The Falkirk Mining Company 

1⁄2 Section 10 Federal Coal Mining Plan

Serial Number: NDM 107039

Supplemental Environmental Assessment

March 2018

US Department of the Interior

Office of Surface Mining Reclamation and Enforcement

Program Support Division

1999 Broadway, Suite 3320

Denver, CO 80202

Phone 303-293-5000

Fax 303-293-5032

Supplemental Environmental Assessment March 2018 Table of Contents

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA i

Table of Contents

Chapter 1 Introduction ..................................................................................................................1

1.1 Introduction .......................................................................................................................1

1.2 Background .......................................................................................................................3

1.3 Regulatory Framework and Necessary Authorizations.................................................4

1.4 Purpose and Need for the Proposed Action...................................................................5

1.5 Outreach and Issues Identification..................................................................................6

Chapter 2 Proposed Action and Alternatives..............................................................................7

2.1 Introduction .......................................................................................................................7

2.1.1 Proposed Action .............................................................................................................7

2.1.2 No Action........................................................................................................................7

2.1.3 Air Quality.......................................................................................................................8

Chapter 3 Affected Environment..................................................................................................9

3.1 Introduction .......................................................................................................................9

3.2 Air Quality and Climate Change.......................................................................................9

3.2.1 Criteria Pollutants National Ambient Air Quality Standards............................................9

3.2.2 Hazardous Air Pollutants..............................................................................................14

3.2.3 Mercury ........................................................................................................................15

3.2.4 Greenhouse Gas/Climate Change ...............................................................................16

Chapter 4 Direct and Indirect Impacts .......................................................................................21

4.1 Introduction .....................................................................................................................21

4.2 Air Quality and Climate Change.....................................................................................21

4.2.1 Emission Sources.........................................................................................................21

4.2.2 Proposed Action ...........................................................................................................23

4.2.3 No Action......................................................................................................................29

Chapter 5 Cumulative Impacts ...................................................................................................30

5.1 Introduction .....................................................................................................................30

5.1.1 Analysis Areas..............................................................................................................30

5.1.2 Past, Present, and Reasonably Foreseeable Actions ..................................................30

5.2 Cumulative Impacts ........................................................................................................32

5.2.1 Air Quality and Climate Change ...................................................................................32

Chapter 6 Coordination and Consultation.................................................................................34

6.1 Agencies and People Consulted....................................................................................34

6.2 Preparers and Participants.............................................................................................34

References.......................................................................................................................................36
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List of Tables

Table 1 NAAQS Standard and Monitored Concentrations at Hanover.............................................12

Table 2 NAAQS Standard and Monitored Concentrations at TRNP-NU ..........................................13

Table 3 Annual Criteria Pollutant Emissions at Coal Creek Station and Spiritwood 

Station 2012-2016........................................................................................................14

Table 4 Annual Emissions for HAPs at Coal Creek Station and Spiritwood Station 2012-

2016 .............................................................................................................................15

Table 5 Annual Mercury Emissions at Coal Creek Station and Spiritwood Station 2012-

2016 .............................................................................................................................15

Table 6 Annual Greenhouse Gas Emissions at Coal Creek Station and Spiritwood 

Station 2012-2016........................................................................................................17

Table 7 1990-2015 Estimated US Greenhouse Gas Emissions Allocated to Economic 

Sectors (in Million Metric Tons of CO2e) ......................................................................18

Table 8 Direct Fleet Emissions from Section 10 Lease Tract Coal, tons..........................................24

Table 9 Estimated Direct Fugitive Emissions from Section 10 Lease Tract Coal Activities..............25

Table 10 Total Annual Direct Emissions ...........................................................................................25

Table 11 Estimated Indirect Annual Emissions for Section 10 Lease Tract Coal in the 

Proposed Action...........................................................................................................26

Table 12 Summary of 2016 and Anticipated Future Lignite Production in North Dakota..................31

Table 13 Coal Fired Power Plants in North Dakota ..........................................................................32

Table 14 North Dakota and Section 10 Lease Tract Emissions .......................................................33

Table 15 List of Preparers ................................................................................................................34

Table 16 Contractors ........................................................................................................................35

List of Figures

Figure 1 Location of Falkirk Mine........................................................................................................3

Figure 2 Ambient Air Monitoring Sites in North Dakota ....................................................................11

Figure 3 Sulfur Dioxide and Nitrogen Oxides Emissions from Power Plants in North 

Dakota..........................................................................................................................28

Appendices

Appendix A Air Emissions Information
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Acronyms

Acronym Definition

AEIR Annual Emission Inventory Reports 

BLM Bureau of Land Management 

CAA Clean Air Act 

CATF Clean Air Task Force 

CEQ Council on Environmental Quality 

CFR Code of Federal Regulations

CH4 Methane

CO Carbon monoxide 

CO2 Carbon dioxide

CO2eq Carbon dioxide equivalent

CWA Clean Water Act 

DOI Department of the Interior 

EA Environmental Assessment 

EIA Energy Information Administration 

EIS Environmental Impact Statement 

EO Executive Order 

EPA Environmental Protection Agency

g Grams

GHG Greenhouse gas

GRE Great River Energy

GWP Global Warming Potential 

H2SO4 Sulfuric acid

HAP Hazardous Air Pollutant

HCl Hydrogen chloride

HF Hydrogen fluoride

Hg Mercury

IPCC Intergovernmental Panel on Climate Change 

lb Pounds

μg/m3 Microgram per meter squared

MACT Maximum Achievable Control Technology 

MATS Mercury and Air Toxics Standards 

MLA Mineral Leasing Act 

MM Million

MMTPY Million tons per year

MPDD Mining plan decision document

MW Megawatt

N2O Nitrous oxide

NAAQS National Ambient Air Quality Standards

ND North Dakota

NEPA National Environmental Policy Act 

NHPA National Historic Preservation Act 
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Acronym Definition

NO2 Nitrogen dioxide

NOx Nitrogen oxides

NPS National Park Service 

NSR New Source Review

O3 Ozone

OSMRE Office of Surface Mining Reclamation and Enforcement 

PAP Permit Application Package

Pb Lead

PM Particulate matter

PM10 Particulate matter less than 10 um in diameter

PM2.5 Particulate matter less than 2.5 um in diameter

ppb Parts per billion

ppm Parts per million

PSC Public Service Commission 

PSD Prevention of Significant Deterioration

SCC Social cost of carbon

Se Selenium

SF6 Sulfurhexafluoride

SMCRA Surface Mining Control and Reclamation Act

SO2 Sulfur dioxide

SOx Sulfur oxides

TOC Total Organic Carbon

TPY Tons per year

TRI Toxics Release Inventory

TRNP Theodore Roosevelt National Park 

US United States

USC United States Code 

VOC Volatile organic carbon
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The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA

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Chapter 1

Introduction

1.1 Introduction

The Falkirk Mining Company, operator of the Falkirk Mine in North Dakota, submitted a 

permit application package (PAP) to the North Dakota Public Service Commission (PSC) on 

November 9, 2017, to add the federal coal included in 1⁄2 Section 10. Please refer to Figure 1

Location of Falkirk Mine for the location of 1⁄2 Section 10. Pursuant to Section 503 of the 

Surface Mining Control and Reclamation Act (SMCRA), which grants states the right to 

assume jurisdiction over the regulation of surface coal mining of non-federal coal, the PSC

developed a permanent regulatory program. In August 1983, pursuant to § 523(c) of 

SMCRA, the PSC entered into a cooperative agreement with the Secretary of the Interior to 

assume that jurisdiction. The PSC maintains primacy to enforce performance standards and 

permit requirements and has authority during environmental emergencies while the Office of 

Surface Mining Reclamation and Enforcement (OSMRE) retains oversight of this 

enforcement. The OSMRE is required to evaluate the PAP before Falkirk Mine may conduct 

mining and reclamation operations to develop the 1⁄2 Section 10. OSMRE is the agency 

responsible for making a recommendation to the United States Department of the Interior 

Assistant Secretary for Land and Minerals Management (ASLM) to approve, disapprove, or 

approve with conditions the proposed mining plan. 

The Bureau of Land Management (BLM) North Dakota Field Office completed an 

Environmental Assessment (EA) in March 2017 that analyzed the environmental impacts of 

a federal coal lease proposed by The Falkirk Mining Company (Falkirk) located in the east 1⁄2 

of Section 10, Township 146 North, Range 82 West, McLean County, North Dakota (refer to 

Figure 1 Location of Falkirk Mine). The United States (US) Department of the Interior (DOI), 

Office of Surface Mining Reclamation and Enforcement (OSMRE), Western Region Office 

and North Dakota Public Service Commission (PSC) cooperated in the preparation of the 

EA (BLM, 2017) (BLM, 2017). 

As a federal agency, OSMRE is subject to the National Environmental Policy Act of 1969

(NEPA), and therefore must conduct an environmental review, in form of either adoption of a 

prior NEPA document for the same project, supplementing a prior NEPA document for the 

same project, or creation of a new NEPA analysis, before proceeding the federal action of 

making a recommendation to the ASLM regarding the mining plan. The OSMRE has 

prepared this supplemental environmental assessment (EA), based on new information 

provided by the Operator to further assess potential air quality impacts associated with the 

issuance of the federal coal lease. The applicable analysis regarding the affected 

environment, environmental impacts and mitigation, and cumulative effects for the following 

elements are addressed, if determined necessary, in the BLM EA and are incorporated by 
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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 2

reference1 and are not discussed further in this Supplemental EA in accordance with 40 

CFR 46.135:

 Areas of Critical Environmental Concern

 Cultural or Historical Values

 Economics

 Environmental Justice

 Floodplains

 General Vegetation

 General Wildlife

 Geology and Minerals

 Invasive, Nonnative Species

 Noise and Vibration

 Paleontology

 Prime or Unique Farmland

 Range

 Soils

 Threatened and Endangered Species

 Topography

 Transportation and Traffic

 Visual Resources Management

 Wastes, Hazardous or Solids

 Water Resources

 Wetland/Riparian

 Wild and Scenic Rivers

 Wilderness

The Supplemental EA review has been conducted in accordance with NEPA as amended

and the President’s Council on Environmental Quality (CEQ) regulations for implementing 

NEPA (40 Code of Federal Regulations [Code of Federal Regulations (CFR)] 1500-1508); 

DOI regulations for implementation of NEPA (43 CFR Part 46); DOI Departmental Manual 

Part 516; and OSMRE guidance on implementing NEPA, including the OSMRE Handbook 

on Procedures for Implementing the National Environmental Policy Act (OSMRE 1989).

The NEPA requires federal agencies to consider the potential environmental impacts of 

proposed federal actions and to make a determination as to whether the analyzed actions 

would significantly impact the environment. The term “significantly” is defined in 40 CFR 

1508.27. If OSMRE determines that the project would have significant impacts following the 

analysis in the EA, then an Environmental Impact Statement (EIS) would be prepared. If 

OSMRE determines that the potential impacts would not be significant, OSMRE would 

 

1 The BLM EA is available on their e-planning website at: https://eplanning.blm.gov/epl-frontoffice/projects/nepa/67410/105731/129311/DOI-BLM-MT-C030-2016-0020-EA.pdf
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prepare a “Finding of No Significant Impact” to document this finding, and, accordingly, 

would not prepare an EIS. 

The BLM Montana State Office is a cooperating agency in the preparation of this 

supplemental EA.

Figure 1 Location of Falkirk Mine

1.2 Background

The Falkirk Mine is located near Underwood, North Dakota. It was first incorporated in 1974, 

with initial construction starting in 1977, and coal production starting in 1978. Currently, the 

mine produces approximately 8.0 - 8.5 million tons of coal per year. Coal produced at the 

Falkirk Mine is transported from the pit in bottom-dump haul trucks to the truck 

dump/crushing facility. From that location, the coal is conveyed on a 5,300-foot-long 

conveyor to the Great River Energy’s Coal Creek Station, which is located approximately 6 

miles south of Underwood, North Dakota. Coal Creek Station generates 1,200 megawatts 

(MW) (2 - 600 Megawatt Units) of power, which is transmitted to 28 power cooperatives that 

serve approximately two-thirds of rural Minnesota (BLM, 2017). 
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The proposed Section 10 lease tract, which encompasses the east 1⁄2 of Section 10, is part 

of the Falkirk Mine’s current and extended Mining Plan with the south 1⁄2 of the Section 10 

lease tract already permitted through the PSC for mining activities. The BLM held a 

competitive lease on October 17, 2017, which was awarded to Falkirk Mining; the effective 

date the lease was issued is January 1, 2018. The southeast 1⁄4 of Section 10 

(approximately 160 acres), NDM-107039 lease tract, is contained within the Falkirk Mine’s 

permit, Permit No. NAFK-8405, issued by the North Dakota Public Service Commission 

(PSC) for mining activities; however, no actual mining of the federal coal tract can occur until 

the mining plan is approved by the ASLM. Revision 37 to Permit NAFK-8405, submitted to 

the North Dakota PSC on November 9, 2017, incorporates plans for mining the south-east 

1⁄4 of Section 10 NDM-107039 lease tract. The Falkirk Mine submitted a mining plan 

modification application, revision 38 to Permit NAFK-8405, to the North Dakota PSC on 

January 18, 2018 that adds 1680 acres to Permit NAFK-8405 including mining activities in 

the north-east 1⁄4 of Section 10 (approximately 160 acres), NDM-107039 lease tract. ASLM

approval of the mining plan and mining plan modification would authorize mining of 2.2 

million tons of federal coal at the Falkirk Mine. Currently, the mine produces approximately 

8.0 to 8.5 million tons of coal per year. The Section 10 lease tract has approximately 4.41 

million tons of private and federal recoverable coal, of which 50%, or approximately 2.2 

million tons, is federal ownership coal. Leasing and mining private and federal coal reserves 

within the Section 10 lease tract would contribute approximately seven months-worth of 

average production at the Falkirk Mine (BLM, 2017). Because the coal in the mineral rights 

of the Section 10 lease tract are undivided, the recovery of the private and federal coal 

would both occur with the approval of the mining plan. Thus, the impacts of the entire 

Section 10 lease tract of 4.41 million tons of coal is assessed in this Supplemental EA.

