BNI Coal Ltd.

LBA Tracts Federal Coal Lease-by-Application

Serial Number: NDM-105513

Supplemental Environmental Assessment

April 2023

US Department of the Interior

Office of Surface Mining Reclamation and Enforcement

Program Support Division

One Denver Federal Center

Lakewood, CO 80225

Phone (303) 236-2900
Supplemental Environmental Assessment April 2023 Table of Contents

BNI Coal Ltd. Federal Coal Lease by Application i

Table of Contents

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

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

1.2 Background .....................................................................................................................5

1.2.1 Milton R. Young Station................................................................................................6

1.3 Regulatory Framework and Necessary Authorizations ................................................6

1.4 Purpose and Need for the Proposed Action..................................................................8

1.5 Outreach and Issues Identification ................................................................................8

1.5.1 Scoping ........................................................................................................................8

1.5.2 Outreach.......................................................................................................................8

Chapter 2 Proposed Action and Alternatives ..........................................................................10

2.1 Introduction ...................................................................................................................10

2.1.1 Proposed Action .........................................................................................................10

2.1.2 No Action....................................................................................................................10

Chapter 3 Affected Environment and Impacts.........................................................................12

3.1 Introduction ...................................................................................................................12

3.2 Past, Present, and Reasonably Foreseeable Future Actions .....................................12

3.3 Climate Change and Social Cost of Greenhouse Gases ............................................13

3.3.1 Trends in Global, United States, and North Dakota Greenhouse Gas Emissions........14

3.3.2 Social Cost of Greenhouse Gases..............................................................................17

3.3.3 Proposed Action .........................................................................................................19

3.3.4 No Action....................................................................................................................20

3.4 Biological Assessment .................................................................................................22

3.5 Mercury Deposition.......................................................................................................24

3.5.1 Proposed Action .........................................................................................................27

3.5.2 No Action....................................................................................................................30

3.6 Selenium Deposition.....................................................................................................31

3.6.1 Proposed Action .........................................................................................................33

3.6.2 No Action....................................................................................................................35

Chapter 4 List of Preparers.......................................................................................................36

Chapter 5 References................................................................................................................37
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BNI Coal Ltd. Federal Coal Lease by Application ii

List of Tables

Table 3-1 Proposed Action Summary for Potential GHG Emissions from Mining LBA 

Tracts and Coal Combusted at an Electric Generating Utility......................................13

Table 3-2 SC-GHGs Associated with Mining LBA Tracts and Coal Combustion under the 

Proposed Action .........................................................................................................20

Table 3-3 SC-GHGs for the No-Action Alternative of Coal Combusted at an Electric 

Generating Utility associated with the No-Action Alternative.......................................21

Table 3-4 Estimated Background Total (wet + dry) Mercury Deposition to the Area ...................26

Table 3-5 Annual Total Indirect Mercury Emissions at Milton R. Young Station, 2015-2019 .......27

Table 3-6 Potential Incremental Total (wet + dry) Mercury Deposition within 50-Kilometer 

Radius of the Milton R. Young Station ........................................................................28

Table 3-7 Estimated Incremental Surface Water Mercury Concentrations Associated with 

Potential Total Mercury Deposition from the Milton R. Young Station .........................30

Table 3-8 Milton R. Young Station Metal Emissions and Comparison to EPA (1980) 

Screening Emission Rates..........................................................................................34

Table 4-1 List of Preparers .........................................................................................................36

Table 4-2 Contractors.................................................................................................................36

List of Figures

Figure 1-1 Location of BNI Center Mine.........................................................................................1

List of Appendices

Appendix A Social Cost of Greenhouse Gasses Calculations

Appendix B Public Comments
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BNI Coal Ltd. Federal Coal Lease by Application iii

Abbreviations and Acronyms

μg microgram

μg/m2

/yr micrograms per square meter per year

μg/m3

/yr micrograms per cubic meter per year

μg/yr micrograms per square meter per year

ASLM Assistant Secretary for Land and Minerals Management

BA Biological Assessment

BLM Bureau of Land Management

BNI BNI Coal Ltd.

