olivia lucas, faegre baker daniels, john iwanski, trinity consultants, crash course in nsr/psd...
TRANSCRIPT
Crash Course in NSR/PSD
Permitting
Midwest Environmental Compliance Conference Chicago, Illinois ♦ October 29, 2015
Olivia Lucas, Faegre Baker Daniels
John P. Iwanski, Trinity Consultants
Introductions
Olivia Lucas, Esq., Counsel
˃ Environmental regulatory attorney focusing on air
permitting, compliance, enforcement and rulemaking.
˃ Legal strategy for complex permitting matters under
NSR PSD and Title V programs.
˃ Represents clients in enforcement actions before state
and federal agencies; robust Region 5 practice.
Introductions
John P. Iwanski, Managing Director
˃ B.S., Meteorology (Penn State)
Engineer/Scientist as Manager Certification (Penn State)
˃ 25+ years consulting experience
˃ Conducts project management and senior technical
consulting for projects ranging from Prevention of Significant
Deterioration (PSD), Nonattainment New Source Review
(NSR), and Title V permits to compliance audits and
regulatory reviews
˃ Directs Trinity’s operations across northern and western U.S.
Session Agenda
˃ Gain understanding of NSR Permitting Program and Process Understanding Applicability
♦ Source definition
♦ What is a Project?
♦ Emission triggers
Avoiding NSR/PSD ♦ Taking limits
♦ Netting
♦ Concerns
NSR Example
The PSD Permitting Process ♦ PSD application elements
Once the permit is issued
Session Goals
˃ Review key concepts, strategies, and
common pitfalls
˃ Understand the respective roles of USEPA
and States
˃ Provide tips for managing public
engagement
˃ Note: will not cover Nonattainment NSR
PSD Program Goals (USEPA’s NSR Workshop Manual)
˃ To ensure that economic growth will occur in harmony
with the preservation of existing clean air resources
˃ To preserve, protect, and enhance the air quality in
areas of special natural recreational, scenic, or historic
value, such as national parks and wildlife areas
˃ To protect the public health and welfare from any
adverse effect which might occur even at air pollution
levels better than the National Ambient Air Quality
Standards (NAAQS)
PSD Program Goals - Metrics
˃ Allow economic growth to occur while limiting
air quality degradation to “PSD Increments”
PSD Increments: Maximum increases in ambient
pollutant concentrations allowed over baseline
concentrations
Baseline concentrations are defined for each
pollutant and averaging period
Achieving Goals of PSD Program
˃ A source should install modern pollution controls… when it is built (new source)
when it makes a major modification (existing source)
˃ A source shall demonstrate no adverse impacts on air quality prior to construction Compliance with NAAQS
Compliance with PSD Increments
No adverse impacts on soils, vegetation, visibility, Class I Areas
Applicability - Overview
Applicability determined by:
˃ Definition of source
˃ Scope of the project
New source
Modification
Exemptions
˃ Emissions
PSD Applicability Basics (1/2)
˃ PSD permitting requirements are triggered by
an event
Construction of a new major source
Major expansion of an existing major source
Physical or operational change at an existing major
source (i.e. a “project”)
˃ PSD applicability is evaluated on a pollutant-by-
pollutant basis
PSD Applicability Basics (2/2)
˃ New Sources
PSD is triggered (for a certain pollutant) when
potential to emit (PTE) from new source exceed
thresholds that define a major source under the
PSD program
˃ Existing Major Sources
PSD is triggered (for a certain pollutant) when net
emission increases exceed thresholds that define a
major modification
Source Definition
˃ Source: All of the pollutant-emitting activities which: belong to the same SIC major group
(or “support activity”), and
are located on one or more contiguous or adjacent properties, and
are under common control
˃ Federal Regulations: 40 C.F.R. 51.166 (PSD) 40 CFR 70.2 (Title V)
˃ States often adopt federal definition of “source”
˃ Different criteria for different regulatory programs State SIP Permitting
Federal NSR Permitting (New Source Review)
Title V Program (similar to NSR)
Title I - NESHAP
˃ State guidance – some states have forms for assessing applicability
Source Definition – Contiguous or
Adjacent (1/2)
Are located on one or more contiguous or
adjacent properties
˃ Longstanding controversy
Can “adjacent or contiguous” contain an element
of functional interrelatedness?
Summit Petroleum decision; aftermath
˃ Recent examples
Source Definition - Contiguous or
Adjacent (2/2)
˃ 1980 PSD rules – no bright line statement
about how far apart “adjacent” sources
could be
˃ 1990’s – no change in rules, but guidance
began giving greater weight to functional
interrelatedness of operations over
physical proximity
Adjacency – Location or
Interrelatedness?
˃ Oil and gas industry a crucible
2007 Wehrum memo focused on oil & gas
proximity over interrelatedness
2009 McCarthy withdrew Wehrum memo,
moved policy towards functional
interrelatedness as a factor in adjacency
Contiguous or Adjacent: Summit
Petroleum v. EPA, 690 F.3d 733 (6th Cir. 2012) ˃ Facts:
Summit is natural gas processor in Michigan that owns a sweetening plant that is not of itself a major source
Sweetens gas from approximately 100 wells located over 43 square miles, from 500 feet to 8 miles away from the plant.
Received USEPA determination that sweetening plant and wells should be aggregated because of adjacency based in interdependent nature of activities
Summit challenged use of interrelatedness in adjacency determination
Summit Petroleum Case (1/2)
˃ USEPA’s rationale in Summit case: No bright line rule for how close sources had to be to
qualify as adjacent.
In recent history, factors such as the “nature of the relationship between the facilities” and the “degree of interdependence between them” had been important to the question of whether two facilities were adjacent.
