The Sixth Circuit Court of Appeals Rejects U.S. EPA’s Functional Interrelatedness Test for Air Aggregation
Introduction
On August 7, 2012, the United States Court of Appeals for the Sixth Circuit, in a 2 to 1 decision, [1] vacated the United States Environmental Protection Agency’s (U.S. EPA) final determination that Summit Petroleum Corporation’s (Summit) commonly owned natural gas production wells and processing plant, located over a 43 square mile area, were a single major stationary source for Title V permitting purposes. [2] The Court also remanded the case to U.S. EPA for a determination of whether these facilities “are sufficiently physically proximate to be considered ‘adjacent’ within the ordinary, i.e., physical and geographical, meaning of that requirement.” [3] In so doing, the Court unqualifiedly rejected U.S. EPA’s functional interrelatedness test for determining whether facilities are “adjacent” for air aggregation purposes. [4] Under the functional interrelationship test, which is neither a regulation nor guidance, but an agency interpretation of a regulation, multiple sources can be combined and treated as a single source regardless of the physical distance separating them if they are “functionally interrelated.”
The Court’s decision is important for industry because the aggregation or combination of emissions from multiple facilities can result in the aggregated source being subject to the stringent permitting requirements of the Prevention of Significant Deterioration (PSD), Nonattainment New Source Review (NNSR) and Title V permitting programs of the Clean Air Act (CAA). Industry is well advised to track the progress of the case to determine if the Sixth Circuit grants U.S. EPA’s anticipated Motion for Rehearing en banc. [5] Industry should also closely monitor the progress of the case on remand. U.S. EPA could apply the definition of “adjacent” as directed by the Court, abandon its functional interrelatedness test or take other significant action to be determined. Although the decision is not binding outside the Sixth Circuit, [6] it is a very significant legal authority that courts and administrative agencies will no doubt consider [7],[8] in making or reviewing source aggregation determinations. Lastly, all industry in general should take note of the decision because U.S. EPA has used the same “functional interrelatedness” test rejected by the Sixth Circuit in Summit to make many source determination decisions in industries other than natural gas production. In light of the Court’s decision in Summit and other possible future developments, the validity of these decisions may at some point be called into question. [9]
Facts
Summit owns natural gas production wells and a natural gas sweetening plant located over a 43 square mile area primarily in the territory of the State of Michigan’s Saginaw Chippewa Indian Tribes Isabella Reservation. The distance between the wells and the plant varies from one-half mile to eight miles. Summit does not own the land between the wells or the land between the wells and the plant. Summit also uses flares to burn off natural gas waste. The closest flare is one-half mile from the plant and the remaining flares are each over one mile away.
The plant, the wells, and the flares emit sulfur dioxide (SO2) and nitrogen oxides (NOX). The plant emits just under 100 tons of each per year. However, if the emissions of the plant are combined with the emissions of one well, the combined emissions would exceed 100 tons per year.
In January of 2005, Summit, with the Michigan Department of Environmental Quality (MDEQ), submitted a request to U.S. EPA for a determination of whether Summit’s combined facilities could be deemed a single major source for Title V Operating Permit purposes.
On October 18, 2010, nearly six (6) years after the initial request and following several requests for information from U.S. EPA and responses by Summit, U.S. EPA issued its final determination that Summit’s plant, wells, and flares worked together as a single unit that “together produced a single product” [10] and that Summit had failed to provide any evidence to demonstrate that the emission sources were not “truly interdependent”.[11] In sum, U.S. EPA concluded the combined facilities were a “major source” and that a Title V Operating Permit was required.
Under Title V of the CAA, owners and operators of “major sources” are required to obtain Title V operating permits. 42 U.S.C. §7661a(a). The term major stationary source means, “any stationary facility or source of air pollutants which directly emits, or has the potential to emit, one hundred tons per year or more of any air pollutant . . .” 42 U.S.C. §7602(j). The emissions from multiple emissions activities can be combined or aggregated for purposes of determining whether Title V operating permit thresholds are met only if: (1) they are located on one or more contiguous or adjacent properties; (2) they are under common control of the same person (or persons under common control); and (3) belong to a single major industrial grouping. 40 C.F.R. §71.2. [12] If emissions activities fail to meet any one of these three requirements, they cannot be combined or aggregated. [13]
In 1978, U.S. EPA promulgated initial PSD regulations that contained a different definition of “stationary source” than the current PSD regulations. [14] In its initial decision considering the validity of those regulations, the United States Court of Appeals for the District of Columbia Circuit, in Alabama Power Company v. Costle, [15] rejected U.S. EPA’s source definition and held that U.S. EPA’s discretion in defining the term “stationary source” was controlled and limited by §111(a)(3) of the Clean Air Act, 42 U.S.C. §7411(a)(3), which defines that term as, “any building, structure, facility or installation which emits or may emit any air pollutant…”.
In its second opinion considering the validity of the initial PSD regulations, the Court in Alabama Power Co. v. Costle, [16] commented that to permit an entire plant or other grouping of emissions activities to be considered a single unit, U.S. EPA should define the terms, “building, structure, facility or installation” with consideration of criteria such as, “proximity and ownership.” Id. 397.
In September of 1979, U.S. EPA had proposed modifications to its initial PSD regulations including an identification of aggregation criteria that was limited to considerations of proximity and ownership. [17],[18] However, in January of 1980, after the D.C. Circuit’s second opinion in Alabama Power, U.S. EPA solicited public comment on whether a third criterion in addition to proximity and ownership should be added. [19] EPA rejected the two prong approach (i.e., proximity and ownership) suggested by the Court in Alabama Power because U.S. EPA believed that such approach would result in the aggregation of activities which did not fit within “the common sense notion of plant” or the ordinary meaning of, “building,” “structure,” “facility” or “installation.” [20]
Notably, through the process, U.S. EPA expressly considered and decisively rejected functional interdependence as a criterion for determining whether emissions from multiple emitting activities should be aggregated. U.S. EPA concluded that the administration of such a requirement would be burdensome on the Agency and, “would have embroiled the Agency in numerous, fine grained analyses.” 45 Fed. Reg. at p. 52695. Ultimately, U.S. EPA settled on the two digit SIC Code which is found in its regulations today as its criteria for determining if a functional relationship exists between emissions activities or facilities.