CCR Coal Combustion Residuals

CCUS carbon capture, utilization, and storage

CEQ Council on Environmental Quality

C.F.R. Code of Federal Regulations

CO2e carbon dioxide equivalent 

°C degrees centigrade 

°F degrees Fahrenheit

EA Environmental Assessment

EIS Environmental Impact Statement

EPA U.S. Environmental Protection Agency

ESA Endangered Species Act

FLIGHT Facility Level Information on Greenhouse Gases Tool

FONSI Finding of No Significant Impact

FWS U.S. Fish and Wildlife Service

Gt gigaton

GHG greenhouse gas

GHRP Greenhouse Gas Reporting Program

Hg(0) elemental mercury

Hg(II) oxidized mercury

Hg-p particle bound mercury

IWG Interagency Working Group

IPCC Intergovernmental Panel on Climate Change

IRA Inflation Reduction Act of 2022

km kilometers

L liter(s)

lb/yr pounds per year

LBA Tracts lease area

LBA lease by application

m2 square meters

m3 cubic meters

MeHg methylmercury

mg/kg milligrams per kilogram

MLA Mineral Leasing Act of 1920

MMT million metric tons
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BNI Coal Ltd. Federal Coal Lease by Application iv

MPDD mining plan decision document

NADP National Atmospheric Deposition Program

NCTF National Climate Task Force

NDC national determined contribution

NEPA National Environmental Policy Act of 1969

ng nanogram

ng/L nanograms per liter

OSMRE Office of Surface Mining Reclamation and Enforcement

PM10 particulate matter less than 10 microns in size

PSC Public Service Commission

R2P2 Resource Recovery and Protection Plan

SC-CH4 social cost of methane

SC-CO2 social cost of carbon dioxide

SC-GHG social cost of greenhouse gases

SC-N2O social cost of nitrous oxide

SMCRA Surface Mining Control and Reclamation Act

UNEP United Nations Environment Programme

U.S.C. United States Code

USDOI United States Department of the Interior
Supplemental Environmental Assessment April 2023 Chapter 1

BNI Coal Ltd. Federal Coal Lease by Application 1

Chapter 1 Introduction

1.1 Introduction

BNI Coal Ltd. (BNI), operator of the Center Mine in North Dakota, proposed a lease by

application (LBA) for Federal coal resources underlying private surface lands in Oliver County, 

North Dakota. The lease area (referred to herein as LBA Tracts, serial number NDM-105513,

Figure 1-1) consists of approximately 630 acres of private surface lands and Federal minerals 

managed by the Bureau of Land Management (BLM) located in the following locations

(Figure 1-1):

• S 1⁄2 NE 1⁄4 NE 1⁄4 Section 8, Township 141N, Range 83W (20.22 acres)

• E 1⁄2 NE 1⁄4, S 1⁄4 SW 1⁄4, and SE 1⁄4 Section 14, Township 141N, Range 84W (319.27 

acres)

• NE 1⁄4, E 1⁄2 SW 1⁄4, SE 1⁄4 NW 1⁄4, and SE 1⁄4 NE 1⁄4 NW 1⁄4 Section 20, Township 142N, 

Range 84W (287.62 acres)

Figure 1-1 Location of BNI Center Mine
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BNI Coal Ltd. Federal Coal Lease by Application 2

BNI’s final LBA was submitted to the BLM on February 14, 2017. BNI currently operates the 

Center Mine under the following permits approved by the North Dakota Public Service 

Commission (PSC) Permits:

• BNCR-8106

• BNCR-8202

• BNCR-8602

• BNCR-9401

• BNCR-9702

• BNCR-1101

The tracts of the application area (i.e., LBA Tracts) in Sections 8 and 20 are within the permit 

area of the Center Mine (BNI mining permit boundary in Figure 1-1) that was approved by the 

PSC (Permits BNCR-9401 and BNCR-9702, respectively). BNI would need to modify permit

BNCR-1101 before disturbing the Section 14 tract.