Summit’s plant, wells, and flares worked together as a single unit that “together produced a single product” and Summit did not provide any evidence that the emissions sources were not “truly interdependent.”
Given this functional interrelationship, Summit’s facilities “should not be considered separate emission sources.”
Summit Petroleum Case (2/2)
˃ Sixth Circuit holding overruled USEPA:
Adjacency cannot be based on anything
other than geographical proximity
The plain meaning of adjacent is
unambiguous and requires proximity
USEPA’s functional interrelatedness test was
unreasonable; and
USEPA’s own regulatory history does not
support the use of relatedness test
Summit Directive
˃ After Summit decision, Dec. 21, 2012 USEPA
memo stating that the opinion would apply only
in the 6th circuit (Michigan, Ohio, Tennessee and
Kentucky)
Outside of 6th Circuit, USEPA will continue to
include interrelatedness when determining
aggregation/adjacency
Different application for subsections of different
USEPA regions (Regions IV and V)
Challenge to Summit Directive
˃ National Environmental Development
Association challenged Summit Directive in D.C.
Cir. Nat’l Environmental Development
Association’s Clean Air Project v. EPA, No. 13-
1035 (D.C. Cir. 2013)
˃ In 2014, Court vacated Summit Directive as
contrary to USEPA regulations requiring national
uniformity in implementing CAA
Current State of “Contiguous or
Adjacent” - USEPA Proposed
Rulemaking
˃ Proposed rule for source determinations in the oil
and gas sector (80 FR 56579 )(Sept. 18, 2015)
Comments due Nov. 17
˃ USEPA proposes and seeks comment on two
approaches: (1) source consists of activities at
surface site and other “adjacent” emitting
activities if they are proximate; (2) source is all
interrelated equipment under common control and
proximate or exclusively functionally interrelated
Recent “Source” Decision
“So, I met with Agency today. Here are some highlights from the meeting: ˃ Agency: If a railroad is going through a stationary source,
you now have two stationary sources.
˃ Agency has a handshake agreement with USEPA that allows agency to define a stationary source as only buildings that are truly adjacent.
None of this is writing, but generally accepted. Therefore, in our situation, we have two stationary sources even if one customer is requesting Company to build the three nearby buildings….and the customer would not build one building without the other two.”
Source Definition – Common
Control
˃ Common control
ownership (i.e., same parent company or a
subsidiary of the parent company)
Decision-making authority via contractual
agreement or voting interest
If common control not established by other two
methods, look at contracts for service or a
support/dependency relationship
˃ Support facility examples
What Triggers PSD at a Source?
˃ §52.21 Prevention of significant deterioration
of air quality
(2) Applicability procedures
♦ (i) The requirements of this section apply to the
construction of any new major stationary source (as defined
in paragraph (b)(1) of this section) or any project at an
existing major stationary source in an area designated as
attainment or unclassifiable under sections 107(d)(1)(A)(ii)
or (iii) of the Act
And What Is a Project?
˃ 40 CFR 52.21(b)(52) Project means a
physical change in, or change in the method
of operation of, an existing major stationary
source
“The clear intent of the PSD regulations is to define
the term "physical change" very broadly, to cover
virtually any significant alteration to an existing
plant.” (USEPA Region V to IDEM, January 26, 2001)
“Source Classification”
˃ Permitting procedures often depend on “source
classification”
Major
Synthetic Minor
True Minor
˃ Different emission thresholds for
different regulatory programs
Source classification depends on “Potential
to Emit”
What is a Major Source?
˃ Source’s potential to emit (PTE) exceeds
major source thresholds
PTE is the maximum capacity to emit
˃ Source can not or chooses not to propose
enforceable limits on emissions and/or
operations to reduce its PTE
“Major Source” Thresholds Under
PSD
˃ Two thresholds depending on whether in one of 28
named source categories (these are “hard coded”
in the Clean Air Act) – see attachment
On “List of 28” : Major Source if PTE > 100 tpy for at
least one regulated pollutant
NOT on “List of 28” : Major Source if PTE > 250 tpy for at
least one regulated pollutant
“Listed” sources (40CFR52.21(b)(1)(i)(c)(iii)) must
include fugitive emissions in determining PTE
˃ PSD addresses “regulated” pollutants and those
“subject to regulation”
PSD Regulated Pollutants* (1/2)
˃ CO, NOX, SO2, PM10, PM2.5
˃ TSP
˃ VOC (called VOM in IL)
˃ Lead
˃ Hydrogen sulfide (H2S)
˃ Total reduced sulfur (including H2S)
˃ Reduced sulfur compounds (including H2S)
˃ Sulfuric Acid Mist
* Specifically excludes pollutants regulated under Title III of the 1990 CAAA
PSD Regulated Pollutants* (2/2)
˃ Fluorides (other than HF)
˃ CFCs (11, 12, 112, 114, 115)
˃ Halons
˃ Municipal waste combustor acid gases, metals, and
organics
˃ Municipal solid waste landfill emissions
˃ GHG – CO2, CH4, N2O, HFCs, PFCs, and SF6 – “subject to
regulation” scenarios
* Specifically excludes pollutants regulated under Title III of
the 1990 CAAA
Does PM2.5 Include Condensables?
˃ Condensables are that portion of the exhaust that passes through the filter in a Method 5 test, but that gets condensed and captured in the cooled sample train used in Method 202 (“back half catch”)
˃ October 25, 2012, (77 FR 65107) amendments to Parts 51 and 52 clarify the status of condensable particulate matter (CPM)
5/16/2008 PM2.5 implementation rule included language that created confusion over when to count CPM. It appeared to imply that CPM is part of PM.