In contradiction of the above express and unqualified rejection of functional interdependence as a criterion for use in source determinations, U.S. EPA in the years following 1980 began using the criterion, which as mentioned, is neither a regulation nor guidance but an agency interpretation, in source aggregation determinations extensively. [21] As stated, U.S. EPA uses functional interrelatedness to determine if sources are “adjacent” within the meaning of the aforesaid regulations and can conclude that emissions activities, regardless of distance can be considered “adjacent” if they are functionally interdependent. [22]
On January 12, 2007, then-Acting Assistant Administrator for U.S. EPA’s Office of Air and Radiation, William L. Wehrum, announced that U.S. EPA would take a different approach concerning aggregation decisions in the oil and gas industry. [23] While functional interdependence might have been considered, it would not drive the determination.
“Given the diverse nature of the oil and gas activities, we believe that proximity is the most informative factor in making source determinations for these industries. We do not believe that it is reasonable to aggregate well site activities, and other production field activities that occur over large geographic distances, with the downstream processing plant into a single major stationary source. Aggregation of such geographically-dispersed activities defies the concept of contiguous and adjacent.” Wehrum Memorandum at pp. 3-4.
On September 22, 2009, Gina McCarthy, Assistant Administrator for the U.S.EPA Office of Air and Radiation, withdrew the Wehrum Memorandum, criticizing it as being overly simplistic and stating that single source determinations should be made on a case-by-case basis utilizing the aforementioned three regulatory criteria. [24] Significantly, the McCarthy Memorandum did not endorse functional interdependence as a test for adjacency and expressly acknowledged that, “after conducting the necessary analysis, it may be that, in some cases, ‘proximity’ may serve as the overwhelming factor in a permitting authority’s source determination decision.” [25]
At the outset the Court noted that the parties agreed that U.S. EPA properly exercised jurisdiction over the tribal lands involved, that the emissions activities were not contiguous (i.e., abutting), and that the facilities were commonly owned. Noting those facts, the Court stated the sole issue before it was, “whether Summit’s facilities are ‘adjacent’ to one another, thus converting them into a stationary source, and a major source, under Title V.” [26]
Having framed the issue, the Court went on to conclude that the use of “adjacent” in U.S EPA’s Title V regulations [27] is unambiguous, basing its conclusion on the dictionary definition of the term, the etymology of the word and applicable case law. [28] The Court then stated that U.S EPA’s interpretation of the regulation as permitting it to consider the functional interrelationship between emissions activities or contextual relationship was not consistent with the plain meaning of, “its unambiguous regulation…” “We conclude that the EPA’s interpretation of the requirement . . . that activities can be adjacent so long as they are functionally related, irrespective of the distance that separates them, undermines the plain meaning of the text, which demands, by definition, that would-be aggregated facilities have physical proximity.” (Emphasis added). [29] Further, the Court afforded U.S. EPA’s interpretation of it regulations no deference because it found that the term “adjacent” was unambiguous and rejected U.S. EPA’s argument that its interpretation was entitled to “heightened deference” because it was long-standing. “We conclude that an agency may not insulate itself from correction merely because it has not been corrected soon enough, for a long-standing error is still an error.” [30]
Next, the Court stated that even if it had afforded U.S. EPA’s interpretation of its regulations deference it would nonetheless have reached the same conclusion concerning U.S. EPA’s decision. [31] The Court found that U.S. EPA’s interpretation was plainly inconsistent with the regulatory history of source determination criteria described above (“the EPA’s decision not to employ a functional relatedness test was categorical and unqualified”) [32] and EPA’s regulatory guidance concerning source determination (i.e., the Wehrum and McCarthy Memoranda, also described above).
In the dissenting Opinion, Circuit Judge Moore essentially concluded that the word “adjacent” as used in U.S EPA’s Source Determination Regulations is ambiguous because U.S. EPA has not specified the distance beyond which sources cannot be considered “adjacent,” and further that as a result, U.S. EPA’s use of the functional interrelatedness test to construe that term was reasonable and entitled to deference.
Conclusion
As stated Summit is an important decision for industry. As a result industry should monitor the progress of the case closely including how U.S. EPA interprets the holding of the Court on remand. Industry should also monitor the decisions of courts and agencies including the PaDEP that make aggregation determinations to further determine how the case will be interpreted and if any such courts or agencies reach different conclusions concerning EPA’s functional interrelatedness test. Lastly, and as also mentioned, depending on future developments the case may have significant implications for industries other than natural gas and those industries should be attentive to future developments.
One final note, on September 10, 2012, a federal appellate court granted the U.S. EPA additional time to file its appeal of the Sixth Circuit’s vacatur of the Summit Petroleum Corporation final determination on source aggregation. The U.S. Court of Appeals for the 6th Circuit has granted U.S. EPA’s motion for an additional 30 days, until October 22, 2012, to appeal the Court’s decision to vacate.
About the Author: Ronald S. Cusano is a partner in the law firm of Schnader Harrison Segal & Lewis LLP, a member of its Energy and Environmental Practice Groups and has extensive experience in environmental permitting and litigation.
Note: This article is published for informational purposes only. It does not dispense legal advice or create an attorney-client relationship with those who read it. Readers should obtain professional legal advice before taking any legal action.
[1] Summit Petroleum Corporation v. United States Environmental Protection Agency, Nos. 09-4348; 10-4572 (6th Cir. Aug. 7, 2012).