Pursuant to sections 503 and 523 of the Surface Mining Control and Reclamation Act of 1977

(SMCRA), the PSC is authorized to regulate surface coal mining operations on private, state 

and Federal lands within North Dakota. 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 the agency responsible for making a recommendation to the 

United States Department of the Interior (USDOI) Assistant Secretary for Land and Minerals 

Management (ASLM) to approve, disapprove, or approve with conditions the proposed mining 

plan.

The BLM North Dakota Field Office completed an Environmental Assessment (EA) in October 

2020 that analyzed the potential environmental impacts of the Federal coal lease proposed by 

BNI (LBA Tracts). The OSMRE Western Region Office and PSC cooperated in the EA 

preparation (reference (1)). As a Federal agency, the OSMRE is subject to the National 

Environmental Policy Act of 1969 (NEPA), and therefore must conduct an environmental review, 

in the form of either adoption of a prior NEPA document for the same project, supplementing a 

prior NEPA document for the same project, or creating a new NEPA analysis, before proceeding 

with the Federal action of making a recommendation to the ASLM regarding the mining plan. 

The OSMRE determined a supplement to the prior EA was needed. 

The OSMRE also determined that the proposed action of mining a new Federal coal lease 

constitutes a mining plan decision requiring approval by the ASLM. The OSMRE’s decision was 

based upon consideration of the Federal regulations at 30 C.F.R. §§ 740 and 746. The OSMRE 

will develop three mining plan decision document (MPDD) recommendations, one for each mine 

permit (BNCR-9401[Revision 17], BNCR-9702 [Revision 42], and BNCR-1101 [Revision 8]), that 

will be based on compliance with:
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BNI Coal Ltd. Federal Coal Lease by Application 3

• NEPA;

• BLM’s Resource Recovery and Protection Plan (R2P2) documentation;

• LBA;

• PSC permit findings;

• Any documentation ensuring compliance with applicable requirements of other Federal

laws, regulations, and executive orders, including preparing a Biological Assessment

(BA) to assess the potential to affect threatened or endangered species as well as 

proposed and final designated critical habitat that may occur within the designated 

analysis areas and fulfill the requirements for consultation with the US Fish and Wildlife 

Service under Section 7(c) of the Endangered Species Act (ESA) of 1973, and 

consultation on cultural resources.

The analyses regarding the affected environment, environmental impacts and mitigation, and 

cumulative effects for the following elements were addressed in the BLM’s 2020 EA

(reference (1)):

• Air Resources

• Climate

• Water Resources

• Cultural Resources

The BLM’s 2020 EA eliminated the following resource issues from further analysis:

• Geology/minerals

• Hazardous materials

• Noise and vibrations

• Paleontology

• Public safety

• Recreation

• Soil Resources

• Special plant species

• Transportation

• Visual Resources
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BNI Coal Ltd. Federal Coal Lease by Application 4

• Vegetation

• Socioeconomics

The OSMRE incorporates, by reference, these analyses from the BLM’s 2020 EA, and they are 

not discussed further in this supplemental EA, in accordance with 43 C.F.R. § 46.135. The 

OSMRE prepared this supplemental EA to: update the climate analysis, further assess potential 

social cost of greenhouse gases (SC-GHG) impacts, and assess potential mercury and 

selenium deposition impacts to the Pallid sturgeon and Whooping crane that would be 

associated with the approval of the Federal mining plan.

The OSMRE analyzed the potential environmental consequences of the proposed action, 

including the effects when combined with reasonably foreseeable future actions and 

environmental trends.

The OSMRE prepared this supplemental EA and the associated BA to thoroughly examine the 

potential environmental impacts of the proposed action and alternative actions to support 

informed decision-making. This supplemental EA is consistent with:

• the purpose and goals of NEPA;

• the requirements of the Council on Environmental Quality’s (CEQ’s) implementing NEPA 

regulations at 40 C.F.R § 1500-1508;

• USDOI’s NEPA regulations (43 C.F.R. § 46);

• USDOI Departmental Manual Part 516;

• OSMRE guidance on implementing NEPA, including the OSMRE Handbook on 

Procedures for Implementing the National Environmental Policy Act (reference (2));

• longstanding Federal judicial and regulatory interpretations;

• Administration priorities and policies including Secretary’s Order No. 3399 requiring 

bureaus and offices to use “the same application or level of NEPA that would have been 

applied to a proposed action before the 2020 Rule went into effect.”