Clarification:
♦ Count CPM as part of PM2.5 and PM10
♦ Do not count CPM as part of PM/TSP
Definition - Fugitive Emissions
“Those emissions which could not reasonably pass
through a stack, chimney, vent, or other
functionally equivalent opening.”
Examples: open coal pile, open product storage piles,
pumps, flanges, and valves, open process or storage
tanks, haul roads, open waste storage piles, open top
storage bins, open conveyors, WWT without enclosures or
cap (NOT ALL PERMITTING AUTHORITIES AGREE ON WHAT
CONSTITUTES FUGITIVE EMISSIONS)
Definition - Fugitive Emissions
˃ The preamble to the USEPA's 1980 promulgation of the definition for "fugitive emissions" states (45FR 52692-93):
“EPA has considered comments with respect to the proposed definition of "fugitive emissions," and has determined that one change is appropriate. Instead of defining fugitive emissions as "those emissions which do not pass through a stack, chimney, vent, or other functionally equivalent opening," EPA believes that the term should apply to "those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening." This change will ensure that sources will not discharge as fugitive emissions those emissions which would ordinarily be collected and discharged through stacks or other functionally equivalent openings, and will eliminate disincentives for the construction of ductwork and stacks for the collection of emissions. Emissions which could reasonably pass through a stack, chimney, vent, or other functionally equivalent opening will be treated the same as all other point emissions for threshold calculation purposes.”
PSD Triggering Thresholds:
PSD Applies If…. ˃ New Sources: Plant will be a major source
(>major source threshold of 100 or 250 tons/year or 100,000
tons/year of GHG (CO2e) when “subject to regulation”) ˃ Existing Minor Sources: Make a modification that in
itself is “major” (>major source threshold of 100 or 250 tons/year or 100,000
tons/year of GHG (CO2e) when “subject to regulation”) ˃ Existing Major Sources: Make a modification that
exceeds de minimis levels (also called PSD Significant Emission Rates); a “major modification” Existing major sources may “net-out” of PSD review
Major Modification (under PSD)
ANY physical change in or change in the method of operation of a major stationary source that would result in a significant net emissions increase.
(unless meet exemption criteria…)
PSD Significant Emissions* (40 CFR 52.21(b)(23)) Significant
Emissions
Pollutant (tons/year)
Carbon monoxide 100
Nitrogen oxides 40
Sulfur dioxide 40
PM10 15
PM2.5 10
VOCs 40
Lead 0.6
**GHG (CO2e basis) 75,000
**GHG (mass basis) 0
*Only criteria pollutants and GHG presented here
** The GHG thresholds are NOT defined at 40 CFR 52.21(b)(23) – “Subject to Regulation” Threshold Applies – USEPA may amend or “justify” these values in future rulemaking
Exemptions from PSD Review
˃ Certain activities excluded from PSD review 40 C.F.R. 52.21(b)(2)(iii):
Physical change or change in method of operation shall not include RMRR ♦ VERY limited universe of what is RMRR
Use of alternative fuel or raw material (several reasons)
Increase in hours of operation or production rate unless results in major increase
Change in ownership
Clean coal technology project
RMRR Exemption
˃ Does project qualify for routine maintenance, repair, replacement exemption?
Assess nature, extent, purpose, frequency, and cost of project
˃ Situations that probably DO NOT qualify for exemption Adding new equipment
Changing process design or control technologies
Life extension projects
Changes that affect capacity
Changes that enable production of alternate product
Relatively high cost projects
Changes that have never been performed previously
Aggregation
˃ Project must include all intended or planned emissions
˃ When should projects be aggregated? USEPA New Source Review: Recommendations (June
2002)
USEPA to clarify the policy as follows – projects should generally be considered separate unless:
♦ Project is dependent upon another project to be economically or technically viable
♦ Project is intentionally split into multiple projects to avoid NSR (sham permitting)
Defer to states for enforcement
Aggregation – Technically
Dependent
˃ Indicators of technical dependence, per USEPA
(proposed and final rule preambles):
A project cannot operate within its maximum design rate
for an extended period without the other project
A source cannot achieve its maximum production
without implementation of both or multiple projects
When a project is needed to make a new product,
absence of another project does not allow for full
production of the new product
See USEPA’s examples in final rule – 74FR pages 2378 and
2379
Aggregation – Economically
Dependent
˃ Simply stated, the return on investment (ROI)
associated with a project could not be realized
without completion of another project(s)
˃ USEPA not suggesting that all projects and
activities at a plant are related
˃ And economic dependence is not as
straightforward as technical dependence
˃ See USEPA’s examples in the preamble of the
proposal (71FR - pages 54246 and 54247) – not
really addressed in final rule
Aggregation
˃ Requirement to avoid sham permitting
Sham permit intended to circumvent PSD by taking unrealistic limits,
Sham permitting also identified by series of minor modifications close in time – may be presumed separate projects if three years apart
BUT time not definitive
˃ Examples
Stephen Page (USEPA OAQPS) to Semiconductor Industry Association, August 26, 2011
Kate Kelly (USEPA Region X) to Simplot, August 29, 2013
Calculating Project Emissions
Increases (PEI) (1/2)
˃ Project Emissions New equipment (emission/process units)
Modified equipment or “changed” processes
Other “associated” emissions
˃ Does not include “secondary” emissions (emissions which occur as a result of the construction or operation of a stationary source, but do not come from the stationary source itself)
˃ Emissions netting discussed later
Calculating Project Emissions
Increases (PEI) (2/2)
˃ For existing units, actual-to-projected actual test – uses the difference between projected actual emissions (definition at 40 CFR 52.21(b)(41)) and baseline actual emissions (definition at 40 CFR 52.21(b)(48))
˃ For new units – actual-to-potential test (actual emissions equal zero)
“Baseline Actual Emissions” (1/6)
“Rate of emissions, in tons per year, of a regulated NSR pollutant”
Existing EUSGU: Average rate the unit actually emitted during any consecutive 24-month period, within a 5-year period, immediately preceding actual construction of the project. Administrator can allow alternative periods.
