governor Mitt Romney’s official campaign website, www.mittromney.com.  However, a section devoted to outlining a national energy strategy is present.  Broken down into a six strategy topics, Governor Romney’s plan is aimed at making “America an energy superpower, rapidly and responsibly” by “increasing [American] production and partnering with [its] allies Canada and Mexico to achieve energy independence…by 2020.”  The remainder of this section will summarize the basis of each of Romney’s six points as they appear on his campaign website.

Onshore State Empowerment

Governor Romney’s six point plan to gaining energy independence is started with empowering states to control onshore energy development.  Specifically, Romney plans to empower states to control all forms of energy production on all lands within their borders, excluding only those specifically designated as off-limits; federal agencies are to provide oversight and certification.

Offshore State Empowerment

Offshore areas are to be developed for energy related purposes.  Governor Romney’s website states, “Mitt will establish the most robust five-year offshore lease plan in history.”  Under such a plan, the coasts of Virginia and the Carolinas will be opened to energy exploration and development.

North American Energy Partnership

A North American energy partnership will be developed with Canada and Mexico.  Governor Romney plans to accomplish this by approving the Keystone XL pipeline, facilitating cross-border energy investment, and instituting a fast-track regulatory approval process for cross-border pipelines and infrastructure.

Energy Resource Assessment

A regimen aimed at ensuring the accurate assessment of energy resources will be instituted.  Romney’s website highlights the growing need to replace “decades-old surveys developed with decades-old technologies.”  Such a regimen will be actuated to determine the quantity and quality of America’s resource endowment.

Permitting and Regulation Reform

Governor Romney would reform all environmental laws and regulations to “strengthen environmental protection without destroying jobs or paralyzing industries.”  Aimed at streamlining reviews, processes, administrative procedures, and lawsuits, reforms will be made to “restore transparency and fairness to permitting and regulation.”

Private Sector Development

Federal research and development will be used to facilitate private-sector-led development of new energy technologies.  Key to this facilitation, the reform of “regulations and permitting processes” will be made to ensure the development of both traditional and alternative energy supplies.

Conclusion

So what does this all mean?  If we are to take the campaign websites to be the last word for both candidates’ environmental policies, President Obama’s strategies could be best described as systematic government regulation while Governor Romney’s strategies could be best described as market based.  However, if the not so prominent presentation, or lack thereof, of each candidate’s strategies on their respective websites is any indication, both candidates are not taking the environment as seriously as some of the other issues this election cycle.

Please remember to get out and vote!