1.3 Regulatory Framework and Necessary Authorizations

The following key laws, as amended, establish the primary authorities, responsibilities, and 

requirements for developing federal coal resources: 

 Mineral Leasing Act of 1920 (MLA); 

 National Historic Preservation Act of 1966 (NHPA); 

 National Environmental Policy Act of 1969 (NEPA); 

 Clean Air Act of 1970 (CAA); 

 Clean Water Act of 1972 (CWA); 

 Endangered Species Act of 1973 (ESA); 

 Surface Mining Control and Reclamation Act of 1977 (SMCRA). 

SMCRA provides the legal framework for the federal government to regulate coal mining by

balancing the need for continued domestic coal production with protection of the 

environment and society while also ensuring the mined land is returned to beneficial use 

when mining is finished. OSMRE implements its responsibilities for the MLA and SMCRA 

under regulations at CFR Title 30 - Mineral Resources, Chapter VII - OSMRE, Department 

of the Interior, Subchapters A-T, Parts 700-955.
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The SMCRA provides the OSMRE primary responsibility for administering programs that 

regulate surface coal mining operations in the United States. Pursuant to Section 503 of 

SMCRA, 30 U.S.C. 1253, the North Dakota PSC developed, and the Secretary of the 

Interior approved, North Dakota’s permanent regulatory program authorizing the PSC to 

regulate surface coal mining operations on private and state lands within North Dakota. 

Pursuant to Section 523 of SMCRA, 30 U.S.C. 1273, the North Dakota PSC entered into a 

cooperative agreement with the Secretary of the Interior authorizing the PSC to regulate 

surface coal mining operations on federal lands within the state. 

Pursuant with this cooperative agreement, a federal coal leaseholder must submit a permit 

application package, which includes the Resource Recovery and Protection Plan and State 

Mining Permit application, to OSMRE and the North Dakota PSC for any proposed coal 

mining and reclamation operations on federal lands located in the state. Federal lands 

include surface ownership and mineral interests, owned by the federal government. If the 

permit application complies with the relevant laws and plan, the North Dakota PSC issues a 

permit to the applicant to conduct coal-mining operations. 

Once the State’s findings and recommendations are received, OSMRE will prepare a mining 

plan decision document (MPDD) in support of its recommendation to the Assistant Secretary 

for Land and Minerals Management (ASLM), who will decide whether or not to approve the 

mining plan and whether or not additional conditions are needed. Pursuant to 30 CFR 

746.13, the OSMRE‘s recommendation shall be based on:

 The PAP including the R2P2;

 Information prepared in compliance with NEPA, including this EA;

 Documentation assuring compliance with the applicable requirements of federal laws, 

regulations, and executive orders other than NEPA;

 Comments and recommendations or concurrence of other federal agencies and the 

public;

 Findings and recommendations of the BLM with respect to the R2P2, federal lease 

requirements, and the MLA;

 Findings and recommendations of the North Dakota PSC with respect to the permit

application and the state program; and

 The findings and recommendations of the OSMRE regarding additional requirements 

of 30 CFR Chapter VII, Subchapter D.

1.4 Purpose and Need for the Proposed Action

The purpose of the action (to make a recommendation to the ASLM to approve, disapprove, 

or approve with conditions the proposed mining plan) is established by the Mineral Leasing 

Act of 1920 (MLA) and the SMCRA, which requires the evaluation of Falkirk Mine’s PAP 

before they may conduct mining and reclamation operations to develop 1⁄2 Section 10 under 

30 CFR Part 746: 30, United States Code (USC)/208(c). OSMRE is the agency responsible 
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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 6

for making a recommendation to the ASLM to approve, disapprove, or approve with 

conditions, the proposed mining plan. As approved in the MLA, the ASLM will decide 

whether the mining plan is approved, disapproved, or approved with conditions. If the ASLM 

approves this action, operations would be extended at the Falkirk Mine for up to an 

additional seven months. The need for the action is to allow Falkirk Mine the opportunity to 

exercise its valid rights granted for 1⁄2 Section 10 (Permit No. NAFK-8405) to extract coal 

from its federal lease issued by the BLM pursuant to the MLA.

1.5 Outreach and Issues Identification

OSMRE developed a project website, which provided additional notice, information, and 

comment opportunities: https://www.wrcc.osmre.gov/initiatives/falkirkMine.shtm. The 

website was activated on February 9, 2018, and is updated periodically as additional 

information becomes available.

OSMRE released the supplemental EA and unsigned FONSI on February 9, 2018 for a 30-

day public comment period. OSMRE notified the public of this comment period through a 

newspaper notice published in the McLean County Independent and Central McLean NewsJournal, mailed public outreach letters, as well as mailed tribal consultation letters to 18 

tribal leaders. The public comment period ended on March 12, 2018. OSMRE received two 

comment letters during the comment period. OSMRE received a comment letter from the 

Bureau of Indian Affairs indicating they have “no environmental objections to the action as 

long as the project complies with all pertinent laws and regulations”. OSMRE also received a 

comment letter from the State of North Dakota PSC requesting correction to the dates of the 

mining plan modification applications to the North Dakota PSC. These corrections have 

been made in the EA and FONSI.
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Chapter 2

Proposed Action and Alternatives

2.1 Introduction

This chapter incorporates Chapter 2.0 of the BLM EA by reference2 and only provides 

supplemental information regarding air quality where relevant to the supplemental analysis 

presented in this document. Chapter 2.0 of the BLM EA describes the alternatives 

considered and analyzed in detail; the Proposed Action and the No Action. In addition, the 

BLM EA identifies alternatives considered but eliminated from detailed analysis, the current 

operations, and continuation of activities under the Proposed Action and under the No 

Action. This section presents a description of the Proposed Action for which air quality is 

analyzed along with a description of the No Action alternative.

2.1.1 Proposed Action

The southeast 1⁄4 of Section 10 (approximately 160 acres), NDM-107039 lease tract, is 

contained within the Falkirk Mine’s permit, Permit No. NAFK-8405, issued by the North 

Dakota Public Service Commission (PSC) for mining activities; however, no actual mining of 

the federal coal tract can occur until the mining plan is approved by the ASLM. Revision 37 

to Permit NAFK-8405, submitted to the North Dakota PSC on November 9, 2017, 

incorporates plans for mining the south-east 1⁄4 of Section 10 NDM-107039 lease tract. The 

Falkirk Mine submitted a mining plan modification application, revision 38 to Permit NAFK8405, to the North Dakota PSC on January 18, 2018 that adds 1680 acres to Permit NAFK8405 including mining activities in the north-east 1⁄4 of Section 10 (approximately 160 acres), 

NDM-107039 lease tract. The Proposed Action is for the OSMRE to submit a mining plan 

decision document making a recommendation to the Department of the Interior ASLM to 

approve the mining plan decision document. The modified mining plan includes mining coal 

within both the southeast 1⁄4 and northeast 1⁄4 of Section 10. The approved mining plan would 

authorize the mining, at the Falkirk Mine, of 4.41 million tons of coal, of which 2.2 million 

tons are federal coal in the Section 10 lease tract (BLM, 2017).

2.1.2 No Action

Under the No Action alternative, the OSMRE would not recommend approval of the mining 

plan decision document to ASLM. Without ASLM approval, ND PSC’s permit would revert to 

the previous permit. Under the previous permit, the Federal coal reserves in the Section 10 

Federal Coal Lease Tract would not be recovered and mining would continue until available 

coal reserves are mined out.

 

2

 The BLM EA is available on their eplanning website at: https://eplanning.blm.gov/epl-frontoffice/projects/nepa/67410/105731/129311/DOI-BLM-MT-C030-2016-0020-EA.pdf
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2.1.3 Air Quality 

Falkirk operates under synthetic minor source air permit number O79002 (NDAC 33-15-14-

03.1.e) from the Environmental Health Section of the North Dakota Department of Health. 

As a synthetic minor source, Falkirk has taken production limits of 20 million tons per year at 

the primary crusher and conveyor, 34 million tons per year at the secondary crusher and 

conveyor, and 14 million tons per year at the cable belt conveyor system.

In accordance with its air permit, among other standards, Falkirk is required to comply with 

fugitive dust controls that include the following (NDDH, 2016):

1. Control fugitive particulates from land clearing, topsoil and overburden removal, and 

other material handling operations using strategies such as watering, revegetation, 

delay of topsoil disturbance until necessary, surface compaction, and sealing unless 

natural moisture is sufficient to control emissions.

2. Use fugitive dust preventative measures such as watering, covering, shielding, or 

enclosing stockpiles, both active and inactive, as necessary to control emissions 

unless natural moisture is sufficient to control emissions.

3. Fugitive dust preventative measures such as frequent watering, addition of dust 

palliatives, detouring, paving, closure, speed control, or surface treatment shall be 

used for onsite haul roads unless natural moisture is sufficient to control emissions.

4. Construct, protect, or treat all conveyors, transfer point, crushers, screens, and 

dryers to minimize particulate matter emissions.

These requirements would apply to Falkirk in both the Proposed Action and the No Action.
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Chapter 3

Affected Environment

3.1 Introduction

This chapter describes the existing condition of resources that could be affected by 

implementation of the alternatives described in Chapter 2, as they relate to the Mining Plan 

Decision Document for Falkirk Mine. This chapter incorporates Chapter 3.0 of the BLM EA 

by reference3 and only provides supplemental information regarding air quality and climate 

change where relevant to the supplemental analysis presented in this document.

3.2 Air Quality and Climate Change

3.2.1 Criteria Pollutants National Ambient Air Quality Standards

The Clean Air Act (CAA) requires the EPA to set National Ambient Air Quality Standards 

(NAAQS) for pollutants considered harmful to public health and the environment. Primary 

standards provide public health protection including sensitive populations such as children, 

chronically ill, and elderly, while secondary standards provide public welfare protection 

(visibility, damage to crops, danger to animals, etc.). EPA has set NAAQS for six principle 

pollutants, called criteria pollutants including carbon monoxide (CO), lead (Pb), nitrogen 

dioxide (NO2), ozone (O3), particulate pollution (PM2.5 and PM10), and sulfur dioxide (SO2), 

see Table 1 NAAQS Standard and Monitored Concentrations at Hanover. Nitrogen oxides 

(NOx) and volatile organic compounds (VOCs) contribute to ozone formation in the 

atmosphere and are regulated through equipment standards and emissions limits.

Air quality for any area is generally influenced by the types and quantities of air pollutant 

emissions released from natural and man-made sources within and upwind of the area. 

Additionally, the local topography, or terrain (such as mountains and valleys), and weather 

(such as wind, temperature, air turbulence and pressure, humidity, etc.) will have a direct 

effect on the how pollutants form, react, disperse, or accumulate. Ambient air quality in the 

affected area is assessed by conducting monitoring for ground level air pollutant 

concentrations in an air shed and comparing to air quality standards established to protect 

human health and welfare. 

Air sheds are also assigned a priority Class (I, II, or III) which describes how much 

degradation to the existing air quality is allowed to occur within the area under the 

Prevention of Significant Deterioration (PSD) regulations. Class I areas are areas of special 

national or regional natural, scenic, recreational, or historic value, and essentially allow very 

little degradation in air quality (i.e. National Parks, Wilderness Areas), while Class II areas 

allow for reasonable economic growth. Falkirk Mine is located in a Class II area. There are 

currently no Class III areas defined in North Dakota.

 

3

 The BLM EA is available on their eplanning website at: https://eplanning.blm.gov/epl-frontoffice/projects/nepa/67410/105731/129311/DOI-BLM-MT-C030-2016-0020-EA.pdf
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When a designated air quality area in a state exceeds a NAAQS that area may be 

designated as a “nonattainment” area. Areas with levels of pollutants below the healthbased standard are designated as “attainment” areas. To determine whether an area meets 

the NAAQS, air monitoring networks have been established and are used to measure 

ambient air quality and determine attainment status. In addition, the visibility in Class I areas 

must be monitored based on the Regional Haze Rule (Clean Air Act 169A and 169B, 40 

C.F.R 51, subpart P).

There are four Class I Areas located in North Dakota: Theodore Roosevelt National Park –

North Unit (McKenzie County), Theodore Roosevelt National Park – Elkhorn Ranch Unit 

(Billings County), Theodore Roosevelt National Park – South Unit (Billings County), and 

Lostwood National Wilderness Area (Burke County). The primary anthropogenic sources of 

visibility impairment in North Dakota Class I Areas include electric utility steam generating 

units, energy production and processing sources, agricultural production and processing 

sources, prescribed burning, and fugitive dust sources (NDDH, 2014). The Section 10 lease 

tract is not located within a North Dakota Class I Area. The nearest North Dakota Class I 

Area to the Section 10 lease tract is the Theodore Roosevelt National Park – North Unit 

(McKenzie County). This Class I Area is located more than 105 miles away, generally 

upwind of the Section 10 lease tract and is unlikely to impact visibility conditions in North 

Dakota Class I areas.