[2] 42 U.S.C. §7471 et seq.
[3] Summit, slip op. at 2.
[4] Id. at 22-23.
[5] The Sixth Circuit has granted a request by EPA for additional time to file its Motion for Rehearing by the Court en banc. Appellee’s Mot. Extend Time to File Pet. Reh’g En Banc (Sep. 4, 2012); Order Granting Mot. (Sep. 10, 2012).
[6] The Sixth Circuit has jurisdiction over federal district courts in Kentucky, Michigan, Ohio, and Tennessee.
[7] In Group Against Smog Pollution v. Commonwealth of Pennsylvania, DEP, EHB Docket No. 2011-065-R the Pennsylvania Environmental Hearing Board described the Sixth Circuit’s decision in Summit as “persuasive.”
[8] On October 12, 2011, the Commonwealth of Pennsylvania, Department of Environmental Protection (“PaDEP” or “Department”) issued interim guidance for performing single stationary source determinations for the oil and gas industry. Like the Sixth Circuit in Summit the Department rejected EPA’s functional interrelatedness test for single source determinations.
[9] Indeed, the court in Summit discusses EPA’s use of the functional interrelatedness test without regard for physical proximity and cites numerous examples from a number of industries. Slip op. at 16-17.
[10] Letter from Cheryl Newton, Director, Air and Radiation Division, EPA, to Scott Huber, Summit Petroleum Corp. at 6 (Oct. 18, 2010), available athttp://www.epa.gov/region7/air/title5/t5memos/singler5.pdf .
[11] Id.
[12] Stationary sources are considered to belong to the same major industrial grouping if they share a two-digit Standard Industrial Classification (“SIC”) Code. 40 C.F.R. §71.2.
[13] The PSD and NSR programs of the Clean Air Act utilize similar definitions and criteria for determining whether or not permits under those programs will be required.
[14] In the 1978 PSD Regulations, EPA defined “source” as “any structure, building, facility,equipment, installation, or operation (or combination thereof).
[15] 606 F.2d 1068 (1979).
[16] 636 F. 2d 323, 395 (1979).
[17] In September of 1979, EPA proposed to define “building, structure, facility and installation” for PSD purposes as “any grouping of pollutant-emitting activities which are located on one or more contiguous or adjacent properties and which are owned or operated by the same person (or persons under common control). 45 Fed. Reg. No. 154 at p. 52693.
[18] In the preamble to the final 1980 PSD Regulations, which have remained largely unchanged through the years, EPA explained the limitations it believed were placed on its discretion in identifying aggregation criteria by the D.C. Circuit’s second opinion in Alabama Power, as follows:
In EPA’s view the December opinion of the Court in Alabama Power sets the following boundaries on the definition for PSD purposes of the component terms of ‘source’: (1) it must carry out reasonably the purposes of PSD; (2) it must approximate a common sense notion of ‘plant’; and (3) it must avoid aggregating pollutant-emitting activities that as a group would not fit within the ordinary meaning of ‘building”, “structure”, “facility”, or “installation”. 45 Fed. Reg. 52695.
[19] 45 Fed. Reg. 6803.
[20] 45 Fed. Reg. 52695.
[21] See fn. 10.
[22] See Summit opinion.
[23] See William L. Wehrum January 12, 2007 Memorandum to Regional Administrators I-X.
[24] See Gina McCarthy September 22, 2009 Memorandum to Regional Administrators Regions I through X.
[25] McCarthy Memorandum at 2.
[26] Slip op. at 11.
[27] Id.
[28] Id. at 11-12 .
[29] Id. at 15.
[30] Id at 18.
[31] Id at 18-19.
[32] Id. at 21.
Exploring Plantwide Applicability Limit (PAL) Basics
Initiating a project that triggers major new source review (NSR) requirements or an NSR applicability analysis at an existing major stationary source is arguably more difficult now than at any time since the inception of the Clean Air Act (CAA). Each of the various steps are complicated in their own way, from figuring out what exactly your “project” includes, to documenting baseline actual emissions, projected future actual emissions, emissions that “could have been accommodated,” and excludable emissions, to figuring out what Best Available Control Technology (BACT) really is for your modification. While we are piling on, let’s add the greenhouse gas (GHG) tailoring rule (and its idiosyncrasies) and national ambient air quality standards (NAAQS) that are changing in form and are becoming uncomfortably close to background levels with each review cycle. All of the above must be accomplished while working your way through the endless volumes of U.S. EPA and state-specific guidance, policy, interpretive memoranda, and precedence that encompass the prevention of significant deterioration (PSD) regulations. Heaven forbid that your facility is located in a non-attainment area and you find out that you cannot initiate a project at your facility because there are zero (0) tons of PM2.5 offsets available at any cost to meet applicable nonattainment new source review (NNSR) requirements. Better yet, you find out that you must now include emissions from a facility that you do not own, and is located several miles from your facility, in your NSR applicability analysis all because a previous interpretive guidance memorandum was rescinded by a new agency official.
Believe it or not, an alternate path exists within the bowels of the PSD and NNSR regulations – the Plantwide Applicability Limit (PAL) provisions. The PAL provisions that exist in the PSD and NNSR rules and (supposedly) in all state “SIP-approved” permitting programs were part of the NSR Reform package that also brought us the “actual-to-projected-actual” test and the “excludable emissions” concepts which was finalized in December 2002 and implemented by states in the following years. It seems as though the general consensus throughout the regulated community is that PALs are more trouble than they are worth and do not provide any substantial benefits. However, for many facilities, PAL based permits represent a legitimate means for facilities to avoid the difficulties that are now a routine part of major NSR permitting. Read on to learn a bit more about PALs in general and how a PAL based permit could help your facility obtain a bit of regulatory flexibility.
What is a PAL?