NEPA requires Federal agencies to consider the potential environmental impacts of proposed 

Federal actions and determine whether significant impacts to the human environment would 

occur. The term “significant” is discussed in 40 C.F.R. § 1501.3(b). If the OSMRE determines 

that the project would have significant impacts following the analysis in this supplemental EA, 

then an Environmental Impact Statement (EIS) would be prepared. If the OSMRE determines 

that the potential impacts would not be significant, the OSMRE would prepare a Finding of No 

Significant Impact (FONSI) to document this finding, and, accordingly, would not prepare an 

EIS.
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BNI Coal Ltd. Federal Coal Lease by Application 5

1.2 Background

BNI is the owner and operator of the Center Mine and has been mining coal at the Center Mine 

since 1970, which typically produces 4.0 to 4.6 million tons of lignite coal per year. The 

maximum production rate approved in the Center Mine’s minor source operating permit is 4.6 

million tons of lignite coal per year (reference (3)). Approximately 98 percent of coal from the 

Center Mine is supplied to the Milton R. Young Station coal-fired power plant located adjacent to 

the northeast corner of the permit area. Lignite power plants are typically constructed next to the 

mines that supply them due to the high-moisture content that makes the transportation of lignite

coal uneconomic over long distances (reference (4)). As such, there is no rail loadout facility at 

the Center Mine, nor are there any proximate rail lines that would allow for rail transport of the 

coal. Minnkota Power Cooperative, Inc. owns and operates the Milton R. Young Station that 

consists of two generating units. BNI is under contract to supply coal to the Milton R. Young 

Station through 2037. 

BNI would haul coal from the LBA Tracts in trucks via a direct corridor passing through 

undisturbed areas and the Permit BNCR 9401 area to the Milton R. Young Station’s coal 

crushing facility. As mining progresses, haul roads within the mining disturbance area are 

rerouted from ahead of the active pit to the reclamation side of the pit. All coal haul traffic occurs 

within the mining disturbance area. In addition, BNI supplies approximately 60,000 tons of coal 

per year to Center Coal Co. that is located adjacent to the mine offices. Center Coal Co. is a 

supplier of small quantities of stoker and lump coal to individual customers, including personal 

residences, R&D facilities, universities, and manufacturers, in North Dakota, South Dakota, 

Minnesota, and Canada (reference (5)).

The Center Mine has approximately 63.20 million tons of coal currently under PSC permits. BNI 

estimates that there are approximately 6.13 million tons of minable coal in the LBA Tracts 

(bringing the total coal in the LBA tracts under PSC Permits to 69.33 million tons if mining is 

approved). If the 6.13 million tons of Federal coal from the LBA Tracts is mined in a continuous 

manner, it would represent approximately 16 months of coal production at the Center Mine at 

the maximum mining rate of 4.6 million tons per year. Given the amount of coal currently under 

PSC permits, the projected mine life and operating plans of the Center Mine are anticipated to 

extend through the year 2037, whether or not the ASLM approves the Federal mining plan for 

the LBA Tracts.

Although the Center Mine has sufficient non-Federal coal leases to supply the Milton R. Young 

Station through 2037, access to the Federal coal leases would allow for a more efficient mine 

plan, i.e., less equipment miles traveled, less overburden, and more efficient reclamation.

Additionally, Revision 17 is immediately adjacent to the Coal Combustion Residuals (CCR)

disposal cells for the Milton R. Young Station. The Center Mine, because of delays in the 

leasing process, has already bypassed some Federal coal adjacent to the CCR disposal cells, 

resulting in construction of a shallow CCR disposal cell above the bypassed Federal coal. CCR 

disposal space at the Milton R. Young Station is running low. Mining of the Federal coal within 

Revision 17 would allow for construction of a deeper CCR disposal cell with a greater storage 
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BNI Coal Ltd. Federal Coal Lease by Application 6

capacity than if the coal within Revision 17 were to be bypassed. The greater storage capacity 

would decrease the need for additional future CCR disposal cells.