EPA has delegated responsibility for many provisions of the Clean Air Act to the State of 

North Dakota Department of Health (NDDH). The NDDH is responsible for monitoring the 

levels of criteria pollutants. The NDDH maintains and operates a network of ten Ambient Air 

Quality Monitoring (AAQM) sites. Nine of these sites are operated directly by NDDH and one 

additional site is operated in partnership with the National Park Service (NPS) in the 

Theodore Roosevelt National Park (TRNP-SU) at Painted Canyon. This monitor and the 

NDDH monitor in the north section of Theodore Roosevelt National Park (TRNP-NU) are 

both in Federal Class I areas. In addition, there are two monitors in Williams County that are 

operated by industry and overseen by NDDH. The closest ambient air monitor to the Falkirk 

Mine is the Hanover station. The TRNP-NU station is the closest station to Falkirk that is in a 

Class I area. Please refer to Figure 2 Ambient Air Monitoring Sites in North Dakota for the 

relative locations of monitoring sites in relation to the Falkirk Mine.
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Figure 2 Ambient Air Monitoring Sites in North Dakota

Table 1 NAAQS Standard and Monitored Concentrations at Hanover and Table 2 NAAQS

Standard and Monitored Concentrations at TRNP-NU, respectively, list the NAAQS and 

recorded levels at the Hanover and TRNP-NU monitoring sites based on the NDDH’s 2017

Annual Report (NDDH, 2017). The only station in the NDDH network that monitors CO is the 

Bismarck station. Monitored CO concentration in 2016 at the Bismarck station are well 

below the NAAQS at 0.779 ppm using a 1-hour averaging time and 0.4 ppm using an 8-hour 

averaging time. No monitors in the NDDH network monitor for lead because the NDDH has 

determined that the state has low ambient lead concentrations and no significant sources of 

lead (NDDH, 2017). 
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Table 1 NAAQS Standard and Monitored Concentrations at Hanover

Pollutant Type

Averaging 

Time

Federal 

Standard Form 2016 2015 2014 2013 2012

CO primary 8-hour 9 ppm Not to be exceeded more than 

once per year

not 

reported

not 

reported

not 

reported

not 

reported

not 

reported

CO primary 1-hour 35 ppm Not to be exceeded more than 

once per year

not 

reported

not 

reported

not 

reported

not 

reported

not 

reported

Lead primary and 

secondary

Rolling 3 

month 

average

0.15 

μg/m3

Not to be exceeded not 

reported

not 

reported

not 

reported

not 

reported

not 

reported

NO2 Primary 1-hour 100 ppb 98th percentile of 1-hour daily 

max. concentrations averaged 

over 3 years

14 ppb 16 ppb 16 ppb 10 ppb 17 ppb

NO2 primary and 

secondary

annual 53 ppb Annual mean 2.09 

ppb

2.18 

ppb

2.17 

ppb

1.72 

ppb

2.11 ppb

O3 primary and 

secondary

8-hour 75 ppb Annual 4th-highest daily max. 8-

hour concentration, averaged 

over 3 years

59 ppb 61 ppb 59 ppb 56 ppb 58 ppb

PM2.5 primary annual 12 μ/m3 Annual mean, averaged over 3 

years

4.3 μ/m3 4.9 μ/m3 5.2 μ/m3 4.9 μ/m3 4.9 μ/m3

PM2.5 secondary annual 15 μ/m3 Annual mean, averaged over 3 

years

4.3 μ/m3 not 

reported

not 

reported

not 

reported

not 

reported

PM2.5 primary and 

secondary

24-hour 35 μ/m3 98th percentile, averaged over 3 

years

18 μ/m3 19 μ/m3 16 μ/m3 14.4 

μ/m3

14.3 

μ/m3

PM10 primary and 

secondary

24-hour 150 μ/m3 Not to be exceeded more than 

once per year on average over 3 

years

72 μ/m3 108 

μ/m3

80 μ/m3 12.3 

μ/m3

14 μ/m3

SO2 primary 1-hour 75 ppb 99th percentile of 1-hour daily 

maximum concentrations, 

averaged over 3 years

10 ppb 14 ppb 24 ppb 24 ppb 40 ppb

SO2 secondary 3-hour 50 ppb Not to be exceeded more than 

once per year

not 

reported

not 

reported

not 

reported

39 ppb 50 ppb

Sources:

Annual Report – North Dakota Ambient Air Quality Monitoring Program – Network Plan with Data Summary (NDDH, 2017).

Annual Report – North Dakota Ambient Air Quality Monitoring Program – Network Plan with Data Summary (NDDH, 2016).

Annual Report – North Dakota Ambient Air Quality Monitoring Program – Network Plan and Five Year Network Assessment with Data Summary (NDDH, 2015).

Annual Report – North Dakota Ambient Air Quality Monitoring Data Summary 2013 (NDDH, 2014).

Annual Report – North Dakota Ambient Air Quality Monitoring Data Summary 2012 (NDDH, 2013).
Supplemental Environmental Assessment March 2018 Chapter 3

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Table 2 NAAQS Standard and Monitored Concentrations at TRNP-NU

Pollutant Type

Averaging 

Time

Federal 

Standard Form 2016 2015 2014 2013 2012

CO primary 8-hour 9 ppm Not to be exceeded more than 

once per year

not 

reported

not 

reported

not 

reported

not 

reported

not 

reported

CO primary 1-hour 35 ppm Not to be exceeded more than 

once per year

not 

reported

not 

reported

not 

reported

not 

reported

not 

reported

Lead primary and 

secondary

Rolling 3 

month 

average

0.15 μ/m3 Not to be exceeded not 

reported

not 

reported

not 

reported

not 

reported

not 

reported

NO2 Primary 1-hour 100 ppb 98th percentile of 1-hour daily 

max. concentrations averaged 

over 3 years

12 ppb 12 ppb 11 ppb 11 ppb 9 ppb

NO2 primary and 

secondary

annual 53 ppb Annual mean 1.30 

ppb

1.66 

ppb

1.64 

ppb

1.16 

ppb

1.2 ppb

O3 primary and 

secondary

8-hour 75 ppb Annual 4th-highest daily max. 8-

hour concentration, averaged 

over 3 years

57 ppb 58 ppb 57 ppb 58 ppb 59 ppb

PM2.5 primary annual 12 μ/m3 Annual mean, averaged over 3 

years

2.8 μ/m3 3.4 μ/m3 4.6 μ/m3 6.5 μ/m3 8.1 μ/m3

PM2.5 secondary annual 15 μ/m3 Annual mean, averaged over 3 

years

2.8 μ/m3 not 

reported 

not 

reported 

not 

reported

not 

reported 

PM2.5 primary and 

secondary

24-hour 35 μ/m3 98th percentile, averaged over 3 

years

17 μ/m3 18 μ/m3 15 μ/m3 11.4 

μ/m3

17.4 

μ/m3

PM10 primary and 

secondary

24-hour 150 μ/m3 Not to be exceeded more than 

once per year on average over 3 

years

57 μ/m3 57 μ/m3 30 μ/m3 7.1 μ/m3 9.4 μ/m3

SO2 primary 1-hour 75 ppb 99th percentile of 1-hour daily 

maximum concentrations, 

averaged over 3 years

6 ppb 6 ppb 8 ppb 6.5 ppb 10.1 ppb

SO2 secondary 3-hour 50 ppb Not to be exceeded more than 

once per year

not 

reported

not 

reported

not 

reported

9 ppb 10 ppb

Sources: 

Annual Report – North Dakota Ambient Air Quality Monitoring Program – Network Plan with Data Summary (NDDH, 2017).

Annual Report – North Dakota Ambient Air Quality Monitoring Program – Network Plan with Data Summary (NDDH, 2016).

Annual Report – North Dakota Ambient Air Quality Monitoring Program – Network Plan and Five Year Network Assessment with Data Summary (NDDH, 2015).

Annual Report – North Dakota Ambient Air Quality Monitoring Data Summary 2013 (NDDH, 2014).

Annual Report – North Dakota Ambient Air Quality Monitoring Data Summary 2012 (NDDH, 2013).
Supplemental Environmental Assessment March 2018 Chapter 3

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14

Criteria pollutant emissions from coal combustion are indirect emissions associated with the 

Falkirk Mine. Two coal combustion power plants, Coal Creek Station and Spiritwood Station 

combust coal from Falkirk. For background, the indirect emissions associated with these two 

power plants are presented in Table 3 Annual Criteria Pollutant Emissions at Coal Creek 

Station and Spiritwood Station 2012-2016.

Table 3 Annual Criteria Pollutant Emissions at Coal Creek Station and Spiritwood 

Station 2012-2016

Year PM10 PM2.5 SO2 NOx CO TOC Unit

2012 194 78 16,272 8,655 1,807 145 tons

2013 185 74 15,455 8,008 1,732 139 tons

2014 193 77 15,865 8,042 1,836 144 tons

2015 144 58 15,510 8,812 1,731 155 tons

2016 134 54 13,317 7,857 1,731 140 tons

Average 170 68 15,284 8,275 1,767 144 tons

Source:

GRE Coal Creek Station Annual Inventory Reports 2012 - 2016 (GRE, 2013) (GRE, 2014) (GRE, 2015) (GRE, 

2016) (GRE, 2017) and Spiritwood Station Annual Inventory Reports 2014, 2015, 2016 (GRE, 2015) (GRE, 

2016) (GRE, 2017).

3.2.2 Hazardous Air Pollutants

In addition to criteria pollutants, the EPA regulates a list of hazardous air pollutants (HAPs). 

HAPs are pollutants that cause or may cause cancer, serious health effects, or adverse 

environmental and ecological effects. The CAA Amendments of 1990 lists 187 HAPs, 

including pollutants such as asbestos, chlorine, and mercury compounds. Most air toxics are 

generated from mobile or stationary, human-made sources. Major stationary sources are 

sources that emit 10 tons per year of any listed HAP. Area sources are defined as smaller 

facilities that release less than 10 tons per year of any listed HAP. Stationary source 

facilities that meet the reporting criteria must report their releases to the EPA through the 

Toxics Release Inventory (TRI) Program (USEPA, 2016). As a synthetic minor source, 

Falkirk emits less than 10 TPY of any listed HAP and less than 25 TPY of all HAPs 

combined. HAP emissions are also generated indirectly from the combustion of coal. HAP 

emissions from Coal Creek Station and Spiritwood Station, which both combust Falkirk coal 

are summarized in Table 4 Annual Emissions for HAPs at Coal Creek Station and 

Spiritwood Station 2012-2016.
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Table 4 Annual Emissions for HAPs at Coal Creek Station and Spiritwood Station 

2012-2016

Year

Total Metal 

HAPs

Total VOC 

HAPs HCl HF H2SO4 Unit

2012 6.61 3.12 0.75 79.00 21.50 tons

2013 6.28 2.99 0.72 75.50 19.50 tons

2014 6.79 2.99 3.42 75.80 69.60 tons

2015 7.00 4.05 37.80 43.80 21.25 tons

2016 5.98 3.59 34.85 39.70 17.55 tons

Average 6.53 3.35 15.51 62.76 29.88 tons

Source: 

GRE Coal Creek Station Annual Inventory Reports 2012 - 2016 (GRE, 2013) (GRE, 2014) (GRE, 2015) (GRE, 

2016) (GRE, 2017) and Spiritwood Station Annual Inventory Reports 2014, 2015, 2016 (GRE, 2015) (GRE, 

2016) (GRE, 2017).

3.2.3 Mercury

Mercury is a naturally occurring metal, but also a potent neurotoxin that affects humans and 

other organisms (USGS, 2000). Mercury emissions are from both natural sources and 

anthropogenic sources as well as re-emission of mercury from the global mercury pool. 

Globally, anthropogenic sources account for about 30% of the total mercury entering the 

atmosphere annually (UNEP, 2013). Coal combustion is a major source of anthropogenic 

mercury emissions and coal combustion at power plants is the primary source of mercury 

emissions by sector in North Dakota (UNEP, 2013). Coal Creek Station, which combusts 

coal from the Falkirk Mine, is the closest power plant to the location of the proposed action. 

Power plants within North Dakota report mercury emissions to the NDDH via Annual 

Emission Inventory Reports (AEIR). Mercury emissions for the past five years from Coal 

Creek Station, as well as Spiritwood Station, which both combust Falkirk Mine coal are 

summarized in Table 5 Annual Mercury Emissions at Coal Creek Station and Spiritwood 

Station 2012-2016.

Table 5 Annual Mercury Emissions at Coal Creek Station and Spiritwood Station 2012-

2016

Power Plant 2012 2013 2014 2015 2016 Unit

Coal Creek Station 800 900 900 880 320 pounds

Spiritwood Station 8 20 10.8 pounds

Source:

GRE Coal Creek Station Annual Inventory Reports 2012 - 2016 (GRE, 2013) (GRE, 2014) (GRE, 2015) (GRE, 

2016) (GRE, 2017) and Spiritwood Station Annual Inventory Reports 2014, 2015, 2016 (GRE, 2015) (GRE, 

2016) (GRE, 2017).

The EPA’s Mercury and Air Toxics Standards (MATS) set emissions standards on all HAPs. 

Recently enacted Maximum Achievable Control Technology (MACT) Standards are 

technology-based emissions limitations for mercury and other toxic air pollutants. These 

standards reflect levels achieved by the best-performing sources currently in operation and 
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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 16

require the installation of mercury controls to achieve over 50 percent reduction from 

historical levels starting in June 2015. The final rule sets standards for all HAPs emitted by 

coal- and oil-fired electric generating units with a capacity of 25 megawatts or greater. All 

regulated units are considered major under the final rule. EPA did not identify any size, 

design, or engineering distinction between major and area sources.

