Olivia Lucas, Faegre Baker Daniels, John Iwanski, Trinity Consultants, Crash Course in NSR/PSD Permitting, Midwest Environmental Compliance Conference, Chicago, October 29-30, 2015

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

[email protected]

˃ 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.

mailto:[email protected]

Introductions

John P. Iwanski, Managing Director

[email protected]

˃ 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

Example – Source Definition -

Continuous or Adjacent

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.”

Some States

Have Even

Developed “a

Form” for

“Source”

Determination

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

Support Facility Can Trump Lack

of Common Control

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.


“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


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


˃ 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


˃ 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


˃ 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


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


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)





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






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






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.”


˃ 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


˃ 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

http://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


˃ 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


˃ 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

Netting – Further Caution

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)

Break & Practical Exercise

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?


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?


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?


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?


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?


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


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)


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


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)


Need to Demonstrate NAAQS/PSD

Increment Compliance?


Any Ambient Monitoring Obligations?

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


Class I Area(s) Nearby?

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


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

PSD Commence Construction

Caution

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

Commencing Construction

Delayed?

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

[email protected]

Olivia Lucas, Esq., Counsel, Faegre Baker

Daniels

[email protected]