As previously noted, with exception to North Dakota PSC approval for the Section 14 tract, BNI 

has the appropriate leases and access agreements to conduct surface disturbance and 

overburden removal on the privately-owned surface overlying the LBA Tracts and, to the extent 

necessary for conducting mining operations, on the adjoining parcels where the surface and 

coal is privately owned. However, before coal removal can occur on the LBA Tracts, the ASLM 

must approve the Federal mining plan covering the LBA Tracts, as required by 30 C.F.R. 

§ 746.11. 

1.2.1 Milton R. Young Station

The Milton R. Young Station is not considered a connected action to this proposed action. The 

OSMRE Handbook on Procedures Implementing NEPA defines connected actions as follows:

Connected actions are those actions that are “closely related’ and should be 

analyzed in the same NEPA document...Actions are connected if they 

automatically trigger other actions that may require an EIS; cannot or will not 

proceed unless other actions are taken previously or simultaneously; or if the 

actions are interdependent parts of a larger action and depend upon the larger 

action for their justification. (reference (2)) 

The Milton R. Young Station is not considered a connected action to this proposed action 

because (1) it would not automatically trigger any action at the Milton R. Young Station that 

would require an EIS; (2) OSMRE approval of the mining plan would not trigger any changes 

(previous or simultaneous actions) at the Milton R. Young Station; and (3) the OSMRE approval 

is not an interdependent part of a larger action at the Milton R. Young Station.

The proposed action would not change production levels at the Milton R. Young Station or 

require changes to its current regulatory permits. If the mining plan is rejected, the Milton R. 

Young Station would continue to operate and be supplied with coal from other Center Mine 

production areas. The Milton R. Young Station would operate, as needed, independent of the 

coal in the LBA Tracts. Although the Milton R. Young Station is not considered a connected 

action, operating data from the power plant are included in this supplemental EA to provide 

context and to assist with analyzing the reasonably foreseeable future action of combustion of 

coal sourced from the LBA Tracts.

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

• NEPA
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BNI Coal Ltd. Federal Coal Lease by Application 7

• Clean Air Act of 1970

• Clean Water Act of 1972

• Endangered Species Act of 1973

• SMCRA

The SMCRA provides the legal framework for the Federal government to regulate coal mining 

by balancing the need for continued domestic coal production with protecting the environment 

and society, while also ensuring the mined land is returned to beneficial use when mining is 

finished. The OSMRE implements its responsibilities for the MLA and SMCRA under regulations 

at 30 C.F.R. §§ 700 through 955. 

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 the 

SMCRA, 30 U.S.C. § 1253, the PSC developed, and the Secretary of the Interior approved, 

North Dakota’s permanent regulatory program authorizing 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, and 30 C.F.R. § 934.30, 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 to this cooperative agreement, a Federal coal leaseholder must submit a permit 

application package, which includes the R2P2 and State Mining Permit application, to the 

OSMRE and 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 

PSC issues a permit to the applicant to conduct coal-mining operations. 

The OSMRE will prepare three MPDDs in support of its recommendations to the ASLM, who will 

decide whether or not to approve the mining plans and whether or not additional conditions are 

needed. Pursuant to 30 C.F.R. § 746.13, the OSMRE‘s recommendations will be based on:

• the permit application package, including the R2P2;

• information prepared in compliance with NEPA, including this supplemental 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;
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BNI Coal Ltd. Federal Coal Lease by Application 8

• findings and recommendations of the PSC with respect to the permit application and the 

state program;

• findings and recommendations of the OSMRE regarding additional requirements of 30 

C.F.R. §§ 740 through 746.