3.2.4 Greenhouse Gas/Climate Change

Greenhouse gases (GHGs) permit incoming (short-wave) radiation from the sun to enter the 

earth’s atmosphere, but block infrared (long-wave) radiation from leaving the earth's 

atmosphere. Through complex interactions on a global scale, the emissions of greenhouse 

gases (GHGs), along with other climate-influencing environmental factors, cause a net 

warming of the atmosphere. GHGs include CO2, methane (CH4), nitrous oxide (N2O), water 

vapor, ozone (O3), fluorocarbons, and sulfurhexafluoride gas (SF6). These are called GHGs 

because when released into the atmosphere they impede the escape of reflected solar 

radiation and heat from the Earth’s surface back into space. In this way, the accumulation of 

GHGs in the atmosphere exerts a “greenhouse effect” on the earth’s temperature.

GHG emissions can be anthropogenic (human-made) or naturally occurring (e.g., volcanic 

activity). Other than GHG emissions, factors that contribute to global warming include 

aerosols, changes in land use, and variations in cloud cover and solar radiation which affect 

the absorption, scattering, and emissions of radiation within the atmosphere and at the 

Earth’s surface. As GHG concentrations increase in the atmosphere, they impact the global 

climate by further decreasing the amount of heat that is allowed to escape back into space.

The average global temperature increased 0.85°C from 1880-2012; during the period from 

1901 to 2012, almost the entire planet experienced higher surface temperatures. Because 

temperature is a part of climate, the phenomenon of global warming is both an element of 

and a driving force behind climate change (IPCC, 2014).

The term “climate change” refers to a substantial and persistent change in the mean state of 

global or regional climate or its variability, usually occurring over decades or longer (CCSP, 

2009). In 2014, the Intergovernmental Panel on Climate Change (IPCC) produced the 

Climate Change Synthesis Report and Summary for Policymakers (IPCC, 2014). The Report 

states that anthropogenic (i.e., human- caused) GHG emissions have increased since the 

preindustrial era, driven largely by economic and population growth, and are now higher 

than they have ever previously recorded. This has led to atmospheric concentrations of 

carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) that are unprecedented in at 

least the last 800,000 years. These anthropogenic GHG emissions are “extremely likely” to 

have been the dominant cause of the observed warming since the mid-20th century.

These climatic changes are impacts in and of themselves; however, they can also affect 

other aspects of the environment including desert distribution, sea level, species distribution, 

species survivability, ocean salinity, availability of fresh water, and disease vectors. These 

effects can vary from region to region over time; some agricultural regions may become 

more arid while others become wetter; some mountainous areas may experience greater 
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The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 17

summer precipitation, yet have their snowpack disappear in the future (IPCC, 2014). North 

Dakota's average temperature increased faster than any other state in the contiguous 

United States, and the number of days with temperatures over 100°F is projected to double 

in the Northern Plains by 2050. Warmer temperatures lengthen the growing season, which 

could increase plant growth or allow for a second planting. However, summer precipitation is 

not projected to rise, which increases vulnerability to drought conditions, while higher 

summer temperatures are likely to reduce plant productivity. Climate change is also 

increasing pest outbreaks, spreading invasive species, accelerating wildfire activity, and 

changing plant flowering times (USEPA, 2017). Thus, the causes and effects of climate 

change can be described as follows. First, GHGs are emitted and other events occur which 

contribute to climate change in the form of global warming. Second, climate change 

contributes to environmental effects around the globe.

Factors that determine a GHG effect on climate change include its concentration, duration, 

and Global Warming Potential (GWP). The GWP is determined by the length of time a GHG 

remains in the atmosphere and the strength with which it absorbs energy. In order to 

aggregate GHG emissions, total GHG emissions are characterized in terms of CO2

equivalent (CO2eq) by adding the product of each GHG multiplied by its GWP. CO2 has a 

GWP of 1, while CH4 and N2O have GWPs of 25 and 298, respectively, based on 100- year 

GWPs (40 CFR Part 98, Table A-1). Greenhouse gases directly emitted from the mining of 

coal are from diesel and gasoline-powered vehicles. Indirectly, GHGs are also produced 

from the generation of electricity used on the mine site and from transporting the coal to the 

end user once it is mined. Further indirect emissions are generated when the coal is 

combusted by the user.

3.2.4.1 Greenhouse Gas Emissions

Coal from Falkirk is combusted at two power plants, Coal Creek Station and Spiritwood 

Station. The indirect emissions generated at these two facilities are summarized in Table 6

Annual Greenhouse Gas Emissions at Coal Creek Station and Spiritwood Station 2012-

2016.

Table 6 Annual Greenhouse Gas Emissions at Coal Creek Station and Spiritwood 

Station 2012-2016

Year

Coal 

Combusted CO2 CH4 N2O CO2e Unit

2012 7,225,823 11,060,356 1,245 181 11,114,323 tons

2013 6,927,877 10,604,299 1,194 174 10,656,040 tons

2014 7,026,579 10,755,379 1,211 176 10,807,858 tons

2015 7,211,153 11,037,901 1,242 181 11,091,758 tons

2016 6,484,546 9,925,705 1,117 163 9,974,135 tons

Average 6,975,196 10,676,728 1,202 175 10,728,823 tons

Source: 

Emissions calculated from reported coal use and emission factors in Table C-1 and C-2 to Subpart C of 40 CFR 

Part 98 (USEPA, 1995).
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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 18

The EPA collects GHG emissions data in the U.S. by source sector (e.g. industrial, land use, 

electricity generation), fuel source (e.g. natural gas, coal, geothermal), and economic sector 

(e.g. industrial, commercial, residential). Considering the diverse sources of GHG emissions 

nationally, from cattle to vehicles to electric power generation, no single source is likely to 

represent a significant percentage of national emissions. Total GHG emissions for the U.S. 

are presented in Table 7 1990-2015 Estimated US Greenhouse Gas Emissions Allocated to 

Economic Sectors (in Million Metric Tons of CO2e) by GHG and for selected source sectors. 

GHG from coal mining are included in Industry emissions and were estimated to be 60.9 

MMT in 2015, or approximately 1% of the total US GHG Inventory. According to the U.S. 

Energy Information Administration (EIA, 2017), US coal production in 2015 was 869,941,000

short tons of which 28,802,000 short tons (approximately 3.3%) were produced from four

surface coal mines in North Dakota. Assuming roughly proportional emissions across coal 

mining operations, the four surface mines in North Dakota account for roughly 0.03% of the 

US GHG inventory. Power production accounts for approximately one third of the US GHG 

inventory and the two power plants combusting Falkirk coal account for approximately 0.5% 

of the electric power industry 2015 GHG emissions and less than 0.2% of the 2015 US GHG 

inventory. 

Table 7 1990-2015 Estimated US Greenhouse Gas Emissions Allocated to Economic 

Sectors (in Million Metric Tons of CO2e)

Sector 1990 2005 2011 2015

Electric Power Industry 1,862.5 2,441.6 2,197.3 1,941.4

Transportation 1,551.2 2,001.0 1,800.0 1,806.6

Industry 1,626.3 1,467.1 1,378.6 1,411.6

Agriculture 526.7 574.3 592.0 570.3

Commercial 418.1 400.7 406.5 437.4

Residential 344.9 370.4 356.3 372.7

US Territories 33.3 58.1 46 46.6

Total Emissions 6,363.1 7,313.3 6,776.7 6,586.7

Land Use, Land-Use Change, and Forestry 

(Sink) (819.6) (731.0) (749.2) (758.9)

Net Emissions (Sources and Sinks) 5543.5 6,582.3 6,027.6 5,827.7

Source: Table 2-10 (USEPA, 2017)

Note that “Land Use, Land-Use Change, and Forestry” represents a sink rather than a source, and is therefore 

presented in parentheses.

On a federal level, the EPA has implemented various programs to encourage the reduction 

of GHG emissions to address climate change. EPA has promulgated rules under the CAA to 

regulate greenhouse gas emissions, finalizing rules under Section 111(d) of the CAA to cut 

carbon emissions from existing fossil fuel-fired power plants. The rule is commonly referred 

to as “the Clean Power Plan”. Executive Order 13763 called for a review of the Clean Power 

Plan and although a repeal of the plan was proposed on October 16, 2017, the possible 

repeal is not finalized. The Clean Power Plan would establish goals for carbon reduction 

from power plants, but the states would determine the means of achieving the standards. 

Under the final Clean Power Plan, North Dakota will be required to reduce CO2 emissions 
Supplemental Environmental Assessment March 2018 Chapter 3

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 19

from existing power plants on the order of 45 percent (USEPA, 2015). The Clean Power 

Plan would not directly regulate emissions from the Mine, but would regulate emissions from 

downstream users of the coal produced by the Mine. The pending repeal of the Clean 

Power Plan has introduced additional uncertainty in the extent of GHG emissions reductions 

that may occur in the near future.

3.2.4.2 Social Cost of Carbon

A protocol to estimate what is referenced as the “social cost of carbon” (SCC) associated 

with GHG emissions was developed by a federal Interagency Working Group (IWG), to 

assist agencies in addressing Executive Order (EO) 12866, which requires federal agencies 

to assess the cost and the benefits of proposed regulations as part of their regulatory impact 

analyses. The SCC is an estimate of the economic damages associated with an increase in 

carbon dioxide emissions and is intended to be used as part of a cost-benefit analysis for 

proposed rules. As explained in the Executive Summary of the 2010 SCC Technical Support 

Document “the purpose of the [SCC] estimates...is to allow agencies to incorporate the 

social benefits of reducing carbon dioxide (CO2) emissions into cost-benefit analyses of 

regulatory actions that have small, or ‘marginal,’ impacts on cumulative global emissions.” 

Technical Support Document: Social Cost of Carbon for Regulatory Impact Analysis Under 

Executive Order 12866 February 2010 (withdrawn by EO13783). While the SCC protocol 

was created to meet the requirements for regulatory impact analyses during rulemakings, 

there have been requests by public commenters or project applicants to expand the use of 

SCC estimates to project-level NEPA analyses.

The decision was made not to expand the use of the SCC protocol for this Falkirk Mine EA 

for a number of reasons. Most notably, this action is not a rulemaking for which the SCC 

protocol was originally developed. Second, on March 28, 2017, the President issued 

Executive Order 13783 that, among other actions, withdrew the Technical Support 

Documents upon which the protocol was based and disbanded the earlier Interagency 

Working Group on Social Cost of Greenhouse Gases. The Order further directed agencies 

to ensure that estimates of the social cost of greenhouse gases used in regulatory analyses 

“are based on the best available science and economics” and are consistent with the 

guidance contained in OMB Circular A-4, “including with respect to the consideration of 

domestic versus international impacts and the consideration of appropriate discount rates” 

(E.O. 13783, Section 5(c)). In compliance with OMB Circular A-4, interim protocols have 

been developed for use in the rulemaking context. However, the Circular does not apply to 

project decisions, so there is no Executive Order requirement to apply the SCC protocol to 

project decisions.

Further, NEPA does not require a cost-benefit analysis (40 C.F.R. § 1502.23), although 

NEPA does require consideration of “effects” that include “economic” and “social” effects. 

40 C.F.R. 1508.8(b). Without a complete monetary cost-benefit analysis, which would 

include the social benefits of the proposed action to society as a whole and other potential 

positive benefits, inclusion solely of an SCC cost analysis would be unbalanced, potentially 
Chapter 3 March 2018 Supplemental Environmental 

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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 20

inaccurate, and not useful in facilitating an authorized officer’s decision. Any increased 

economic activity, in terms of revenue, employment, labor income, total value added, and 

output, that is expected to occur with the proposed action is simply an economic impact, 

rather than an economic benefit, inasmuch as such impacts might be viewed by another 

person as negative or undesirable impacts due to potential increase in local population, 

competition for jobs, and concerns that changes in population will change the quality of the 

local community. Economic impact is distinct from “economic benefit” as defined in 

economic theory and methodology, and the socioeconomic impact analysis required under 

NEPA is distinct from cost-benefit analysis, which is not required.

Finally, the SCC protocol does not measure the actual incremental impacts of a project on 

the environment and does not include all damages or benefits from carbon emissions. The 

SCC protocol estimates economic damages associated with an increase in carbon dioxide 

emissions - typically expressed as a one metric ton increase in a single year - and includes, 

but is not limited to, potential changes in net agricultural productivity, human health, and 

property damages from increased flood risk over hundreds of years. The estimate is 

developed by aggregating results “across models, over time, across regions and impact 

categories, and across 150,000 scenarios” (Rose, et al., 2014). The dollar cost figure arrived 

at based on the SCC calculation represents the value of damages avoided if, ultimately, 

there is no increase in carbon emissions. However, the dollar cost figure is generated in a 

range and provides little benefit in assisting the authorized officer’s decision for project level 

analyses. For example, in a recent environmental impact statement, OSM estimated that the 

selected alternative had a cumulative SCC ranging from approximately $4.2 billion to $22.1 

billion depending on dollar value and the discount rate used. The cumulative SCC for the no 

action alternative ranged from $2.0 billion to $10.7 billion. Given the uncertainties associated 

with assigning a specific and accurate social cost of carbon resulting from seven additional 

months of operation under the mining plan, and that the SCC protocol and similar models 

were developed to estimate impacts of regulations over long timeframes, this EA quantifies 

direct and indirect GHG emissions and evaluates these emissions in the context of global, 

U.S., and North Dakota GHG emission inventories as discussed in Sections 4.2 and 5.2. 