As indicated earlier, PAL is the acronym for Plantwide Applicability Limit. A PAL is essentially a facility-wide permit limit for a regulated NSR pollutant or a facility cap for that pollutant. A PAL permit based on past actual emissions establishes a single, facility-wide emission limit for designated regulated NSR pollutants. PALs can be established for one (1) or more regulated NSR pollutant at an existing major stationary source. Each PAL level is based on a 12-month rolling total, expressed in tons of pollutant per year. Compliance with PALs must be demonstrated monthly during the term of the PAL permit. Each limit is generally established based on the average annual (e.g., baseline) emission rate for a 24-month consecutive period during the prior 10 years of facility operation. In most states, different baselines can be established for different regulated NSR pollutants. The PSD (or NNSR) significant increase threshold for the regulated NSR pollutant that is specified in the rule is then added to the baseline actual emission rate to set the PAL level. The PAL rule also includes provisions that address emission units that have been added or removed from service at a facility since the baseline period. Provisions for actual PALs are codified in the Federal regulations at 40 CFR §52.21(aa), §51.165(f), and Appendix S to Part 51 – Emission Offset Interpretative Ruling. Most SIP approved state NSR programs include PAL provisions. PAL provisions are included in all delegated state programs. The PAL is in place for 10 years and at renewal, the limit can be adjusted (downward). While a PAL is established for a 10 year period, it can be reopened during its term for a number of reasons and the limit can be adjusted accordingly – for example for new applicable requirements, or to address issues like NAAQS compliance. U.S EPA still supports PALs; even the current administration does as evidenced by the recently finalized PAL revisions to clarify the use of PALs for GHGs.
PALs were initially of great benefit to sources where technology (and regulations) was driving emissions lower. In other words, when facilities wanted to make changes and increase production, technology was pushing emission rates lower per unit of production (e.g., automobile surface coating, glass manufacturing). For more complicated sources like pulp mills or cement plants, there were always three big concerns. The first was with the effort associated with developing the PAL application. The second was developing the methods to demonstrate compliance with the PAL (e.g., developing emission rate data for all units, tracking and demonstrating compliance). The third is the fact that facilities are perpetually looking at ways to increase production and the PSD rules could work to allow emissions increases to occur at facilities as a result of a modification (with the associated BACT, modeling, etc.). So why would a facility even consider a PAL that locks into historic baseline actual emission rates?
With regard to the first concern, the development of a PAL for a complicated facility, you must consider the emissions related work that has likely already been completed over the past several years by default through minor NSR permits, enhanced emission inventories for reporting purposes, and completion of information requests for regulatory support. By now there should not be any emissions units at most major facilities that are not identified in a spreadsheet with associated representative emissions factors. Therefore, tracking and calculating monthly mass emissions could just be a matter of linking the production rate data of the units to the appropriate spreadsheet cells.
With regard to the second concern regarding being locked into limits that represent historical baseline emissions, we suggest the following analysis. Review your reported emissions inventories for the past ten years. Almost every major facility emission inventory that we work with shows a trend of decreasing actual emission rates. There are multiple contributing factors to this trend, some of which are regulatory driven. However, the bottom line is that baseline emissions are shrinking and this fact will impact any future PSD permitting endeavor. Even more importantly, you must consider the impact that the new short-term NAAQS will have on actual facility emissions once PSD is triggered. Surprisingly, applying best available control technology (BACT) is no longer the primary concern with regards to PSD permitting as post change emissions may need to be controlled to levels that are more stringent than BACT in order to demonstrate compliance with short term NAAQS. Hence, if you are PSD significant for a project the significant impact levels (SILS) and the NAAQS will now drive the PSD permitting process and you may ultimately find that your project cannot be PSD significant, period. If your project can’t be permitted through the PSD process, then you will need to build emission reductions into your project in order to avoid PSD. Ultimately this means that your future actual emissions and future baseline actual emission rates will be lower still for future projects. A PAL will let you preserve your baseline actual emission rate for at least 10 years and possible longer.
A primary advantage of a PAL permit is that as long as the facility demonstrates compliance with the PAL, physical changes and changes in the method of operation are not major modifications and projects do not require approval under applicable PSD (or NNSR) programs. Facilities may still need to deal with state construction permitting requirements but the associated NSR applicability analyses for every project and the complications associated with PSD/NNSR for major modifications go away. Essentially, the facility takes over managing the operations and projects to allow growth while maintaining emissions below the PAL levels. If emissions reductions are required, it is the facility that makes the decision with regard to what unit(s) is controlled and what control technology is chosen, not the regulatory agencies. Consequently, regulatory agency review times for modifications are compressed and even eliminated in many instances. In our opinion, the time saving associated with facility changes represents the greatest advantage of operating under a PAL permit.
Most SIP approved state NSR programs include PAL provisions. PAL provisions are included in all delegated state programs. ALL4 suggests initially reviewing the PAL regulations in your state and then initiating contact with the regulatory agency to get a feel for their familiarity with PALs and their receptiveness to their implementation. Note that some state regulations (i.e., Delaware) may not explicitly address PALs and in such instances, contact with the agency is required to assess how PALs are implemented. We have found that most state air regulatory agencies are familiar with the PAL concept and are generally supportive. However, due to the relative scarcity of PAL permits, it is fair to assume that many agency personnel have never seen a PAL application. The learning curve associated with agency review of a PAL application will likely translate into an extended technical review period.
You will need to compile ten (10) years of baseline actual emission rates and then think about what pollutants you may or may not want a PAL for. This strategic planning will take time, effort, and money to be done properly. Once you determine how you would like the PAL structured, it is recommended that you initiate a formal meeting with the regulatory agency to present your plans and work through the details. They will need to be comfortable with your emissions information and there likely will be issues (think about PM2.5 and condensables) to discuss and work through. All of the other typical baseline emission inventory issues will be exposed as well (e.g., have the historic emission factors been high or low, good or bad, measured or AP-42?). You may also need to amend reported actual annual emissions and pay associated fees (and penalties). Please note that the state agency will need to “buy in” to any initial baseline emissions adjustments needed for this to work.