1.4 Purpose and Need for the Proposed Action

BNI’s purpose and need for the proposed action is to mine the approximately 6.13 million tons 

of minable coal in the LBA Tracts for continued operation of the Center Mine. As previously 

noted, if the 6.13 million tons of Federal coal from the LBA Tracts is mined in a continuous 

manner, it would represent approximately 16 months of coal production at the Center Mine at 

the maximum mining rate of 4.6 million tons per year.

The purpose of the OSMRE’s Federal action is to respond to BNI’s need for a Federal mining 

plan that is required before the Federal coal contained in the lease tracts can be mined. The 

OSMRE must recommend to the ASLM to approve, disapprove, or approve BNI’s proposed 

mining plan with conditions as required by the Mineral Leasing Act of 1920 and the SMCRA. 30 

C.F.R. §746: 30 U.S.C. § 208(c). The ASLM will use the OSMRE’s recommendation to decide 

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

1.5 Outreach and Issues Identification

1.5.1 Scoping

The OSMRE Handbook on Procedures Implementing NEPA, Section 9.3.1 states:

When evaluating the need for external scoping, consider factors such as: the size or scale 

of the proposed action; whether the proposal is routine or unique; who might be interested 

or affected; and whether or not external scoping has been conducted for similar projects 

and what the results have been. The EA should include the agency's rationale for 

determining whether or not to conduct external scoping. (reference (2))

A 30-day Public Scoping period was conducted for the BLM’s 2020 EA from June 14 to July 14, 

2017. During that period, the BLM received two comment letters and one email. In addition, The 

BLM’s 2020 EA was available for public review from September 8 to October 8, 2020. During 

that time only one non-substantive comment relating to the proposed leasing action was 

received from the public. As a cooperating agency, the OSMRE reviewed all public comments 

received for the BLM’s 2020 EA (reference (1)). Given the recent public comment periods for 

the BLM’s 2020 EA, which is incorporated by reference within this supplemental EA, the 

OSMRE determined it was not necessary to conduct additional public scoping. 

1.5.2 Outreach

The OSMRE released this supplemental EA and unsigned FONSI on January 26, 2023, for a 

30-day public comment period and notified the public of this comment period by publishing a 

notice in the Bismarck Tribune and the Center Republican, mailing public outreach letters, as 
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BNI Coal Ltd. Federal Coal Lease by Application 9

well as mailing tribal consultation letters to 18 tribal leaders. The public comment period ended

on February 25, 2023.

The OSMRE received an email from the Section 106 Review contact for the Fort Peck 

Assiniboine and Sioux Tribes on February 9, 2023, asking the OSMRE to resubmit the 

consultation letter with an additional addressee. Accordingly, the OSRME mailed a second letter 

on February 14, 2023, as requested in the email.

The OSMRE received three comment letters during the comment period. The North Dakota

Department of Environmental Quality provided guidelines for minimizing impacts to waterways, 

noted that the Center Mine’s existing permits to discharge stormwater and wastewater from its 

mining activies extend to the LBA Tracts, and reference to waste management requirements.

The North Dakota Department of Water Resources submitted comments regarding potential 

floodplain impacts, requirements for water storage impoundment/surface drain/water 

appropriation permits, requirements for consultation for any impacts to their observation wells, 

and noted a typographical error in the Draft EA. Section 3.7 and Appendix D of the BLM’s 2020 

EA (reference (1)) assesses the potential for impacts to water resources. Furthermore, 

Appendix B of the BLM’s 2020 EA (reference (1)) provides the extended Mine Plan and 

describes waste management for the Center Mine. As previously noted, OSMRE incorporates 

by reference these analyses from BLM’s 2020 EA, and they are not discussed further in this EA.

Lastly, the North Dakota Department of Transporatation commented that the project should 

have no adverse effect to its highways; however, permits may be necessary if work will occur 

within its rights of ways. The BLM’s 2020 EA (reference (1)) eliminated transporatation from 

further analysis. 