“Baseline Actual Emissions” (2/6)
“Rate of emissions, in tons per year, of regulated NSR pollutant” Existing non-EUSGU: Average rate the unit actually
emitted during any consecutive 24-month period, within a 10-year period, immediately preceding actual construction of the project or the date an application is received, whichever is earlier.
No allowance for alternative periods for non-EUSGUs
“Baseline Actual Emissions” (3/6)
Includes average fugitive emissions, to the extent quantifiable, in selected 24-month period
Includes average emissions associated with startups, shutdowns and malfunctions, in selected 24-month period
If, during the 24-month period, unit did not meet an enforceable limit in effect at that time, average emissions in selected 24-month period get adjusted downward to exclude these non-compliant emissions
“Baseline Actual Emissions” (4/6)
˃ For non-EUSGU’s, average rate selected gets
adjusted downward to exclude any emissions
that would have exceeded an emission or limit
or operating restriction which the source must
NOW comply with:
A raw material/fuel previously used is now
prohibited
A subsequent allowable emission rate change
“Baseline Actual Emissions” (5/6)
˃ However, if the subsequent limit is part
of a proposed or promulgated MACT
standard, adjust baseline actual
emissions downward only if the State has
taken credit for the MACT reductions in
an attainment demonstration or
maintenance plan
“Baseline Actual Emissions” (6/6)
˃ If the project at hand involved multiple existing emission units, only one consecutive 24-month period is used to determine the baseline actual emissions for all emission units impacted by the project
˃ Can use different consecutive 24-month periods for each regulated NSR pollutant impacted by the project
˃ Can’t use 24-month periods with “inadequate information”
Year VOC
Emissions
2003 75 tpy
2004 85 tpy
2005 95 tpy
2006 80 tpy
2007 60 tpy
2008 50 tpy
2009 50 tpy
2010 40 tpy
2011 25 tpy
2012 35 tpy
Pre-NSR Reform Rule: Past actual
emissions (two-year period preceding the
change) = 30 tpy
Baseline Actual Emissions (1/3)
EXAMPLE #1 – Project proposed in 2013
Past actual emissions (company can select
24-month period within 10 year period
preceding the change)
= 90 tpy
Year VOC
Emissions
2003 750 tpy
2004 850 tpy
2005 950 tpy
2006 800 tpy
2007 60 tpy
2008 50 tpy
2009 50 tpy
2010 40 tpy
2011 25 tpy
2012 35 tpy
Pre-NSR Reform Rule: Past actual
emissions (two-year period preceding
the change) = 30 tpy
Baseline Actual Emissions (2/3)
EXAMPLE #2 – Project proposed in 2013
Baseline actual emissions of 900 tpy not
available for use since allowable emission
rate was subsequently reduced.
New controls require 90% destruction
efficiency, meaning baseline actual
emissions are only 10% of the highest
uncontrolled emission rate in previous 10
year period, or 90 tpy
Year SO2
Emissions
2008 150 tpy
2009 165 tpy
2010 175 tpy
2011 150 tpy
2012 145 tpy
Baseline Actual Emissions (3/3)
EXAMPLE # 3 (EUSGU) – Project proposed
in 2013
Past actual emissions = 170 tpy; though
alternative period can be allowed by
Administrator if shown to be more
representative of normal source operation
New Versus Existing Units
˃ "Emissions unit" means any part of a stationary source that emits or would have the potential to emit any regulated NSR pollutant and includes an EUSGU. There are two types of emissions units as described in paragraphs (A) and (B) below:
(A) A new emissions unit is any emissions unit that is (or will be) newly constructed and that has existed for less than 2 years from the date such emissions unit first operated
(B) An existing emissions unit is any emissions unit that does not meet the requirements in paragraph (A) of this definition. A replacement unit is an existing emissions unit
˃ Interesting sidelight – units that have not been operating (USEPA’s reactivation policy)
Replacement Unit (40 CFR 52.21(b)(33))
˃ A “replacement” unit is considered an existing unit under these conditions The unit is a reconstructed unit within the meaning of 40 CFR
60.15(b)(1), or the facility replaces an existing facility
The unit is identical to or functionally equivalent to the replaced facility
The replacement does not alter the basic design parameters of the process unit
The replaced unit is permanently removed from the major source, otherwise permanently disabled, or permanently barred from operation by a permit that is enforceable
˃ If the replaced unit is brought back into operation, the unit will be considered to be a new unit
˃ No creditable emission reductions are generated from shutting down the existing unit that is replaced
˃ If the proposed project includes a replacement unit, the baseline emissions of the unit being replaced must be determined
Projected Actual Emissions
˃ Future side of equation
˃ “the maximum annual rate, in tons per year, at which an existing emissions unit is projected to emit a regulated NSR pollutant…” [40 CFR 52.21(b)(40)(i)] Next 10 years if the project involves increasing the
emission unit’s design capacity or its potential-to-emit of that regulated NSR pollutant and full utilization of the unit would result in a significant emissions increase or a significant net emissions increase at the major stationary source
Next 5 years otherwise
Projected Actual Emissions – Calculation (1/2)
˃ In determining projected actual emissions, the owner or operator… Shall consider all relevant information, including but not
limited to, historical operational data, the company’s own representations, the company’s expected business activity and the company’s highest projections of business activity, the company’s filings with the State or Federal regulatory authorities, and compliance plans under the approved plan; and
Shall include fugitive emissions to the extent quantifiable and emissions associated with startups, shutdowns, and malfunctions
[40 CFR 52.21(b)(40)(ii)(a) and (b)]
Projected Actual Emissions – Calculation (2/2)
˃ Preamble to 12/31/2002 rule (67 FR 80196):
˃ “Accordingly, you will calculate the unit’s projected actual emissions as the product of:
(1) The hourly emission rate, which is based on the emission units operational capabilities following the change(s), taking into account legally enforceable restrictions that could affect the hourly emissions rate following the change, and
(2) the projected level of utilization, which is based on both the emissions unit’s historical annual utilization rate and available information regarding the emission unit’s likely post-change capacity utilization
…you should consider both the expected and the highest projections of the business activity that you expect could be achieved and that are consistent with information your company publishes for business-related purposes…”
˃ Projected Actual Emissions = Hourly Rate x Projected Utilization
Option to Use PTE
˃ Projected actual emissions can be set
equal to the emission units potential-to-
emit
˃ Dilemma – How to address start-up, shut-
down, and malfunction (upset) emissions
in baseline and projected emissions?