To summarize, this EA does not undertake an analysis of SCC because 1) it is not engaged 

in a rulemaking for which the protocol was originally developed; 2) the IWG, technical 

supporting documents, and associated guidance have been withdrawn; 3) NEPA does not 

require cost-benefit analysis ; and 4) the full social benefits of coal-fired energy production 

have not been monetized, and quantifying only the costs of GHG emissions but not the 

benefits would yield information that is both potentially inaccurate and not useful.
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA

21

Chapter 4

Direct and Indirect Impacts

4.1 Introduction

This chapter describes the direct and indirect impacts in sufficient detail to understand a 

change from the present as a result of the alternatives considered in detail (OSMRE, 1989). 

Direct impacts are those that are caused directly by the proposed activities at the same time 

and place (40 CFR 1508.8(a)). Indirect impacts are those that are removed in time and 

place (40 CFR 1508.8(b)). This chapter incorporates Chapter 4.0 of the BLM EA by 

reference4 and only provides supplemental information regarding air quality where relevant 

to the supplemental analysis presented in this document.

4.2 Air Quality and Climate Change

4.2.1 Emission Sources

4.2.1.1 Direct Emissions

Particulate and gaseous air pollutants are emitted during the coal mining process. The Mine 

currently operates under North Dakota Air Pollution Control Minor Source Permit to Operate 

#O79002. The NDDH sets standards to ensure operations under the Minor Source Permit 

are within State and Federal air quality regulations. In accordance with the Falkirk Mine 

Permit to Operate, the owner/operator keeps records of monthly coal production (tons per 

month) and may not exceed the allowable annual production limit listed in the Permit (20.0

MMTPY for the truck dump, primary crushing station, and conveyor; 34.0 MMTPY for the 

secondary crushing station and conveyor; and 14.0 MMTPY for the east dump/primary 

crusher/cable belt system). At the Mine, the only reportable sources included in the permit, 

and therefore included in the ND statewide emission inventories, are two lignite processing 

and handling facilities, one 16,000-ton storage silo, and one cable belt conveyor system. 

Emission limits to the controlled sources limit emissions from these units, and in 2016 

emitted approximately 9.97 tons of total particulates based on mine production. Please refer 

to Appendix A Air Emissions Information, for details regarding the emission calculations.

Other sources of direct emissions from mining are fugitive emissions from coal excavation 

and reclamation activities and tailpipe emissions from equipment. Fugitive particulate 

emissions result from dust being generated during dragline operations, coal haulage, 

bulldozers, scrapers, loaders, and other equipment operating on the Mine, coal stockpiles, 

and reclamation activities. Please refer to Appendix A Air Emissions Information, for details 

regarding the calculations related to fugitive emissions. The fugitive emissions calculated for 

this EA use basic screening equations and actual production information at the Falkirk Mine. 

The screening equations provide high-end estimates that are intended to overestimate and 

 

4

 The BLM EA is available on their eplanning website at: https://eplanning.blm.gov/epl-frontoffice/projects/nepa/67410/105731/129311/DOI-BLM-MT-C030-2016-0020-EA.pdf
Chapter 4 March 2018 Supplemental Environmental 

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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 22

not underestimate actual emissions. Fugitive emissions are generally not reportable 

emissions.

In accordance with the Fugitive Dust Control Plan in Section 3-4 of the Falkirk Mine Permit 

to Engage in Surface Coal Mining and Reclamation Operations (Appendix B of (BLM, 

2017)), fugitive dust emissions would be reduced by removing topsoil and subsoil in 

increments, only disturbing areas necessary for operations at any one time. All areas of 

disturbance would be stabilized as soon as possible using approved revegetation 

techniques. Fugitive dust from equipment activities and traffic would be reduced by treating 

road surfaces with approved stabilization agents; using water on roads and problem areas 

associated with construction, leveling, and other traffic activities; and using dust 

suppressants during dry periods on haulage and access roads. The Falkirk Mine also is

required to implement fugitive dust control measures listed in the air permit for the entire 

site.

One air pollutant of note that is created during the surface coal mining process is black 

carbon. Black carbon is a light-absorbing, fine particulate (PM2.5) that is formed by the 

incomplete combustion of fossil fuels, biofuels, and biomass. The Clean Air Task Force 

estimates that 75% of diesel particulate matter is black carbon (CATF, 2009). Based on the 

diesel combustion at the Mine, approximately 36.4 tons of black carbon was generated per 

year from 2012 to 2016.

Another group of pollutants is nitrogen oxides (NOx). NOx is formed when fuel is combusted, 

such as from vehicles, off-road equipment, fires, and power plants. These emissions can 

create particulate matter and ground-level ozone, as well as contribute to respiratory issues. 

NOx levels are tracked by the criteria pollutant NO2. North Dakota is in attainment for NO2

levels, as previously shown by Table 1 NAAQS Standard and Monitored Concentrations at 

Hanover and Table 2 NAAQS Standard and Monitored Concentrations at TRNP-NU. NOx is 

created at the Mine by the burning of diesel and, in very small amounts, by coal blasting. 

Please refer to Appendix A Air Emissions Information, for calculations relating to tailpipe and

blasting NOx emissions.

4.2.1.2 Indirect Emissions

Falkirk Mine sells coal to two facilities: Coal Creek Station and Spiritwood Station, both coalfired power plants. Coal Creek Station is a 1,100-megawatt facility with two generating units; 

one that began commercial operation in 1979 and the second that began operating in 1980. 

Spiritwood Station is a 99-megawatt facility and began operations briefly in 2010 before 

shutting down for economic reasons. Operations resumed in 2014 and have continued to 

date. These plants work by combusting coal to heat water, which generates steam. This 

steam turns a turbine connected to a generator. The generator produces electricity using 

magnets spinning against wire coils. The electricity is then delivered to customers through 

transmission lines. Spiritwood Station also provides process steam to adjacent industrial 

consumers.
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 23

On a yearly basis, approximately 93 percent of the coal from the Falkirk Mine is consumed 

at Coal Creek Station and the remaining 7 percent is consumed at Spiritwood Station. Coal 

Creek Station and Spiritwood Station each maintain Title V Permits to Operate, issued by 

the NDDOH. These permits are required for any operations that emit 100 tons per year or 

more of a criteria pollutant, or 10 tons per year of a HAP, or 25 tons per year or more of any 

combination of HAPs. Each facility has technology in place that reduces the amount of 

pollutants from coal combustion to levels acceptable under NDDH and EPA regulations.

One particular pollutant of interest from power plant emission is mercury. Mercury is a 

naturally occurring element, but releases from power plants are the largest source of 

anthropogenic mercury in the United States (UNEP, 2013). Once released into the 

atmosphere, mercury deposits onto land or into water. Once deposited, microorganisms can 

transform it into methylmercury, which is highly toxic, and bioaccumulates in fish and other 

organisms. Mercury can cause health effects such as harm to the brain, heart, kidneys, 

lungs, and immune system if exposure levels are high enough. It can also have ecological 

impacts, particularly to fish, birds, and mammals that eat fish. Mercury exposure to 

ecological communities can cause reduced reproduction, slow growth and development, 

and death. When coal from the Mine is combusted, mercury is released.

4.2.2 Proposed Action

4.2.2.1 Direct Impacts

The mine plan operation under the Proposed Action at the Mine are not anticipated to 

substantially change; the coal from the Section 10 lease tract accounts for approximately 

seven months of operations. The overall annual amount of particulate and gaseous air 

pollution is also not anticipated to increase from current levels. Dust suppression techniques 

are utilized throughout Mine operations to manage fugitive particulate emissions. One 

common dust suppression technique is to apply water from sedimentation ponds to gravel 

roads throughout the Mine.

Specifically, it is estimated that the mining of the Section 10 lease tract coal in the Proposed 

Action would result in the use of approximately 23,183,000 gallons of diesel fuel. This 

equals approximately 260,000 short tons of CO2 emissions per year from the mining of the 

Section 10 lease tract coal.5

Direct emissions from equipment used on the Mine to mine the Section 10 lease tract coal in 

the Proposed Action were estimated using the average total hours per year from 2012 to 

2016 that each fleet-type was operated and the emission factors for that engine. Emission 

factors for hydrocarbons, NOx, CO, and PM were based on typical engine manufacturer 

guaranteed rates.6 As a conservative estimate, it was assumed that all HC/NOx was emitted 

as NOx. The emission factor for CO2 was derived from the amount of diesel fuel used. 

 

5 1 gallon diesel combusted = 22.50 pounds CO2

6 Calculations were completed using the formula: tons of emissions=(x g/kw-hr*y kw*z average total 

hours)/907,185 g
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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 24

Emission factors for SOX and TOC were taken from EPA’s AP-42, Compilation of Air 

Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources (USEPA, 1995).

These amounts are reported in Table 8 Direct Fleet Emissions from Section 10 Lease Tract 

Coal, tons.

Table 8 Direct Fleet Emissions from Section 10 Lease Tract Coal, tons

Fleet1 NOx

2,3 SOX4 CO2 PM102 PM2.52

Hydraulic Shovels 28 0.04 4.6 0.3 0.3

Rubber Tire Dozers 11 0.02 1.9 0.1 0.1

Track Dozers (D10T) 32 0.06 24.2 1.4 1.4

Track Dozers (D11T) 81 0.11 12.8 0.9 0.9

Front End Loaders 66 0.06 9.6 1.0 1.0

Motor Graders 43 0.08 26.1 1.6 1.6

Scrapers 23 0.05 23.4 1.0 1.0

Coal Haulers 263 0.25 36.6 6.0 6.0

Overburden Truck Fleet 700 0.65 97.5 16.0 16.0

Total 1,248 1.3 237 28 28

1 Calculations were completed using the formula: tons of emissions=(x lb/hp-hr*y hp*z average total 

hours)/2,000 lb

2 Emission factors from engine manufacturer data. Calculations were completed using the formula: 

tons of emissions=(x g/kw-hr*y kw*z average total hours)/907,185 g

3 Assumed value based on combined NOx and HC certifications, with the exception of the front-end

loaders, which had a direct NOx emission factor

4 Emission factors from EPA’s AP-42 Chapter 3 Sections 3 and 4 (USEPA, 1995). Calculations were 

completed using the formula: tons of emissions=(x lb/hp-hr*y hp*z average total hours)/2,000 lb

Based on historical ANFO usage for blasting coal, an estimated 1,200 pounds NOx, 140 

pounds SO2, and 4,600 pounds CO would be generated from the seven months of mining 

the Section 10 lease tract coal. Assuming the amount of diesel fuel combusted stays 

consistent, the amount of black carbon generated from mining the Section 10 lease tract 

coal in the Proposed Action would be approximately 21.2 tons.

Direct fugitive emissions are generated from mine and vehicle activities related to coal 

extraction, stockpiling, reclamation, and vehicle traffic. Table 9 Estimated Direct Fugitive 

Emissions from Section 10 Lease Tract Coal Activities shows the anticipated direct fugitive 

emissions related to mining the Section 10 lease tract coal. Details regarding the calculation 

of fugitive emissions are in Appendix A Air Emissions Information.
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 25

Table 9 Estimated Direct Fugitive Emissions from Section 10 Lease Tract Coal 

Activities

Fugitive Sources1 PM10, tons PM2.5, tons

Road Emissions 3,930 393

Truck Loading 4.5 0.1

Bull Dozing 74.0 2.2

Dragline 5.2 0.1

Grading 40.7 2.1

Active Storage Pile 0.4 0.4

Total 4,055 398

1 Emission Factors developed from factors in AP-42 Chapter 13 Section 2.2 and Chapter 11 Section 9 (USEPA, 

1995)

Please see Appendix A Air Emissions Information for details regarding direct emissions 

calculations. Table 10 Total Annual Direct Emissions shows the emissions including fleet 

emissions, permitted emission points, blasting and fugitive emissions from both the 

proposed mining of Section 10 lease tract coal and coal from other areas not in the Section

10 lease tract (non-federal coal). Compared to total North Dakota state emissions of 

hundreds of thousands of tons (see Section 5.2.1) the direct emissions from Falkirk are 

minor, even less than one percent of statewide emissions. As such, impacts of direct 

emissions from the Proposed Action would be minor and short-term, extending operations at 

the Falkirk Mine by seven months and staying in compliance with existing state air permits 

and NAAQS.

Table 10 Total Annual Direct Emissions

From Section 10 

lease tract coal, 

tons 

(A)

From coal not in 

Section 10 lease 

tract, tons 

(B)

Total Falkirk mine 

coal, tons 

(A+B)

NOX 1,248 892.0 2,140.8

SOX 1.4 1.0 2.4

CO 239.0 170.7 409.7

PM10 4,089.6 2,921.1 7,010.7

PM2.5 432.5 308.9 741.4

CO2 52,164 37,260.2 89,424.6

CH4 2.1 1.5 3.6

N2O 0.4 0.3 0.7

CO2e 52,290 37,350.3 89,640.8

Black carbon 21.2 15.2 36.4

4.2.2.2 Indirect Impacts

Indirect emissions resulting from the combustion of 1⁄2 Section 10 lease tract coal proposed 

in the Proposed Action were calculated based on historical emissions from each facility in 

which Falkirk Mine coal is combusted: Coal Creek Station and Spiritwood Station. Falkirk 

Mine is assumed to be the sole provider of coal to these facilities. Emission data was 
Chapter 4 March 2018 Supplemental Environmental 

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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 26

derived from the NDDH and Annual Emissions Inventory Reports (2012-2016). Anticipated 

Section 10 lease tract coal combusted at each facility was then estimated based on the 

average amount of coal used at each facility. These emission estimates are located in 

Table 11 Estimated Indirect Annual Emissions for Section 10 Lease Tract Coal in the

Proposed Action. 