The OSMRE received two telephone calls during the comment period from nearby landowners 

with questions but no specific comments regarding this EA.
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BNI Coal Ltd. Federal Coal Lease by Application 10

Chapter 2 Proposed Action and Alternatives

2.1 Introduction

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

supplemental information regarding the SC-GHG, BA for Federal threatened and endangered 

species, and mercury and selenium deposition where relevant to the 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 alternative). In addition, the BLM EA identifies the 

current operations and continuation of activities under the proposed action and under the noaction alternative. This section presents descriptions of the proposed action and the no-action 

alternative relative to the SC-GHG and mercury and selenium deposition analysis in Chapter 

3.0.

2.1.1 Proposed Action

The location of the LBA Tracts is detailed in Chapter 1.1 and shown on Figure 1-1. The 

Sections 8 and 20 tracts of the application area (i.e., LBA Tracts [NDM-105513]) are within the 

permit area of the Center Mine (Figure 1-1) that was approved by the PSC (Permits BCNR-9401 

and BNCR-9702, respectively). BNI submitted a request to the PSC to revise Permit BNCR1101 to include the Section 14 tract. No mining of the Federal coal in the LBA Tracts can occur 

until the PSC approves the modification to Permit BNCR-1101 and the ASLM approves the 

mining plan. 

BNI estimates that there are approximately 6.13 million tons of minable Federal coal located in 

the LBA Tracts. If the 6.13 million tons are mined continuously, it would represent approximately 

16 months of coal production at the Center Mine at a mining rate of 4.6 million tons per year. 

However, the actual time to produce the coal from the LBA Tracts would be longer than 16 

months and BNI estimates will occur over the course of seven years. The Center Mine projected 

mine life and operating plans, whether the LBA Tracts are mined or not, extend through the year 

2037. The proposed action is for the OSMRE to submit an MPDD making a recommendation to 

the ASLM to approve the MPDD.

Mining and reclamation activities would proceed as described in Appendix B of the BLM EA 

(reference (1)).

2.1.2 No Action

Under the no-action alternative, the OSMRE would not recommend approval of the MPDD to 

the ASLM. Without ASLM’s approval, the PSC’s proposed permit would revert to the previous 

permit. Under the previous permit, the Federal coal reserves in the LBA Tracts would not be 

recovered and mining would continue in other permitted areas until available coal reserves are 

mined out.

Under the no-action alternative, additional soil removal and stripping would occur on these 

tracts under the previous state permit in order to support mining the adjoining private coal 

reserves, as well as additional soil stockpiles being placed on these tracts. Beyond additional 
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BNI Coal Ltd. Federal Coal Lease by Application 11

physical disturbances, a no-action alternative would also delay reclamation of the surrounding 

private lands.
Supplemental Environmental Assessment April 2023 Chapter 3

BNI Coal Ltd. Federal Coal Lease by Application

12

Chapter 3 Affected Environment and Impacts

3.1 Introduction

This chapter describes the existing condition of resources and the findings from the BA and 

evaluates climate change, SC-GHGs, and mercury and selenium deposition that could be 

affected by implementation of the alternatives described in Chapter 2.0, as they relate to the 

MPDD for the Center Mine. This chapter incorporates Chapter 3.0 of the BLM EA by reference 

and provides only supplemental information regarding climate, SC-GHGs, and mercury and 

selenium deposition where relevant to the analysis presented in this document.

In accordance with 40 C.F.R. § 1501.3(b), this chapter describes the potential environmental 

consequences of the proposed action, including the effects when combined with reasonably 

foreseeable future actions and environmental trends. “Reasonably foreseeable” means

sufficiently likely to occur such that a person of ordinary prudence would take it into account in 

reaching a decision. 40 C.F.R. § 1508.1(g) defines “effects or impacts” as:

...changes to the human environment from the proposed action or alternatives that are 

reasonably foreseeable and include the following:

(1) Direct effects, which are caused by the action and occur at the same time and 

place. 

(2) Indirect effects, which are caused by the action and are later in time or farther 

removed in distance, but are still reasonably foreseeable. Indirect effects may include 

growth inducing effects and other effects related to induced changes in the pattern of 

land use, population density or growth rate, and related effects on air and water and 

other natural systems, including ecosystems.