Year* VOC Actual
Emissions
2010 55 tpy
2011 65 tpy
2012 85 tpy (projected)
2013 85 tpy (projected)
2014 90 tpy (projected)
2015 90 tpy (projected)
2016 95 tpy (projected)
Following a project, source resumes normal operation in
2012. Source first commenced operation in 2010 as a
major source.
Potential-to-Emit of Source:
350 tpy
Actual-to-Projected-Actual
Applicability Example
Year* VOC Actual
Emissions
2010 55 tpy
2011 65 tpy
2012 85 tpy (projected)
2013 85 tpy (projected)
2014 90 tpy (projected)
2015 90 tpy (projected)
2016 95 tpy (projected)
Potential-to-Emit:
350 tpy
Net Increase = 290 tpy
SUBJECT TO PSD
For actual emissions, use most recent two-year period.
Since modified unit has “not begun normal operations,
actual emissions are set equal to the potential-to-emit.
Pre-Reform: Actual-to-Potential
Applicability
Year* VOC Actual
Emissions
2010 55 tpy
2011 65 tpy
2012 85 tpy (projected)
2013 85 tpy (projected)
2014 90 tpy (projected)
2015 90 tpy (projected)
2016 95 tpy (projected)
Future Potential Emissions:
350 tpy
New Rule
Baseline actual emissions = 60 tpy
Projected actual emissions = 95 tpy
Emissions increase (PEI) = 35 tpy
MINOR MODIFICATION, not subject to
PSD
Final Rule: Actual-to-Projected -
Actual Applicability Test
“Demand Growth” Exclusion
˃ Actually part of the “projected actual emissions” definition [40 CFR 52.21(b)(40)(ii)(c)]
˃ “Shall exclude…that portion of the unit’s emissions following the project that an existing unit Could have accommodated during the consecutive 24-month
period used to establish the baseline actual emissions …; and
that are also unrelated to the particular project, including increased utilization due to product demand growth”
˃ Often referred to as the “demand growth exclusion” but regulatory language is not specific to demand growth
˃ Potential to avoid PSD by limiting emission increase calculation just to the effect of the project itself
Demand Growth Exclusion “Could have accommodated”
˃ Be careful not to overestimate the capacity that the emission unit was capable of accommodating Averaging period is annual
♦ Could unit have sustained operation at that capacity for a full year?
♦ Did you adjust downward to account for required maintenance
Think more broadly than just one emission unit ♦ For a change to the boiler, can the plant actually handle the
additional steam production?
♦ Can it handle that steam year-round?
Demand Growth Exclusion “Unrelated to the particular project”
˃ Not so simple as it looks
Prior to the project, how accurate are engineering
estimates of what increases the project will
accomplish?
How will source be able to demonstrate that an
increase in production is not the result of the
project?
˃ Relative void of USEPA guidance for interpreting
this language is troubling
Demand Growth Exclusion (1/3)
˃ 67FR 80203 describes the exclusion
˃ “…even if the operation of an emissions unit to meet a
particular level of demand could have been
accomplished during the baseline period, but the
increase is related to the changes made at the unit,
then the emissions increases resulting from the
increased operation must be attributed to the project,
and cannot be subtracted from the projection of the
projected actual emissions.”
Demand Growth Exclusion (2/3)
˃ Increase utilization that follows increases in reliability, lower
operating costs or improving other operational
characteristics should be attributable to the change
˃ Any change that significantly alters the efficiency of a
facility must be included in the projected emissions
˃ If efficiency improvements are the predominant cause of the
emissions increase, then the exclusion does not apply
˃ The bottom-line: Although an emissions unit could have
theoretically increased emissions without the project, other
factors must be considered before these projected emissions
are excluded
Demand Growth Exclusion (3/3)
˃ Situations where external market drivers might
provide evidence that the exclusion is
legitimate
Skyrocketing demand because a product becomes a
fad
Mishaps at a factory, causing production increases
elsewhere
Opening of new markets
Significant decrease in raw material prices
Demand Growth - “Could have
been accommodated” ˃ USEPA Region III letter – April 20, 2010
“…a facility is permitted to burn coal with a sulfur content up to two percent but actually burns coal with one percent sulfur during the baseline period. The company bases the projected actual emissions on continuing to burn one percent sulfur coal. Emissions that can be excluded would be limited to emissions associated with burning one percent coal, regardless of the limit that would allow them to burn a higher sulfur coal.”