After agency acceptance, you will need to compile the application and proceed through the formal application submittal process. The implementing regulations at 40 CFR §52.21(aa), §51.165(f), and Appendix S to Part 51 – Emission Offset Interpretative Ruling as well as any SIP approved state program all lay out the required contents of the application. Please note that there is no specific requirement in the PAL rules to demonstrate compliance with the NAAQS. However, as mentioned earlier, a PAL can be reopened to address NAAQS issues so going into a PAL without at least some knowledge of facility-specific NAAQS concerns might be unwise.
The costs associated with developing a PAL application could cover a pretty wide range, likely greater than $35,000 or more depending on the status of the existing facility baseline emission inventory, the complexity of the facility, and the possibility of conducting exploratory NAAQS modeling. Also note that the longer the process takes for reasons like protracted agency negotiations, the more it’s going to cost. On the other hand, the cost of a PAL application will likely be comparable to the cost of the next PSD permit at the plant, and that cost would go away under a PAL.
Our take is that facilities have always had enough trouble with the complications of air permitting that they have avoided even investigating the possible benefits of PALs. The reasons mentioned above with regard to why complex facilities have avoided PALs combined with a fear of “giving up” existing permit limits (some of which may be greatly inflated anyway) for a cap based on actual emissions are likely driving this aversion to PALs. Also, a common PAL misconception is that all unit-specific requirements are eliminated, which is not the case. While NSR avoidance limits (e.g., emissions, production, and hours of operation) are eliminated by a PAL, unit-specific applicable requirements (e.g., NSPS, NESHAP, RACT, SIP requirements, technology limits, etc.) remain applicable.
Facilities have also expressed the point that a PAL may need to be exceeded at some future time. Note that a PAL can be increased, but there are requirements for technology evaluations for all of the emissions units, and all of the requirements for NSR/PSD are triggered including the need to demonstrate compliance with the PSD increments and the NAAQS. Facilities also have concerns regarding how they may exit from a PAL permit should they decide that it is not working for their plant. PAL termination requirements are included in the implementing and state specific PAL rules. First, every emission unit or group of units under the PAL will end up with an emission limit for that pollutant so that the total from all units is equal to the previous PAL level. The facility would propose the “distribution” of the PAL emissions to the emissions units for the administrator’s approval. The resulting new permit would require a compliance demonstration for each unit with its new limit on the same 12-month rolling total basis as with the PAL. Existing and prior BACT, RACT, and other federally applicable requirements would continue to apply.
A PAL May Be a Smart Strategic Decision for Your Facility
In essence, since the PAL level represents an NSR “bright-line,” facilities with PAL permits can evaluate projects and determine how they will comply with the PALs, rather than being required to consider PSD (or NNSR), apply BACT or lowest achievable emission rate (LAER) technology, purchase offsets, and demonstrate NAAQS compliance. Under a PAL permit, decisions regarding process and air pollution control technology remain with the source, and the facility baseline emissions are preserved for at least ten (10) years. Most importantly, if a PAL permit makes sense for a facility, the facility can potentially have an economic advantage over competitors that make similar modifications and must go through the time consuming and costly major NSR permitting process.
As indicated above, many facilities have already recognized the advantages that PAL permits provide. PAL permits represent a key component of the 2002 NSR Reform rule that have not been the subject of subsequent evaluation and re-interpretation by U.S. EPA. As a result, the advantages that were recognized for facilities where PAL permits are a good fit remain in place. PAL permits represent a legitimate means for facilities to avoid the difficulties that are now a routine part of air permitting events that trigger the requirements of major NSR.
ALL4 has been involved with the development and implementation of several PAL permits across different industries and we have never had a client, or have spoken to a facility that had a PAL that thought negatively about it. Just imagine your thought process every time that someone at the plant tells you that they have already made a change, or they plan to have a new project in place with added production and pay back in the next few months. How many times have you heard, “don’t worry because we will not exceed the permit limit.” Having a PAL permit in place would virtually eliminate the heartburn caused by such actions, not to mention fears of a CAA 114 letter and the associated repercussions. Please contact Roy Rakiewicz at (610) 933-5246 x27 or John Egan at (610) 933-5246 x14 if you have any questions related to PALs.
ALL4’s: Is That Your Final Answer?
Last Month’s Answer and Winner:
A scant minute separated the first two correct responses to last month’s “Is That Your Final Answer” question concerning the only occurrence of an arc serving as the border between two states. However, it was who David Bier of Motiva Enterprises who provided the first correct answer that it is Pennsylvania and Delaware who share this unique arc border. And as for the parcel of land that was disputed until 1921, well, because of the incongruity of a 12 mile arc centered on New Castle, Delaware and used as the northern border for Delaware and the original William Penn longitude/latitudes used to establish the Pennsylvania state boundaries, a tract of land known as the “Delaware Wedge” was claimed by both states. Although Dave admitted to consulting Wikipedia to identify this tract of land, no other responses named the Delaware Wedge. Congratulations to Dave and thanks to all those who participated in the contest.
Question:
October will see the end of more than 52 years of bachelorhood for me. During that period my mother displayed admirable patience for some 30 of those years and Marie, my fiancée, has shown even greater patience for the last six. And I certainly do not plan on testing Marie’s patience for not remembering any of the forthcoming anniversaries, which I can only hope will exceed 50. We all know that I will celebrate the 25th and 50th anniversaries with a silver and golden gift, respectively, to Marie, but as the September “Is That Your Final Answer” question, what will the 1st anniversary gift to Marie be? I also mention that this month’s answer will be of interest to ALL4’s Chuck Doyno who, after October, will also need to know this answer to avoid disappointing his soon to be wife Katie next year. Good luck with our September 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!