Table 11 Estimated Indirect Annual Emissions for Section 10 Lease Tract Coal in the 

Proposed Action

Tons Emissions

PM10 99

PM2.5 40

SO2 8,916

NOx 4,827

CO 1,031

TOC 84

Mercury 0.22

Selenium 0.06

Total Metals 3.8

Total HAP VOC 2.0

HCl 9

HF 37

H2SO4 17

CO2 6,228,092

CH4 701

N2O 102

CO2e 6,258,480

Source: 

GRE Coal Creek Station Annual Inventory Reports 2012 - 2016 (GRE, 2013) (GRE, 2014) (GRE, 2015) (GRE, 

2016) (GRE, 2017) and Spiritwood Station Annual Inventory Reports 2014, 2015, 2016 (GRE, 2015) (GRE, 

2016) (GRE, 2017).

For comparison, the total indirect emissions from the combustion of all coal mined at the 

Falkirk Mine for the period 2012-2016 are shown in Table 6 Annual Greenhouse Gas 

Emissions at Coal Creek Station and Spiritwood Station 2012-2016, Table 3 Annual Criteria 

Pollutant Emissions at Coal Creek Station and Spiritwood Station 2012-2016, and Table 4

Annual Emissions for HAPs at Coal Creek Station and Spiritwood Station 2012-2016.

Emissions related to the Proposed Action would be minor and short-term by providing coal 

for seven months and maintaining compliance with state issued air permits and NAAQS. 

Note that Spiritwood Station began operations in 2014 so emissions in 2012 and 2013 are

solely from Coal Creek Station.

NDDH relies on regional monitors in the state monitoring system as shown in Figure 2

Ambient Air Monitoring Sites in North Dakota to demonstrate attainment of the NAAQS. 

North Dakota policy is that applicable facilities report emissions as required by their permit 

and that air quality attainment is maintained as demonstrated by the regional monitoring 

network. As such, facility specific ambient air quality modeling data is not available for 

demonstration of NAAQS attainment. North Dakota is in attainment of all criteria pollutants
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 27

as shown in Table 1 NAAQS Standard and Monitored Concentrations at Hanover and

Table 2 NAAQS Standard and Monitored Concentrations at TRNP-NU. Historical emissions 

may be compared to the monitored results to relate a level of ambient air quality associated 

with the reported or estimated emissions. The monitored ambient air is expected to continue 

to have consistent concentrations of monitored pollutants as related to the proposed action.

Coal Creek Station and Spiritwood Station operate under Title V Permits to Operate. The 

permits are legally-enforceable documents that detail what the facilities must do to control 

air pollutants. These permits are issued and enforced by the NDDH as required by the 

Clean Air Act. Each permit specifically documents limits of air pollutants for each emitting 

source unit. Reporting requirements are also described in the Title V permits. These permits 

can be found on the NDDH website for air quality permits.7

Advances in technology and efficiency have allowed coal-fired power plants across North 

Dakota to greatly reduce their emissions. Electrostatic precipitators and filters remove a 

majority of fly ash from the combusted coal. Low NOx burners have helped reduce nitrogen 

oxide emissions. 

Greenhouse gas emissions under the Proposed Action are expected to be minor and short 

term when compared to state emissions. GHG emissions from the combustion of Section 10 

lease tract coal at Coal Creek Station and Spiritwood Station together account for 

approximately 19% of the North Dakota GHG inventory and approximately 0.1% of the total 

US GHG inventory (USEPA, 2017) (USEPA, 2018).

In addition to CO2, other airborne pollutants are produced during the combustion of coal.

These emissions are reported to the NDDH on a yearly basis. The levels of NOx, SO2, and 

PM within the state of North Dakota have been steadily decreasing due to implementation of 

Best Available Retrofit Technology (BART) controls on BART eligible facilities such as Coal 

Creek Station. The North Dakota State Implementation Plan for Regional Haze specifies

that for Coal Creek Station BART for SO2 is achieved with modifications to the wet 

scrubbers and the addition of a unique coal drying operation using waste heat and BART for 

NOx to be achieved with low NOx burners with separated overfired air (LNC3+) (NDDH, 

2010). As part of the Supplement No. 2 to Regional Haze State Implementation Plan 

(NDDH, 2012) the NDDH reaffirmed its position regarding BART for NOx at Coal Creek 

Station. As a major source that began operations after the BART eligibility timeframe, 

Spiritwood Station is subject to Best Available Control Technology (BACT). The 

implementation of these technologies as well as the implementation of BART at other 

facilities in the state has resulted in a decreasing trend in both NOx and SO2 emissions from 

power plants in North Dakota as shown in Figure 3 Sulfur Dioxide and Nitrogen Oxides 

Emissions from Power Plants in North Dakota (USEPA, 2017).

 

7 http://www.ndhealth.gov/EHS/FOIA/AQPermits/AQPermitOperating.aspx
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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 28

Figure 3 Sulfur Dioxide and Nitrogen Oxides Emissions from Power Plants in North 

Dakota

Power plants within North Dakota report mercury emissions to the NDDH. Much like NOx

and SO2, improvements in technology have resulted in decreasing emissions of mercury.

The EPA’s Mercury and Air Toxics Standards (MATS) set emissions standards on all HAPs. 

Recently enacted Maximum Achievable Control Technology (MACT) Standards require the 

installation of mercury controls to achieve over 50 percent reduction from historical levels 

starting in June 2015. This effectively provides greater reduction of mercury emissions from 

North Dakota emission sources. More specifically, mercury controls at Coal Creek Station 

include use of bromine and a patented scrubber additive (GRE, 2016). Please refer to 

Table 5 Annual Mercury Emissions at Coal Creek Station and Spiritwood Station for a 

summary of mercury emissions at Coal Creek Station and Spiritwood station for the past five 

years.

Lignite coal from the Falkirk Mine would continue to be combusted at Coal Creek Station 

and Spiritwood Station even if the mining of the 1⁄2 Section 10 coal proposed by this 

document did not occur. As shown in Table 11 Estimated Indirect Annual Emissions for 

Section 10 Lease Tract Coal in the Proposed Action, emissions of CO2, criteria pollutants, 

and HAPS, from coal combustion would be minor and short term by providing coal for seven 

months and remaining in compliance with state issued permits and NAAQS.

Technological advances have recently been developed as the result of regulations. One 

such regulation is the New Source Performance Standards (NSPS). This regulation required 

0

50

100

150

200

250

1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016

Thousands of Tons

Source: EPA State Tier 1 inventory

NOX

SO2
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 29

new or modified facilities to meet emissions ratings and demonstrate compliance with the 

state implementation plan. The Acid Rain Program created under Title IV of the 1990 CAA 

Amendments required emission reductions of SO2 and NOx. The MATS rule previously 

discussed in Section 3.2.3 required similar reductions in HAPs. In order to continue 

operating, Coal Creek Station and Spiritwood Station must meet the requirements outlined 

in those regulations. As shown in Table 5 Annual Mercury Emissions at Coal Creek Station 

and Spiritwood Station 2012-2016, the indirect mercury emissions from Falkirk Mine coal 

show a decreasing trend over the past five years. As technologies continue to advance, it is 

reasonable to assume that further reductions in emissions could be achieved. Because 

future advancements and responses to regulation are facility-specific and have not yet been 

determined, it is reasonable to assume the technological advances would continue the past 

trend of reducing emissions.

4.2.3 No Action

Under the No Action Alternative, the ASLM would not approve the mining plan to recover the 

coal in 1⁄2 Section 10. Impacts from direct and indirect emissions have resulted from current 

mining activity and, therefore, under this alternative, direct and indirect emissions would be 

similar to the Proposed Action but would not be extended for an additional seven months.
Supplemental Environmental Assessment March 2018 Chapter 6

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA

30

Chapter 5

Cumulative Impacts

5.1 Introduction

Cumulative impacts are defined as “the impact on the environment which results from the 

incremental impact of the action when added to other past, present, and reasonably 

foreseeable actions regardless of what agency (federal or non-federal) or person undertakes 

such other actions. Cumulative impacts can result from individually minor, but collectively 

significant actions taking place over a period of time” (40 CFR 1508.7). This chapter 

incorporates Chapter 5.0 of the BLM EA by reference8 and only provides supplemental 

information regarding air quality where relevant to the supplemental analysis presented in 

this document.

5.1.1 Analysis Areas

For the purposes of this analysis, the temporal span of the Proposed Action represents the 

time during which the Section 10 lease tract would be mined (i.e., seven months). The 

geographic extent of cumulative impacts includes McLean County and adjacent counties 

Mercer County and Oliver County. No significant, adverse, cumulative effects were identified 

in the cumulative effects analysis.

5.1.2 Past, Present, and Reasonably Foreseeable Actions 

Currently, there are five operating surface coal mines in North Dakota that produced 

approximately 29.18 million tons of coal in 2016: Beulah Mine, Center Mine, Coyote Creek

Mine, Falkirk Mine, and Freedom Mine. Section 5.1 of the BLM EA is incorporated by 

reference and provides a detailed description of each mine (BLM, 2017). Table 12 Summary

of 2016 and Anticipated Future Lignite Production in North Dakota presents a summary of 

the annual production of each mine in 2016. Future production at each of these mines is 

expected to be consistent with 2016 levels except for Beulah Mine, which ended its coal 

supply contract with Coyote Power station in April, 2016 and Coyote Creek Mine, which 

began production in April 2016 and had its first year of full production in 2017. The 

anticipated future production levels for North Dakota surface mining is also shown in 

Table 12 Summary of 2016 and Anticipated Future Lignite Production in North Dakota and is 

not appreciably different from 2016 production levels. Production levels at Falkirk Mine are 

expected to be the same for the Proposed Action.

 

8

 The BLM EA is available on their eplanning website at: https://eplanning.blm.gov/epl-frontoffice/projects/nepa/67410/105731/129311/DOI-BLM-MT-C030-2016-0020-EA.pdf
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 31

Table 12 Summary of 2016 and Anticipated Future Lignite Production in North Dakota

Surface Mine

2016 Annual Coal 

Production, 

MMtons

Anticipated Future 

Coal Production, 

MMtons

Description of Anticipated 

Production Changes

Beulah Mine 2.5 0.5 Change in supply contracts

Center Mine 3.83 3.83 No anticipated change

Coyote Creek Mine 1.49 2.5 2016 production represents 

a partial year

Falkirk Mine 7.24 7.24 Additional seven months 

mine life from production of

Section 10 lease tract coal. 

No change to annual 

production.

Freedom Mine 14.12 14.12 No anticipated change

Total 29.18 28.19

Source:

USEIA 2016 Annual Coal Report (EIA, 2017) and North Dakota Mine Operators Data (BLM, 2017).

Coal Creek Station and other coal-fired power plants in the vicinity of the Section 10 lease 

tract are considered to be major stationary point sources (i.e., more than 100 TPY) for 

federally listed criteria pollutants (NDDH, 2017). A summary of the coal-fired power plants 

located in the area and considered to be major stationary point sources for CO, NOx, VOCs, 

PM10, and SO2 is presented in Table 13 Coal Fired Power Plants in North Dakota (USEPA, 

2017). The net electrical generation of each source is expected to remain relatively constant 

compared to 2014, except for Spiritwood station, which commenced operations in 2014. 

However, because Spiritwood is one of the smaller sources, the overall net generation in 

North Dakota is expected to be similar to that in 2014. Thus, overall impacts from electrical 

generation are expected to be relatively constant in the future.

One other major stationary source in the cumulative impact assessment area is the Dakota 

Gasification Company. The Dakota Gasification Company has added a urea manufacturing 

facility to the existing plant site, which is expected to begin operations in early 2018. This 

project adds to particulate and gaseous air pollutants in the area. As a major modification, 

direct impacts from the urea facility were addressed in PSD permitting and found to have no 

significant adverse impact (DGC, 2013). As the NAAQS levels have not been exceeded 

during the time of the Mine’s operation, continued mining operations on a similar scale for 

seven additional months over the life of the mine are unlikely to cause a cumulative impact 

large enough to exceed the NAAQS standards even when combined with future projects, as 

those projects must also be permitted through the NDDH and be in compliance with the 

state implementation plan.
Chapter 4 March 2018 Supplemental Environmental 

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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 32

Table 13 Coal Fired Power Plants in North Dakota

Nameplate Capacity, 

MW

2014 net Generation, 

MWh

Antelope Valley 869.8 5,838,431 

Coal Creek Station 1,211.6 8,880,798 

Coyote 450.0 2,745,038 

Leland Olds 656.0 3,453,455 

Milton R Young 734.0 4,557,992 

R M Heskett 203.0 547,268 

Spiritwood Station 106.2 32,125 

Stanton 191.2 5,838,431 

Source: 

USEPA eGRID2014 (USEPA, 2017)

5.2 Cumulative Impacts

5.2.1 Air Quality and Climate Change

5.2.1.1 Criteria and HAPs Pollutants

Air emissions from past and present actions are currently considered in the air quality 

monitoring data in the state of North Dakota. As such, any cumulative air quality impacts 

from past and present actions are reflected in the local air quality monitoring data at the 

NDDH’s Hanover ambient air monitoring site. The 2016 reported levels did not exceed any 

NAAQS (see Table 1 NAAQS Standard and Monitored Concentrations at Hanover). 