“In other words, the emissions that "could have been accommodated" are not defined by all the many different operating conditions that could have occurred during the baseline period; rather emissions that may be excluded are limited by the proposed operating conditions used to project emissions into the future.”
www.epa.gov/Region7/air/nsr/nsrmemos/psdanalysis.pdf
Treatment of “Associated”
Emissions
˃ Emissions which occur as a result of construction or modification activities and come from the source itself. For example: increased emissions from an existing cement kiln
associated with a raw feed mill expansion (“debottlenecking”)
increased emissions from existing boilers associated with a new distillation column (an increase in boiler “utilization”)
Projects that Debottleneck
˃ A unit that limits the capacity of a process is termed a “bottleneck”
˃ Removal of a bottleneck “increases the capacity” of the source, affecting upstream and downstream units
˃ Increased emissions associated with the debottlenecking must be considered
Reasonable Possibility
Recordkeeping Rule (40 CFR 52.21(r)(6))
˃ Specifies circumstances in which source undergoing a
modification, that does not trigger PSD (major NSR),
must keep records
˃ If projected actual emission increases (PEI) ≥ 50% of
PSD significant emission rate (SER) after “demand
growth” emissions are excluded from the increase
Pre-construction records – project description, units affected
by project, emission increase analysis
Post-construction records – of actual emissions for 10 yrs if a
capacity increase; for 5 yrs otherwise
Submit a report to the regulators if the actual emissions
increase exceeds 100% of the SER (after “demand growth”
emissions are excluded from the increase)
Reasonable Possibility
Recordkeeping Rule
˃ If projected actual emission increases (PEI)
would be ≥ 50% of PSD SER but < 50% of NSR SER
if the “demand growth” emissions are excluded
Pre-construction records only – project description,
units affected by project, emission increase
analysis
˃ EGUs have more stringent reasonable possibility
recordkeeping (and reporting) obligations
GHG Permitting
˃ UARG v. EPA (U.S. Supreme Court, 2014) – GHG BACT required if PSD permitting required based on another criteria pollutant and GHG levels are met
˃ No more requirement for PSD permitting based solely on GHG
˃ USEPA July 24, 2014 memorandum: PSD for GHG when source is an “anyway” source and project has 75,000 tpy CO2e (new source) or increase and net increase greater than or equal to 75,000 tpy CO2e (modification)
PSD Key Requirements (or Why You Want to Try to Avoid PSD)
˃ You can NOT begin construction before a permit issued! ˃ Control Device Review (BACT) ˃ Air Quality Review
NAAQS analysis PSD increment analysis Air Toxics Review
˃ Preconstruction Monitoring Requirements ˃ Class I Areas ˃ Additional Impacts Analysis
Growth, Environmental Justice, etc. Visibility Soils, Vegetation, Animals
PSD Avoidance Permit Actions
˃ Restrictions proposed through permit application to synthetically limit project (or net) emission increases or facility potential
˃ Restrictions self defined Emission limits
Process limitations
Operating hour limits
Material content limits
PSD Avoidance Permit Actions -
Minor Source
˃ For existing minor sources, all PSD
applicability issues can be avoided as
long as synthetic minor status maintained
PSD Avoidance Permit Actions -
Major Sources
˃ Existing major PSD sources can synthetically limit project (or net) emission increases to less than PSD Significant Emission Rates Install technology necessary to limit emission
increases voluntarily
Take restrictions on raw materials and/or fuels
Ensure limitations are tied to specific equipment and not the entire plant or process
PSD Avoidance Permit Actions
˃ Permitting strategies can be very
complex
˃ PSD synthetic minor limits can only be
“relaxed” by going through PSD
permitting (40 CFR 52.21(r)(4))
Emissions Netting (1/2)
˃ If project emissions increases (PEI) are greater than
significance levels, can attempt to “net-out” of
PSD review
˃ Net emissions change (NEC) equals:
emission increases - proposed project/modification (PEI)
minus
source-wide creditable contemporaneous decreases (CCD)
plus
source-wide creditable contemporaneous increases (CCI)
Emissions Netting (2/2)
˃ Project emissions increases (PEI) can be further
evaluated as the sum of three components:
Modified unit(s) emissions increases (MUEI) - these
unit are being physically or operationally changed
Associated unit(s) emissions increases (AUEI) -
these units are not physically changed as part of
the project
New unit(s)
PEI = MUEI + AUEI + New Units
PSD Definitions - Contemporaneous
˃ The contemporaneous period is the
period ranging from 5 years before
construction commences on a particular
project to the time normal operation
commences for that change
PSD Definitions - Creditable (1/3)
˃ Contemporaneous emissions decreases associated with
a particular change are considered creditable if they
are federally enforceable (permitted) on and after the
date construction on the proposed modification
commences
˃ Generally, actual reductions must take place before the
date the emissions increase from any of the new or
modified emissions units occurs
PSD Definitions - Creditable (2/3)
˃ An increase or decrease in emissions is creditable (included in a project’s netting calculation) if it was NOT previously “relied on” in issuing an enforceable PSD permit for the source
˃ Generally, otherwise creditable increases and decreases in emissions are included in current netting calculations if not the result of a project that triggered PSD for that pollutant (even if “used” in a netting calculation for a past project)
˃ Generally, reductions due to installation of controls to comply with HAP rules (MACT, etc.) are creditable
PSD Definitions - Creditable (3/3)
˃ A decrease in actual emissions is creditable only to the
extent that it meets all the conditions below:
If the old level of actual emissions or the old level of
allowable emissions, whichever is lower, exceeds the new
level of actual emissions
If it is enforceable as a practical matter at and after the time
that actual construction on the particular change begins
If it has approximately the same qualitative significance for
public health and welfare as that attributed to the increase
from the particular change
Project Netting
˃ Two situations are often addressed
A project (such a production increase) involves multiple
emission units some (or all) will add additional pollution
controls resulting in emissions decreases despite production
increases
A project involves multiple emission units and at least one will
be shut-down.