Spare Parts and Permit Conditions
A seemingly simple question was recently raised by an ALL4 client regarding the level of spare parts inventories that facilities are obligated to keep on hand for air pollution control equipment, as required by applicable air permits. The question prompted a review of the facility’s operating permit to identify any specific obligations. While the operating permit did include specific requirements for the facility to maintain an adequate inventory of spare “bags” for several fabric filter dust collectors, it was not surprising that that the permit was silent regarding specific spare parts inventories for other types of air pollution control (e.g., selective non-catalytic reduction (SNCR), dry sorbent injection, etc.). While the short answer to the question is that operating permits generally do not require spare parts inventories to be maintained for such systems, the real answer is a bit more complex as compliance with several typical operating permit conditions could be impacted by the availability of spare parts for critical air pollution control systems as listed below:
- General Duty Requirements – Operating permits may include conditions that reflect a “general duty” for the facility to operate and maintain sources and air pollution control devices in accordance with “good engineering practice” or “good operating practices.” Such terms are very generic with potentially broad implications and the case that maintaining an inventory of spare parts for critical equipment would be viewed as a “good engineering practice and good operating practice” and that failure to do so is not.
- Maintenance/Repair Requirements – Operating permits may include conditions with specific language regarding the implications associated with the failure of a facility to adequately maintain or repair air pollution control equipment. Failure to maintain an inventory of spare parts for a piece of critical air pollution control equipment could be viewed as a failure to maintain air pollution control equipment in the event of an equipment malfunction or breakdown, should a key spare part not be readily available.
- Affirmative Defense – With both federal and state regulators focusing on “affirmative defense” provisions, developing an affirmative defense in response to a malfunction of an air pollution control systems would be much easier if spare parts to address the malfunction were readily available on-site.
- Cessation of Operations – 40 CFR Part 70 requires that operating permits include language that prohibit facilities from citing the need to halt or reduce a permitted activity to maintain compliance with a permit term or condition in the defense for an enforcement action. Based on this language, if spare parts are not readily available and must be ordered resulting in an extended malfunction of the control device (and presumed permit violations if operations continue), it is almost imperative that the process be shutdown during the malfunction to mitigate any enforcement action.
- Negligence – Operating permits may include conditions that disqualify upset conditions caused by “poor maintenance or careless operation” as malfunctions. Malfunctions are generally categorized as not reasonably preventable. A lack of adequate spare parts for air pollution control equipment could be viewed as “poor maintenance or careless operation” by a regulatory agency.
When planning spare part inventories for air pollution control equipment, it would be prudent to discuss typical key spare parts lists for affected equipment with system vendors and to have a clear understanding of the associated order and delivery times. If the equipment is new to the site, discussions with facilities that use similar equipment regarding their operational experience and maintenance practice is recommended. On an extreme note, it may be wise to evaluate the cost of maintaining an inventory of air pollution control system spare parts on-site with the costs associated with an unanticipated and extended production outage that could result from an air pollution control system breakdown.
September 2012 Pennsylvania Air Quality Technical Advisory Committee Update
The September 2012 Air Quality Technical Advisory Committee (AQTAC) meeting was held on Wednesday, September 12th. The agenda was very full, with three proposals that the Pennsylvania Department of Environmental Protection (PADEP) was seeking approval to take to the Environmental Quality Board (EQB) for action.
AQTAC voted to approve taking the final form of the regulation to lower the sulfur content of fuel oil burned in
No. 2 and lighter oil – 500 PPM
No. 4 oil – 2,500 PPM
No. 5, No. 6 and heavier oil – 5,000 PPM
On an issue that will eventually impact all Title V facilities, AQTAC approved PADEP to propose a rulemaking to increase the Title V emission fee from $56 per ton to $85 per ton, beginning with emissions released in 2013. 2013 emission fees will be due on or before September 1, 2014.
AQTAC did not concur with PADEP sending their proposed Reasonably Available Control Technology (RACT 2) regulation for major sources of nitrogen oxides (NOX) and volatile organic compounds (VOC) as a proposal to the EQB. The RACT regulation is a prerequisite of the U.S. EPA in order for
- The regulation, as drafted, had very short submittal and compliance deadlines.
- Several members requested to know the overall number of RACT submittals that would be made to PADEP by affected facilities.
- Several members also wanted to know how many case-by-case RACT analyses were expected (case by case analyses would be required for facilities not able to meet the presumptive rule RACT levels).
A concern expressed by several AQTAC members related to the significant work effort that was required during the previous RACT submittals of the mid to late 1990s. PADEP expressed confidence that they have significantly reduced the work effort, with numerous presumptive RACT compliance requirements in RACT 2 versus the required case-by-case requirements of the original RACT rule.
PADEP will be returning to AQTAC either for the October or December AQTAC meeting with answers to these questions and likely regulatory revisions. PADEP will again be seeking approval to move the revised RACT 2 regulation to the EQB for publication and comment. We are advising all major sources of ozone precursors to keep an eye on the
Mind Your NAAQS: An Update
The pre-election regulatory lull is in full swing, so we thought it was a good time to get fully caught up on the latest National Ambient Air Quality Standards (NAAQS) news. Here are the key points to be aware of related to criteria pollutant NAAQS levels:
- 1-Hour Sulfur Dioxide (SO2): We have been keeping you up to date on the 1-hour SO2 NAAQS saga through various blog posts and 4 The Record articles. Our last update pertained to the U.S. EPA stakeholder workgroup meetings that were held to solicit comments on the best way to implement the 1-hour SO2 NAAQS (dispersion modeling, monitoring, or a combination of both?). U.S. EPA heard a range of comments at those meetings and is tasked to release a proposed rulemaking or proposed guidance on the NAAQS implementation process. Given the information that U.S. EPA needs to consider and the logistical considerations around a possible increased ambient monitoring network, we would be surprised to see anything be released until mid-2013. Keeping with that trend, U.S. EPA delayed the finalization of 1-hour SO2 designations for areas with ambient monitoring data until June 2013.