Additionally, the state of North Dakota has been classified as in attainment for NAAQS for all 

criteria pollutants that are classifiable in North Dakota. The Proposed Action would not 

increase production at the Mine or combustion at any facility receiving coal from the Falkirk

Mine. As a result, the Proposed Action will extend the life of the mine by seven months, 

however, no changes to annual emissions of criteria pollutants or HAPs are expected from 

the Proposed Action. For perspective, the contribution of emissions from the Proposed 

Action in comparison with total reported statewide emissions in North Dakota is provided in 

Table 14 North Dakota and Section 10 Lease Tract Emissions. It is important to note that 

the reportable statewide emissions do not generally include fugitive emissions or tailpipe 

emissions, both of which are included in the direct emissions from the Proposed Action. 

Therefore, the relative contribution of direct and indirect emissions from the Proposed Action 

is overstated. 
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 33

Table 14 North Dakota and Section 10 Lease Tract Emissions

2016 

Reported1

Total North 

Dakota 

Emissions, 

tons

Average Direct 

Emissions2

Section 10

Lease Tract, 

tons

Average 

Indirect 

Emissions 

Section 10

Lease Tract, 

tons

Percent3

Direct + 

Indirect 

Section 10 

Lease Tract 

Emissions 

CO 334,632 239.0 1,031 0.4%

NOx 175,321 1248.8 4,827 3.5%

PM10 651,782 4089.6 99 0.6%

PM2.5 134,879 432.5 40 0.4%

SO2 152,506 1.4 8,916 5.8%

VOC 550,129 n/a 84 0.02%

Source:

USEPA FLIGHT tool (USEPA, 2018) and USEPA State Tier 1 Inventory (USEPA, 2017) for statewide emissions. 

Direct and indirect emissions are as presented in Table 10 and Table 11

1 Reported emissions generally do not include fugitive emissions or tailpipe emissions.

2 Direct emissions calculated for this EA include fugitive dust and tailpipe emissions.

3 Percent is calculated using available reportable emissions data for the State of ND, which does not include 

fugitive dust emissions or tailpipe emissions, which are included in direct Section 10 lease tract emissions. 

Therefore, percentages of statewide emissions should be considered high-end estimates.

Contributions to the measured criteria pollutant levels at the Hanover monitoring site are 

expected to remain the same in the future as they were when the 2016 results were 

measured. As emissions rates would be similar to existing operations but extended for 

seven months under the Proposed Action compared to the No Action, no significant 

cumulative impact to air quality would occur. 

5.2.1.2 Greenhouse Gases and Climate Change

The EPA completes an annual inventory of greenhouse gases across the U.S. The most 

recent inventory shows a general trend of decreasing greenhouse gas emissions, with a 2.3

percent decrease from 2014 to 2015 (USEPA, 2017). In addition, 2015 emission levels were 

10 percent below 2005 levels. The 2015 total U.S. greenhouse gas emissions equaled 

6,587 million metric tons of carbon dioxide equivalents. Electricity generation was the largest 

source of these emissions, comprising 30 percent of the total, followed by transportation (27 

percent), industry (21 percent), and agriculture (9 percent) (USEPA, 2017). The US Energy 

Administration tracks carbon dioxide emissions by sectors and by state. The 2015 total 

North Dakota carbon dioxide emissions was 57.1 million metric tons of carbon dioxide 

(USEIA, 2017), which represents a 2.6 percent decrease from 2014. Electricity generation is 

the largest source of carbon dioxide emissions in North Dakota comprising 52 percent of the 

total, followed by industry (28 percent), and transportation (16 percent). Direct emissions 

from the Proposed Action account for 0.2 percent of total carbon dioxide emissions from 

North Dakota and 0.0009% of carbon dioxide equivalents from the entire US. Indirect 

emissions from the Proposed Action account for approximately 19% of the total carbon 

dioxide emissions from North Dakota and approximately 0.1% of carbon dioxide equivalents 

from the entire US.
Chapter 4 March 2018 Supplemental Environmental 

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The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 34

The EPA prepared a summary of available information regarding black carbon emissions. 

The 2005 total estimated black carbon emissions in the US was approximately 5.5 million 

tons. Black carbon emissions from the Proposed Action comprise less than 0.0004 percent 

of the total US annual black carbon emissions (USEPA, 2012).

Though total greenhouse gas emission levels from mining operations and emissions from 

Coal Creek Station and Spiritwood Station have been calculated for this EA (refer to 

Table 10 Total Annual Direct Emissions and Table 6 Annual Greenhouse Gas Emissions at 

Coal Creek Station and Spiritwood Station 2012-2016), current limitations in the climate

change earth systems modeling make it impossible to directly link the emissions from a 

single action to an effect on climate change. The rate of contribution to cumulative climate 

change, however, would be similar to the rate of existing operations under both the 

Proposed Action and the No Action. Emissions would be extended for seven months under 

the Proposed Action.

Chapter 6

Coordination and Consultation

6.1 Agencies and People Consulted

No additional people or agencies beyond those identified in Chapter 6.1 of the BLM EA9

were consulted prior to and during the preparation of this Supplemental EA.

6.2 Preparers and Participants

Table 15 List of Preparers shows a list of the preparers of this Supplemental EA and those 

who participated in the preparation of this Supplemental EA from OSMRE. 

Table 15 List of Preparers

Organization Name Title/ Project Responsibility

OSMRE Gretchen Pinkham Natural Resource Specialist/ Project Manager, 

internal scoping, review of Supplemental EA

OSMRE Erica Trent Natural Resource Specialist/MPDD Coordinator

OSMRE Cecil Slaughter Technical Reviewer

Table 16 Contractors shows a list of the preparers of this Supplemental EA and those who 

participated in the preparation of this Supplemental EA from the third party consultants Barr 

Engineering Co.

 

9 The BLM EA is available on their eplanning website at: https://eplanning.blm.gov/epl-frontoffice/projects/nepa/67410/105731/129311/DOI-BLM-MT-C030-2016-0020-EA.pdf
Supplemental Environmental Assessment March 2018 Chapter 4

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA 35

Table 16 Contractors

Organization Name Title/ Project Responsibility

Barr Engineering Co. Nadine Czoschke, PhD Senior Environmental Scientist/Project Manager, 

Supplemental EA author

Barr Engineering Co. Rachael Shetka Senior Environmental Specialist/Supplemental EA 

author

Barr Engineering Co. Amar Patel Air Quality Scientist/Supplemental EA author
Supplemental Environmental Assessment March 2018 References

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA

36

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CATF, 2009. The Carbon Dioxide-Equivalent Benefits of Reducing Black Carbon Emissions 

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CCSP, 2009. Climate Literacy – The Essential Principles of Climate Sciences. [hereinafter 

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Energy.

GRE, 2015. Spiritwood Station Annual Emissions Inventory for 2014, s.l.: Great River 

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Energy.

GRE, 2016. Great River Energy North Dakota 19 Year Plan Report 2016-2025, s.l.: North 

Dakota Public Service Commission.

GRE, 2016. Spiritwood Station Annual Emissions Inventory for 2015, s.l.: Great River 

Energy.

GRE, 2017. Coal Creek Station Annual Emissions Inventory for 2016, s.l.: Great River 

Energy.

GRE, 2017. Spiritwood Station Annual Emissions Inventory for 2016, s.l.: Great River 

Energy.
Supplemental Environmental Assessment March 2018 References

The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 37

IPCC, 2014. Climate Change 2014: Synthesis Report. Contribution of Working Groups I, II 

and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate 

Change, Geneva, Switzerland: IPCC.

NDDH, 2010. North Dakota State Implementation Plan for Regional Haze, s.l.: North Dakota 

Department of Health.

NDDH, 2012. Supplement 2 to North Dakota State Implementation Plan for Regional Haze, 

s.l.: North Dakota Department of Health.

NDDH, 2013. Annual Report – North Dakota Ambient Air Quality Monitoring Data Summary 

2012, s.l.: North Dakota Department of Health.

NDDH, 2014. Annual Report – North Dakota Ambient Air Quality Monitoring Data Summary 

2013, s.l.: North Dakota Department of Health.

NDDH, 2014. North Dakota Regional Haze State Implementation Plant Periodic Progress 

Report, s.l.: North Dakota Department of Health.

NDDH, 2015. Annual Report – North Dakota Ambient Air Quality Monitoring Program –

Network Plan and Five Year Network Assessment with Data Summary, s.l.: North 

Dakota Department of Health.

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Company, s.l.: North Dakota Department of Health.

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Network Plan with Data Summary, s.l.: North Dakota Department of Health.

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Report Network Plan with Data Summary, s.l.: North Dakota Department of Health.

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Policy Act. US Department of the Interior. Available online http://www.google.com/ur . 

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s.l.: Electric Power Research Institute.

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Reductions, s.l.: https://obamawhitehouse.archives.gov/blog/2015/07/02/estimatingbenefits-carbon-dioxide-emissions-reductions.

UNEP, 2013. Global Mercury Assessment 2013: Sources, Emissions, Releases and 

Environmental Transport, s.l.: United Nations Environment Programme.

USEIA, 2017. North Dakota Carbon Dioxide Emissions, s.l.: 

https://www.eia.gov/environment/emissions/state/ (accessed Dec 2017).

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Point and Area Sources, s.l.: US Environmental Protection Agency.
References March 2018 Supplemental Environmental 

Assessment

The Falkirk Mining Company Federal Coal Mining Plan Supplemental EA 38

USEPA, 2012. Report to Congress on Black Carbon, s.l.: US Environmental Protection 

Agency.

USEPA, 2015. Fact sheet: clean power plan state roles, s.l.: s.n.

USEPA, 2016. Pollutants and Sources, s.l.: http://www3.epa.gov/airtoxics/pollsour.html.

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Available at: https://19january2017snapshot.epa.gov/climate-impacts/climate-impactsgreat-plains_.html#Reference 1

[Accessed 4 January 2018].

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Agency: accessed Dec 2017; https://www.epa.gov/air-emissions-inventories/airpollutant-emissions-trends-data.

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Trends, s.l.: US Environemental Protection Agency.

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Geological Survey.
Supplemental Environmental Assessment March 2018 Appendix A

The Falkirk Mining Company Federal Coal Lease by Application Supplemental EA

Appendix A

Air Emissions Information
Emission Factors for Falkirk Mine Emissions Calculations

AP42, Chapter 13, Section 2.2 Unpaved Roads 

Equation 1a

a b EF = k * (s/12) * (W/3) where, 

k, a, and b are empirical constants from AP 42 Section 13.2.2 Table 13.2.2‐2 E = size‐specific emission factor (lb/VMT) 

s = surface material silt content (%) from AP 42 Section 13.2.2 Table 13.2.2‐1 W = mean vehicle weight (tons) 

AP42, Section 13.2, Introduction to Fugitive Dust Sources, Table 13.2.2‐1 and 13.2.2‐2 

Constant PM PM10 PM2.5 Comment 

s (%) 8.4 8.4 8.4 Western surface coal mining Haul road to/from pit 

k (lb/VMT) 4.9 1.5 0.15 No comment 

a 0.7 0.9 0.9 No comment 

b 0.45 0.45 0.45 No comment 

AP42, Section 11.9 Western Surface Coal Mines, Table 11.9‐1 

Operation PM15 PM10 PM2.5 Units 

Truck Loading 0.01 0.01 0.00 lb/ton 

Bulldozing 17.06 12.80 0.38 lb/hr 

Dragline 0.02 0.01 0.00 lb/cubic yard (assume 1.2 ton/cubic yd density) 

Grading 2.57 1.54 0.08 lb/vmt 

Active storage pile 9.65 9.65 9.65 lb/acre‐hr (assume PM=PM10=PM2.5) 

AP42, Section 11.9 Western Surface Coal Mines, Table 11.9‐3 and Table 11.9‐5 

Description Value Constant Unit Comment 

Horizontal area A ft2 Blasting depth # 70 ft. Not for vertical face of a bench 

Material moisture content 17.8 M % Coal loading 

Material moisture content 10.4 M % Bulldozing coal 

Material moisture content 3.2 M % Dragline 

Material silt content 8.4 s % No comment 

Wind speed 13.4 u mph No comment 

Drop height 28.1 d ft No comment 
Emission Factors for Falkirk Mine Emissions Calculations (cont.)

AP42, Chapter 13, Section 3.3, Table 13.3‐1 Emission Factors for Detonation of Explosives 

Composition Explosive CO NOx SO2 Unit 

4,5 Ammonium nitrate with 5.8‐ 8% fuel oil ANFO 67 17 2 lb/ton 

Table C‐1 and C‐2 to Subpart C of40 CFR Part 98—DefaultHigh Heat Values for Various Types of Fuel 

Fuel type HHV Unit 

Lignite 14.21 mmBtu/ton 

Distillate Fuel Oil No. 2 0.14 mmBtu/gallon 

Table C‐1 and C‐2 to Subpart C of40 CFR Part 98

Default CO2, CH4, and N2O Emission Factors for Various Types of Fuel 

Fuel type CO2 CH4 N2O CO2e Unit 

Lignite 97.72 1.10E‐02 1.60E‐03 kg/mmBtu 

Lignite 1.531 1.72E‐04 2.51E‐05 1.54 ton/ton 

Distillate Fuel Oil No. 2 73.96 3.00E‐03 6.00E‐04 kg/mmBtu 

Distillate Fuel Oil No. 2 0.011 4.56E‐07 9.13E‐08 0.011 ton/gal 

Global Warming Potential ‐ Table A‐1 40 CFR 98

Greenhouse gas GWP 

CO2 1 

CH4 25

N2O 298
Emission Factors for Falkirk Mine Emissions Calculations (cont.)