˃ The main question is whether one can have a
“negative” increase in the STEP 1 (PEI) emission
increase calculation on a unit-by-unit basis? Answer:
No
Considerations in deciding
whether to avoid PSD
˃ PSD permitting is resource intensive
˃ Often, required controls are very expensive
˃ PSD permits receive heightened
reporting/scrutiny (?)
˃ BUT source needs headroom to operate without
constant compliance concerns
˃ “Relaxation” provisions triggering PSD – 40
C.F.R. 52.21(r)(4)
Basic PSD Applicability Example -
Part 1 (1/2)
˃ Case: Surface Coating Operation in an
attainment area
˃ Current PTE:
200 tpy VOC, 50 tpy NOx
˃ Project: Add a new surface coating line
to the plant
PTE of new line: 40 tpy VOC
˃ Is project subject to PSD?
Basic PSD Applicability Example -
Part 1 (2/2)
˃ What is the existing source status?
Is this source category on the list of 28?
What is the major source threshold?
˃ What is PSD triggering threshold in this
case?
Basic PSD Applicability Example -
Part 2 (1/2)
˃ Now PTE of source: 240 tpy VOC, 50 tpy
NOx
Actual emissions: 120 tpy VOC, 30 tpy NOx
˃ Project: Add a 3rd surface coating line
and dryer to the plant
PTE of new line: 80 tpy VOC
PTE of new dryer: 30 tpy NOx
˃ Is the project subject to PSD?
Basic PSD Applicability Example -
Part 2 (2/2)
˃ What is the existing source status now?
˃ After project complete, PTE of VOC will
be 320 tpy; for NOx 80 tpy How does this
affect applicability determination?
˃ What is the PSD triggering threshold in
this case?
Basic PSD Applicability Example -
Part 3 (1/2)
˃ Now PTE of source: 320 tpy VOC, 80 tpy NOx
Actual emissions: 180 tpy VOC; 45 tpy NOx
˃ Project: Add a new boiler
PTE of boiler: 50 tpy NOx
PTE of boiler: 5 tpy VOC
˃ Is the project subject to PSD?
Basic PSD Applicability Example -
Part 3 (2/2)
˃ What is existing source status now?
˃ Is the site “a major source of NOx”?
˃ What is the PSD triggering threshold in this
case?
˃ Any other “issues” that may arise in this
application process?
PSD Key Requirements
˃ Control Device Review (BACT)
˃ Air Quality Review NAAQS analysis
PSD increment analysis
Air Toxics Review
˃ Preconstruction Monitoring Requirements
˃ Class I Areas
˃ Additional Impacts Analysis Growth, Environmental Justice, etc.
Visibility
Soils, Vegetation, Animals
The PSD Permitting Process
˃ 10 elements that need to be addressed in the
PSD permit application
Applicability and affected emission units
Control technology requirements
Air quality analysis
Additional Impacts
State construction permitting/approval
requirements
Startup, shutdown (and malfunction) scenarios
1. PSD Permitting Process –
Explain PSD Applicability
˃ If source is a major source, PSD applicability
has to be addressed
Why project triggers
Why project does not trigger
˃ Typically this is a narrative discussion as part of
the regulatory applicability section of the
application
2. PSD Permitting Process –
Address All Emission Units
Impacted by the Project ˃ There is no de minimis threshold, or concept of “insignificant
activity” under PSD applicability
˃ Don’t forget about associated emissions changes that occur as a
result of the project (these emissions must be quantified)
˃ PSD rules have an allowance for temporary emissions, but it is very
narrow
˃ Some emission units impacted by a project may not be subject to
PSD control technology requirements (units that are not physically
modified)
3. PSD Permitting Process –
Best Available Control Technology
“...an emissions limitation...based on the
maximum degree of reduction for each
pollutant... which the [permitting authority]...on
a case-by-case basis, taking into account energy,
environmental, and economic
impacts...determines is achievable...”
40 CFR 52.21(b)(12)
BACT Defined
˃ BACT applies to each pollutant triggering PSD applicability
˃ BACT emission limits can not contribute to violation of NAAQS or PSD Increment
˃ BACT emission limits must be practically enforceable Averaging time consistent with test method
Method of compliance delineated in permit (testing, monitoring, recordkeeping, and reporting)
Assumptions of BACT analysis incorporated into limits and/or compliance methods
Design, equipment, or work practice standards may be used in lieu of emission limits if compliance with emission limits infeasible
Separate BACT determination – startup, shutdown scenarios
USEPA’s “Top Down” Approach
˃ Step 1 – Identify available control options
˃ Step 2 – Eliminate technically infeasible options
˃ Step 3 – Rank options by control effectiveness
˃ Step 4 – Evaluate most effective controls and
emission limits achievable
˃ Step 5 – Select BACT
4. PSD Permitting Process –
Modeling the Impact of the
Project
˃ Identify NSR regulated pollutants subject to PSD air quality review based on project emissions (overall PSD applicability for the project)
Significant Monitoring
Concentrations
Pollutant
Calendar Quarter
(µg/m3)
Annual
(µg/m3)
24-hour
(µg/m3)
8-hour
(µg/m3
)
3-hour
(µg/m3
)
1-hour
(µg/m3)
PM2.5 ----- ----- 0 ----- ----- -----
PM10 ----- ----- 10 ----- ----- -----
SO2 ----- ----- 13 ----- ----- -----
NO2 ----- 14 ----- ----- ----- -----
CO ----- ----- ----- 575 ----- -----
Lead 0.1 ----- ----- ----- ----- -----
Total Reduced Sulfur ----- ----- ----- ----- ----- 10
Reduced Sulfur ----- ----- ----- ----- ----- 10
Hydrogen Sulfide ----- ----- ----- ----- ----- 0.2
Fluorides ----- ----- ----- ----- ----- 0.25
Why Do Class I Areas Matter?