- Annual Fine Particulate Matter (PM2.5): U.S. EPA is threatening in proposed rulemaking to tighten the annual PM2.5 NAAQS from 15 micrograms per cubic meter (µg/m3) to 11 to 13 µg/m3. It is already very difficult to demonstrate modeled compliance with the annual NAAQS under the Prevention of Significant Deterioration (PSD) modeling process for major permitting projects. A tightened standard would make it even more difficult and is very likely to rapidly expand the list of PM2.5 nonattainment areas since the proposed 11 to 13 microgram per cubic meter range is already being measured as a background concentration at many of the existing ambient monitors. A possible secondary PM2.5 NAAQS that is visibility oriented is also lurking out there. Regardless of the outcome of this process, facilities will continue to need to find internal reductions to offset PM2.5 emissions increases so that major source and modification permitting requirements can be avoided for PM2.5.
- 8-Hour Ozone: The reconsideration of the 8-hour ozone NAAQS (a range of 65 to 75 µg/m3 was considered) that was destined to increase the number of ozone nonattainment areas was dropped by presidential order. However, don’t lose sight of the ozone NAAQS. The next reconsideration is scheduled for 2013, so the process of evaluating more stringent ozone standards and the nonattainment area permitting implications of a tightened ozone standard will happen again.
On a bigger picture note, legal challenges to the 1-hour SO2 and NO2 NAAQS levels were recently rejected, so the NAAQS levels are here to stay for the foreseeable future. These recent court cases show that health-based standards, once established, will be difficult or even impossible to scale back (although there is still hope that the implementation process for those standards can be adjusted). Given the permanence of the NAAQS levels, they will continue to be one of the primary areas that dictate a facility’s ability to operate and expand in the future. We will continue to keep track of the latest developments around the NAAQS levels, so stay tuned for updates as they arise.
U.S. EPA Proposed NSPS Revisions – Stationary Gas Turbines and Stationary Combustion Turbines
In the August 29, 2012 Federal Register, U.S. EPA published a proposal to amend various portions of the New Source Performance Standards (NSPS) for Stationary Gas Turbines (40 CFR Part 60 Subpart GG) and Stationary Combustion Turbines (40 CFR Part 60 Subpart KKKK). The proposed amendments to specific sections of these regulations are intended to resolve issues related to a September 5, 2006 petition for reconsideration filed by the Utility Air Regulatory Group (UARG). U.S. EPA states that the proposed amendments would increase the environmental benefits of the existing requirements because the emission standards would apply at all times and would promote efficiency by recognizing the environmental benefit of combined heat and power (CHP) and the beneficial use of low energy content gases.
U.S. EPA is proposing to amend the applicability criteria such that only the combustion turbine engine will be considered when determining if a stationary turbine is a new or reconstructed turbine. The theory here is that this approach reflects the environmental benefits of heat recovery and output-based standards, which was the intention of the original rule. The proposed revisions also make it clear that the replacement of a turbine engine at a CHP or combined cycle facility that is not currently subject to Subpart KKKK would result in a “new” turbine that would now be subject to the rule.
A second proposed change is an exemption from the Subpart KKKK sulfur dioxide (SO2) standards for turbine owners that meet the SO2 provisions of 40 CFR Subparts J or Ja (petroleum refineries.) Under this proposal, an exemption from the Subpart KKKK SO2 standards would also be provided to turbine owners that have a federally-enforceable gaseous fuel sulfur limit of no more than 20 grains of sulfur per 100 standard cubic feet or a liquid fuel limit of no more than 0.050 percent sulfur (500 ppm) by weight.
The proposed rule changes would also allow turbine owners who are currently subject to Subpart GG to petition U.S. EPA to comply with Subpart KKKK in lieu of complying with Subpart GG and any associated steam generating unit NSPS. The final portion of the proposed changes to these rules centers on U.S. EPA’s requests for comments relative to situations when turbines are overhauled or refurbished offsite, resulting in the inability to perform a reconstruction analysis. Such an analysis is necessary to determine whether the cost of the new components exceeds 50 percent of the fixed capital cost of a new facility (i.e., meets the definition of a “reconstructed” facility). Essentially, U.S. EPA proposed to define overhauls or turbine refurbishments where the combustor itself is replaced as reconstructed, if the owner is otherwise not able to perform a reconstruction analysis.
The proposal also includes changes to the nitrogen oxides (NOX) standard for turbines that burn multiple fuels by basing the standard on the type of fuel being burned in the turbine engine. The existing rule considers the total heat input to the turbine, including associated duct burners. NOX emissions would apply during periods of startup and shutdown, with an affirmative defense for malfunction periods. For SO2, the proposed changes include clarifying that a source using a fuel analysis to demonstrate compliance must include all sulfur compounds. Sources would be allowed to use fuel blending to achieve the SO2 standard as long as the average fuel fired meets the standard at all times. U.S. EPA is also proposing to expand the existing 0.15 lb SO2/MMBtu heat input emission standard to include turbines that combust 50 percent or more of any gaseous fuels that have heating values less than 750 Btu/ft3 (e.g., blast furnace gas, coke oven gas, coal bed methane, and landfill gas). Like the proposed NOX emission standards, the proposed SO2 standards would also apply during periods of startup and shutdown.
U.S EPA is requiring comments on these proposed rule changes to be submitted on or before October 29, 2012.