Horsepower Kilowatt Fleet Vehicle Types Model

Emission

Standard

HC Exhaust

(g/kw‐hr)a

Ox Exhaust

(g/kw‐hr)a

NMHC

+NOX

Exhaust

(g/kw‐hr)a

CO Exhaust

(g/kw‐hr)a

PM Exhaust

(g/kw‐hr)a

SOX

lb/hp‐hrb

CO2

lb/hp‐hrb

TOC

lb/hp‐hrb

Black

carbon

c

533 398 M. grader 24M Tier 3 n/a n/a 4 2.4 0.15 1.21E‐05 1.08 12.555 0.1125

580 433 track dozer D10T Tier 3 n/a n/a 3.7 2.8 0.16 1.21E‐05 1.08 12.555 0.12

850 634 track dozer D11T Tier 2 n/a n/a 5.7 0.9 0.06 1.21E‐05 1.16 7.05 0.045

1969 1468 OB truck 789D Tier 2 n/a n/a 6.3 1.6 0.16 1.21E‐05 1.16 7.05 0.12

2337 1743 OB truck 793D Tier 2 n/a n/a 7.9 1.1 0.18 1.21E‐05 1.16 7.05 0.135

302 225 M. grader 16M Tier 3 n/a n/a 3.7 2.7 0.16 1.21E‐05 1.08 12.555 0.12

600 447 scraper 657G Tier 3 n/a n/a 3.4 3.4 0.15 1.21E‐05 1.16 7.05 0.1125

1463 1091 front end loader 994F Tier 1 0.4 8.3 n/a 1.2 0.13 1.21E‐05 1.16 7.05 0.0975

907 676 rt dozer & OB shovels 854K Tier 2 n/a n/a 5.4 0.9 0.06 1.21E‐05 1.16 7.05 0.045

2100 1566 coal hauler 3516B Tier 2 n/a n/a 7.9 1.1 0.18 1.21E‐05 1.16 7.05 0.135

a

from engine manufacturer data

b

from AP‐42 Table 3.3‐1 and Table 3.4‐1

c

Clean Air Task Force, 2009; Table 5. Assumption that 75% of diesel particulate matter is black carbon
Emission Factors for Falkirk Mine Emissions Calculations (cont.)

Permitted Emission Units Emission Limits at Falkirk Mine 

Unit # Description Rate, ton/hr Emission Limit, lb/hr PM

EU1 Truck dump 4000 1 

EU2‐3 NICO apron feeders 4000 2 

EU4‐5 Primary crushers 4000 2 

EU6 72" conveyor 4000 1 

EU7‐8 Syntron MF‐1000B Feeders 4000 2 

EU9‐10 Secondary crushers 4000 2 

EU11 72" Silo feed conveyor 4000 1 

EU12 Coal storage silo 

EU13 Cable Belt conveyor 1800 not operating 

Particle size range Fraction 

PM10 0.75 

PM2.5 0.03 

AP‐42 Table 11.9‐01 most conservative fraction for coal 
Emissions Calculation Inputs for Falkirk Mine Fugitive Dust and Tailpipe Emissions

Based on fuel usuage and metered hours

Vehicle Type Distance Traveled Unit

Average

weight Capacity Unit Model PM EF PM10 EF PM2.5 EF Unit

Light vehicles 400,000 miles/yr 5 n/a tons Various 4.804 1.369 0.137 lb/vmt

Coal Haulers 830,000 miles/yr 461 200 tons Kress 200C 36.786 10.486 1.049 lb/vmt

Cat End Dump Truck Fleet 3,200,000 miles/yr 518 190 tons CAT 793D 38.763 11.049 1.105 lb/vmt

Miscelaneous 100,000 miles/yr 30 n/a tons Various 10.759 3.067 0.307 lb/vmt

Total 4,530,000 miles/yr n/a n/a n/a n/a n/a n/a n/a n/a

Annual Fuel Usage, 2012‐2016

Year Diesel Usage Unit CO2 CH4 N2O CO2e Unit

2012 8,216,759 gallons 92,444 4 1 92,668 tons

2013 7,638,060 gallons 85,934 3 1 86,141 tons

2014 7,930,836 gallons 89,228 4 1 89,443 tons

2015 8,238,261 gallons 92,686 4 1 92,910 tons

2016 7,717,800 gallons 86,831 4 1 87,041 tons

Total 39,741,716 gallons 447,123 18 4 448,204 tons

Annual VMT and diesel data provided by Falkirk Mining.
Blasting Emissions at Falkirk Mine

ANFO Amount Unit

2012 275,000.0 lbs

2013 225,000.0 lbs

2014 260,000.0 lbs

2015 260,000.0 lbs

2016 150,000.0 lbs

Total 1,170,000.0 lbs

Annual ANFO data provided by Falkirk Mining.

Year CO NOX SO2 Unit

2012 4.6 1.2 0.14 TPY

2013 3.8 1.0 .011 TPY

2014 4.4 1.1 0.13 TPY

2015 4.4 1.1 0.13 TPY

2016 2.5 0.6 0.08 TPY

Annual 3.9 1.0 0.12 TPY

Calculation methodology for CO, NOX, and SO2 follows AP42, Chapter 13, Section 3.3, which provides an emission factor for pounds of

pollutants per ton of ANFO combusted.
Falkirk Mine Total Mine Historical Emissions

Whole Mine Direct Fleet Emissions, Average of 2012‐2016, tons

Equipment NOX SOX CO PM10 PM2.5

Hydraulic Shovels 48 0.1 8 0.5 0.5

Rubber Tire Dozers 19 0.0 3 0.2 0.2

Track Dozers(D10T) 55 0.1 42 2.4 2.4

Track Dozers(D11T) 139 0.2 22 1.5 1.5

F.E. Loaders 113 0.1 16 1.8 1.8

Motor Graders 74 0.1 45 2.8 2.8

Scrapers 40 0.1 40 1.8 1.8

Coal Haulers 450 0.4 63 10.3 10.3

OB Truck Fleet 1,200 1.1 167 27.3 27.3

Total 2,140 2.2 406 48.5 48.5

Whole Mine Fugitive Emissions, average of 2012‐2016, tons

Fugitive Sources PM10 PM2.5

Road Emissions 6,737 674

Truck Loading 7.8 0.2

Bull Dozing 127 4

Dragline 8.9 0.2

Grading 70 4

Active Storage Pile 0.8 0.8

Total 6,951.5 682.2

Average Emissions per Year Whole Mine, 2012‐2016, tons

Pollutant EU 1‐11

Tailpipe

emissions Blasting Fugitives Total

NOX n/a 2,139.8 1.0 n/a 2,140.8

SOX n/a 2.2 0.1 n/a 2.4

CO n/a 405.8 3.9 n/a 409.7

PM10 10.7 48.5 n/a 6,951.5 7,010.7

PM2.5 10.7 48.5 n/a 682.2 741.4

CO2 n/a 89,424.6 n/a n/a 89,424.6

CH4 n/a 3.6 n/a n/a 3.6

N2O n/a 0.7 n/a n/a 0.7

CO2e n/a 89,640.8 n/a n/a 89,640.8

Black carbon n/a 36.4 n/a n/a 36.4

Months Coal Source

7 Section 10 coal

5 non-section 10 coal
Falkirk Mine Section 10 Federal Coal Direct Emissions

Section 10 Direct Fleet Emissions, tons

Equipment NOX SOX CO PM2.5

Hydraulic Shovels 28 0.04 4.6 0.3

Rubber Tire Dozers 11 0.02 1.9 0.1

Track Dozers(D10T) 32 0.06 24.2 1.4

Track Dozers(D11T) 81 0.11 12.8 0.9

F.E. Loaders 66 0.06 9.6 1.0

Motor Graders 43 0.08 26.1 1.6

Scrapers 23 0.05 23.4 1.0

Coal Haulers 263 0.25 36.6 6.0

OB Truck Fleet 700 0.65 97.5 16.0

Total 1248 1.3 237 28

Section 10 Fugitive Emissions, tons

Fugitive Sources PM10 PM2.5

Road Emissions 3,930.1 393.0

Truck Loading 4.5 0.1

Bull Dozing 74.0 2.2

Dragline 5.2 0.1

Grading 40.7 2.1

Active Storage Pile 0.4 0.4

Total 4,055.0 398.0

Total Direct Emissions

Pollutant

From Section 10

coal, tpy

[A]

From non‐

Section 10 coal,

tpy

[B]

Total Falkirk

mine coal, tpy

[A+B]

Average

Historical Falkirk

Mine, tpy

Change in total

Falkirk Mine

emissions,tpy

NOX 1,248.8 892.0 2,140.8 2,140.8 0

SOX 1.4 1.0 2.4 2.4 0

CO 239.0 170.7 409.7 409.7 0

PM10 4,089.6 2,921.1 7,010.7 7,010.7 0

PM2.5 432.5 308.9 741.4 741.4 0

CO2 52,164.3 37,260.2 89,424.6 89,424.6 0

CH4 2.1 1.5 3.6 3.6 0

N2O 0.4 0.3 0.7 0.7 0

CO2e 52,290.4 37,350.3 89,640.8 89,640.8 0

Black carbon 21.2 15.2 36.4 36.4 0
Indirect Emissionsfrom Combustion of Falkirk Mine Coal

Annual Indirect GHG Emissions based on coal combusted at Coal Creek Station and Spirit Wood, 2012‐2016

Year Coal Combusted Unit CO2 CH4 N2O CO2e Unit

2012 7,225,823 tons 11,060,356 1,245 181 11,114,323 tons

2013 6,927,877 tons 10,604,299 1,194 174 10,656,040 tons

2014 7,026,579 tons 10,755,379 1,211 176 10,807,858 tons

2015 7,211,153 tons 11,037,901 1,242 181 11,091,758 tons

2016 6,484,546 tons 9,925,705 1,117 163 9,974,135 tons

Average 6,975,196 tons 10,676,728 1,202 175 10,728,823 tons

Annual Total Indirect Emissions based on coal combusted at Coal Creek Station and Spirit Wood, 2012‐2016

Year Coal Combusted Unit PM10 PM2.5 SO2 NOx CO TOC Unit

2012 7,225,823 tons 194 78 16,272 8,655 1,807 145 tons

2013 6,927,877 tons 185 74 15,455 8,008 1,732 139 tons

2014 7,026,579 tons 193 77 15,865 8,042 1,836 144 tons

2015 7,211,153 tons 144 58 15,510 8,812 1,731 155 tons

2016 6,484,546 tons 134 54 13,317 7,857 1,731 140 tons

Average 6,975,196 tons 170 68 15,284 8,275 1,767 144 tons

Year Coal Combusted Unit Hg Se Total Metals Total HAP VOC HCl HF H2SO4 Unit

2012 7,225,823 tons 0.40 0.02 6.61 3.12 0.75 79.00 21.50 tons

2013 6,927,877 tons 0.45 0.02 6.28 2.99 0.72 75.50 19.50 tons

2014 7,026,579 tons 0.45 0.02 6.79 2.99 3.42 75.80 69.60 tons

2015 7,211,153 tons 0.45 0.23 7.00 4.05 37.80 43.80 21.25 tons

2016 6,484,546 tons 0.17 0.20 5.98 3.59 34.85 39.70 17.55 tons

Average 6,975,196 tons 0.38 0.10 6.53 3.35 15.51 62.76 29.88 tons
Indirect Emissionsfrom Combustion of Falkirk Mine Coal (cont.)

Annual Section 10 Coal combusted at Coal Creek Station and Spirit Wood Indirect Emissions, over life of project

Year Coal Combusted Unit PM10 PM2.5 SO2 NOx CO VOCa Unit

n/a 4,068,864 tons 99 40 8,916 4,827 1,031 84 tons

a Assumes TOC=VOC

Year Coal Combusted Unit Hg Se Total Metals Total HAP VOC HCl HF H2SO4 Unit

n/a 4,068,864 tons 0.22 0.06 3.81 1.95 9.04 36.61 17.43 tons

Year Coal Combusted Unit CO2 CH4 N2O CO2e Unit

n/a 4,068,864 tons 6,228,092 701 102 6,258,480 tons
Comparison of Direct and Indirect to North Dakota and US Emissions

All emissions

in tons

2016 ND, from

State Tier 1

Section 10

Direct

Section 10

Indirect

Section 10, %

(Direct+Indirect)

Anticipated% change to State

Emissionsfrom ProposedAction

CO 334,632 239.0 1,031 0.4% 0%

NOx 175,321 1248.8 4,827 3.5% 0%

PM10 651,782 4089.6 99 0.6% 0%

PM2.5 134,879 432.5 40 0.4% 0%

SO2 152,506 1.4 8,916 5.8% 0%

VOC 550,129 n/a 84 0.02% 0%

North Dakota Emissions referenced from EPA State Tier 1 inventory; https://www.epa.gov/air‐emissions‐inventories/air‐pollutant‐emissions‐trends‐data

All emissions in mm tons CO2e % of ND % of US Black carbona % of ND % of US

North Dakota Total 33.6 0.003

US Total 5,764 5.5

Section 10 Direct

Emissions

0.05 0.2% 0.0009% 2.12E‐05 0.8% 0.0004%

Section 10 Indirect

Emissions

6.3 19% 0.1%

Data Extracted from EPA's FLIGHT Tool (http://ghgdata.epa.gov/ghgp)

a

Clean Air Task Force, 2009; Table 5. Assumption that 75% of diesel particulate matter is black carbon