˃ Air Quality Related Value (AQRV) impacts analysis Definition of AQRV - A resource, as identified by the FLM for one or more
Federal areas, that may be adversely affected by a change in air quality. The resource may include visibility or a specific scenic, cultural, physical, biological, ecological, or recreational resource identified by the FLM for a particular area
˃ Requires Federal Land Manager (FLM) review and approval
˃ More stringent Class I increments if within 10 km - Increment modeling is typically not required if: The impact from the proposed project (or the “net emissions increase”)
is less than the PSD modeling significance levels
The location of the facility is more than 100 kilometers from the closest edge of the Class I area (however, facilities more than 100 kilometers from a Class I area have been scrutinized on a case-by-case basis)
˃ Best Available Retrofit Technology (BART) considerations
8. PSD Permitting Process -
Additional Impacts Analysis ˃ Required in all PSD applications
˃ The permitting authority should determine scope of analyses depending on sensitivities in the area around the proposed new source or modification
˃ Analysis tends to be qualitative (in most applications)
Potential adverse impacts can often be discerned against secondary NAAQS (public welfare, including environment)
Non-air quality assessments can be considered
˃ Analyzes impairment to visibility, soils, and vegetation that occurs
as a result of:
The new source or modification
General commercial, residential, industrial, or other growth
associated with the source or modification
9. PSD Permitting Process –
Don’t Forget About the Rest of
the Agency Application Submittal
Obligations ˃ Narrative description of the project
˃ Process flow diagram
˃ Site map / layout drawing
˃ Agency Forms
˃ Fees
˃ Regulatory applicability – SIP, NSPS, NESHAP, etc.
˃ Signatures
˃ Goal – a complete application garnering a completeness determination!
10. PSD Permitting Process -
Addressing Startup, Shutdown,
Malfunction ˃ Traditionally, permits address SSM situations to allow
sources to follow particular steps to remain in
compliance with permit during these situations
˃ USEPA recently issued SIP call for SSM provisions in SIPs
that were considered too broad in controlling federal
court response to SSM situations
˃ Most states still in flux regarding how to address SIP
call
Opportunity for interested parties to get involved
Tips and Strategies for Working
With the Agencies
˃ State will be primary permitting authority
Know the personnel and internal process
Maintain open communications during process
˃ Develop a thorough administrative record
˃ Interaction with USEPA
State-issued PSD permits sent to USEPA for review
Requesting USEPA determinations – can be time-
consuming and unpredictable
PSD Permit Timeline – “Best Case”
Final
Permit
Issuance
Proposed
Final
Permit
1.5
month
USEPA
Review
Public
Review
Agency Admin
Completeness
Submit
Application
Admin
Completeness
Notification
0.5
month
Agency
Technical
Review
Proposed
Draft
Permit
4
months
Start of
Process
3
months 1
month
Develop
Application
10 months
PSD Permit Timeline – “Worst Case”
Final
Permit
Issuance
Proposed
Final
Permit
6 month
USEPA + FWS
+ NHPA
Review
Public
Review +
Meeting
Agency Admin
Completeness
Submit
Application
Admin
Completeness
Notification
1
month
Agency
Technical
Review
Proposed
Draft
Permit
9
months
Start of
Process
6
months 2
month
Develop
Application
24 months
Prior to Permit Issuance ˃ What activities can be carried out before PSD permit issuance?
Equipment may be received at a plant site/stored provided no
attempt is made to assemble the equipment or to connect the
equipment into any electrical, plumbing, or other utility system
Portable equipment may be placed on the property provided no work
is done to assemble or erect the equipment
Any work such as excavation upon which permit units will rest shall
be considered construction
Land clearing, leveling of the area, utility lines, road building, power
line installation, fencing, etc., are gray areas
˃ Recommend clarifying “start of construction” with local agency
and/or your legal team
Public Notice Procedures
˃ Will vary by state
˃ Usually require publication through air quality
agency and in newspaper
˃ Usually 30 day timeframe
˃ Pros and cons of requesting public hearing on
your own permit
During Permit Issuance – Public
Involvement
˃ Who comments and what to expect?
NGOs – fuels and climate change related
♦ Coal or solid fuels
♦ Local environmental issues of concern
Public - health related
♦ Will emissions harm our children and the elderly?
♦ What is the danger in being exposed to the cumulative
emissions from all of the industry in the area?
USEPA Region V - regulatory related
♦ BACT is a focus area
♦ Historically, fewer modeling related comments
… and some unpredictable!!
Once Permit Decision is Made
˃ Permit to construct – must commence
construction within 18 months of permit
˃ From the opposite perspective – cannot
commence construction until permit in hand
˃ Examples of what constitutes “commence
construction”
Delivery of materials?
Work on areas of project unrelated to emission
unit?
3rd Party Challenge to PSD Permit
˃ Several opportunities
Public hearing
State administrative procedures
Petition to USEPA EAB for review of PSD permit (if
USEPA is issuing authority)
State or federal court proceedings
Petition to USEPA against Title V permit – another
bite at the PSD apple
˃ Limited to issues raised during public comment
period
Changing a PSD Permit?
˃ Per 40 CFR 52.21(w) – PSD permits remain in
effect unless expires (construction is not
commenced with time allowed by permit) or
permit is rescinded
˃ There is some “draft” guidance from 1985 and
1991 on modifying a PSD permit
4 categories of change – administrative, minor,
significant, fundamental
Each category brings it own set of obligations on
the part of the applicant
Questions?
John P. Iwanski, Managing Director
Olivia Lucas, Esq., Counsel, Faegre Baker
Daniels