Recent Non-Hazardous Secondary Material (NHSM) Determinations
There has been a lull in U.S. EPA’s issuance of the “comfort” letters requested by the regulated community for non-hazardous secondary materials (NHSM) legitimacy determinations. However, the lull was recently broken, first by the North Carolina Department of Environment and Natural Resources (NCDENR) in early July and then most recently by U.S. EPA in late August. There are a couple of interesting items involving each of these two notices.
With respect to the NCDENR comfort letter, there is a little back story that is of interest, and those facilities that currently use landfill gases and other “uncontained gases” may want to follow this narrative closely. In early spring of this year, NCDENR requested that U.S. EPA confirm that a company proposing to install a generator to burn landfill gas purchased from a landfill would not be considered a new source under the Commercial Industrial Solid Waste Incinerator (CISWI) rules. NCDENR felt obligated to make this request because U.S. EPA had distanced itself from their long established determination that “uncontained gases” (i.e., gases that travel through a pipe) are not solid wastes and are not subject to the CISWI rule. See U.S. EPA’s April 2011 correspondence to the American Forest and Paper Association (AF&PA) and the proposed December 2011 NHSM revisions for examples of U.S. EPA’s last public support of its long established position that “uncontained gases” are not solid wastes. Operating within the vacuum generated by U.S. EPA, NCDENR and the regulated source went through the NHSM legitimacy determination process to confirm that the landfill gas is not a solid waste. Since there are many industrial sectors that combust “uncontained gases,” such as the pulp and paper and refining industries, the NCDENR action has significant meaning. It should be noted that NCDENR was able to make the NHSM determination because the state is delegated to implement the CISWI rule. Also, although NCDENR used the legitimacy criteria process to determine that the landfill gases are a NHSM, this determination is in lieu of the preferred finding that uncontained gases (i.e., pipeline gases) are not wastes, a situation akin to the proverbial “kissing your sister/brother.”
In an unrelated action, a comfort letter was issued by U.S. EPA in August regarding an alternate fuel that is comprised of comingled municipal solid waste, commercial waste, and institutional waste. What is important to note in this letter is the timing and effort that is associated with preparing the comfort letters and the actual legitimacy criteria demonstration. The timing for U.S. EPA comment and “approval” was approximately six months and required multiple information submittals (at least five information exchanges) and several meetings. There was also legal support throughout the process. In addition to the effort involving the management of the legitimacy criteria demonstration, there would have also been engineering support and analytical costs associated with developing the supporting documentation. ALL4 estimates that a legitimacy criteria demonstration could have easily cost $10,000 to $15,000 depending on how complicated the various fuel components made the process. The addition of analytical lab expenses could easily add $500 per sample to the aforementioned costs. The time and effort to prepare, support, and negotiate a legitimacy criteria demonstration should not be underestimated.
There are several resources that you can contact here at ALL4 to help you with aspects of the NHSM rule or aspects of the Boiler MACT and CISWI rules; please contact Ron Harding, Lindsey Kroos, or Dan Holland for more guidance.
More Greenhouse Gas Reporting Rule Revisions
On August 24, 2012 in Federal Register Vol.77, No 165, U.S. EPA announced the finalization of amendments to specific provisions of the Greenhouse Gas Reporting Rule. The amendments are intended to provide greater clarity and flexibility to facilities subject to reporting of greenhouse gas (GHG) emissions from the industrial waste landfill, petroleum and natural gas systems, fluorinated gas production, and electronics manufacturing source categories. These amendments come at a time when reporting facilities in these categories are preparing to submit their first annual data by September 28, 2012. However, U.S. EPA does not expect this to cause any problems for reporting facilities since the amendments do not significantly change the overall calculation and monitoring requirements or add additional requirements. In this same action, U.S. EPA also finalized confidentiality determinations for four (4) new data elements for the fluorinated gas production source category and amendments to defer the reporting deadline of an input to an emission equation utilized by this source category until 2015.
Published by U.S EPA on October 30, 2009, the Mandatory Greenhouse Gas Reporting Rule, which is codified in 40 CFR Part 98 (Part 98), mandates U.S. EPA’s collection of GHG data and other relevant information from large sources and suppliers in the United States for use in informing future policy decisions. This action finalizes amendments to provisions in the following Subparts of Part 98: A (General Provision), TT (Industrial Waste Landfills), W (Petroleum and Natural Gas Systems), and L (Fluorinated Gas Production).
The amendment to Subpart A is intended to bring the Subpart into accord with a technical correction previously finalized in February 2012 for Subpart I (Electronics Manufacturing) which required reports to calculate emissions of certain additional fluorinated heat transfer fluids. Amendments to Subpart TT add another method that sources can use to show that the material placed in a landfill is inert and thus exclude their facility from the reporting requirements. The method involves the direct determination of waste-specific degradable organic carbon (DOC) via an anaerobic biodegradation test. The landfill is excluded from reporting requirements when a waste is determined to have a DOC value of 0.3 weight % (wet basis) or less. The U.S. EPA rationalizes these changes on the basis that the excluded facilities are not expected to emit GHGs since they receive only inert wastes that do not generate methane. Unfortunately, the timing of this amendment may not help all facilities eligible for the exclusion because the 2011 reporting deadline comes only 35 days after the notice of the amendment, and the anaerobic biodegradation test takes at least 60 days.
The amendments to Subpart W consist mostly of technical corrections and clarifications which are not expected to affect the methods and actions facilities must take in order to comply with the rule (e.g., corrections to emission factors in Table W-1A for the onshore petroleum and natural gas production segment). In the case of Subpart L, the amendments are temporary to defer detailed reporting of GHG emissions from fluorinated gas production facilities until 2014 in order to allow U.S. EPA time to fully evaluate concerns about confidentiality raised by stakeholders. Facilities subject to Subpart L will continue to report GHG emissions in a more aggregated manner in 2012 and 2013. Finally, the amendments finalize confidentiality determinations for the four new Subpart L data elements added in this rule.