(3) Cumulative effects, which are effects on the environment that result from the 

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

reasonably foreseeable actions regardless of what agency (Federal or non-Federal) or 

person undertakes such other actions. Cumulative effects can result from individually 

minor but collectively significant actions taking place over a period of time.

(4) Effects include ecological (such as the effects on natural resources and on the 

components, structures, and functioning of affected ecosystems), aesthetic, historic, 

cultural, economic, social, or health, whether direct, indirect, or cumulative. Effects may 

also include those resulting from actions which may have both beneficial and 

detrimental effects, even if on balance the agency believes that the effects will be 

beneficial.

3.2 Past, Present, and Reasonably Foreseeable Future Actions

For the purposes of this analysis, the temporal span of the proposed action represents the time 

during which mining of LBA Tracts would occur (i.e., 16 months of mining over seven years).

For assessing potential mercury and selenium deposition impacts from air emissions, the 
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BNI Coal Ltd. Federal Coal Lease by Application 13

geographic extent consists of the area within 50 km of the Milton R. Young Station. The SCGHGs are considered at the state, national, and global scales.

Past and present actions in the analysis areas that would contribute to cumulative effects 

include mining activities, power plants, industrial activities, and agricultural activities. Of these 

activities, surface mining and the associated electrical power generation dominate the 

emissions of the analysis area. In addition to these sources, agriculture, including row crops, 

hayfields and grazing lands, is a predominant industry in North Dakota. Although there is 

significant oil and gas development in northwest North Dakota, notably in the Bakken Region

whose southeast portion is about 40 km to the north of the Milton R. Young Station, there is little 

oil and gas development in the analysis area.

Therefore, the reasonably foreseeable actions for this analysis consist of potential future mining 

of Federal coal at the Center Mine and the coal combustion at the Milton R. Young Station.

Mining operations at Beulah Mine, Coyote Creek Mine, Falkirk Mine, and Freedom Mine are 

expected to continue for the foreseeable future with current production rates and continued 

surface disturbances according to individual approved mine plans. The continued operations of 

the other mines at permitted rates and within their permitted boundaries are not considered a 

change to existing conditions, therefore are not identified as a reasonably foreseeable action.

3.3 Climate Change and Social Cost of Greenhouse Gases

The BLM’s 2020 EA presented an analysis regarding the affected environment, environmental 

impacts and mitigation, and cumulative effects for climate (reference (1)). This section provides 

an updated climate analysis in addition to SCC-GHGs.

Table 3-1 summarizes the direct and indirect GHG emissions from the mining and combustion 

of the 6.13 million tons of mineable Federal coal located in the LBA Tracts based on the 

emissions presented in the BLM EA (reference (1)). Table 3-1 assumes GHG emission global 

warming potentials published by Intergovernmental Panel on Climate Change (IPCC) in 2014 

(reference (6)).

Table 3-1 Proposed Action Summary for Potential GHG Emissions from Mining LBA 

Tracts and Coal Combusted at an Electric Generating Utility

Parameter Description Proposed Action

Total Federal Coal Combusted (million tons) 6.13

Number of Years in Operation (years) 7

Annual Federal Coal Combusted (tons) 875,714

Cumulative 100-year CO2e Mining Emissions (million tons CO2e) 0.157

Annual 100-year CO2e Mining Emissions (million tons CO2e/year) 0.02

Annual 100-year CO2e Mining Emissions (metric tons CO2e/year) 22,471

Cumulative 100-year CO2e Coal Combustion Emissions (million tons CO2e) 8.516

Annual 100-year CO2e Coal Combustion Emissions (million tons CO2e/year) 1.22

Annual 100-year CO2e Coal Combustion Emissions (metric tons CO2e/year) 1,216,524

From reference (1)
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3.3.1 Trends in Global, United States, and North Dakota Greenhouse Gas 

Emissions

3.3.1.1 Emission Levels

Preliminary estimates from the Rhodium Group for 2020 show global emissions at 50.1 gigatons

(Gt) of CO2e, representing a 4.4% decline from 2019 levels, by far the largest drop in recorded 

history. The reduction in emissions in 2020 was primarily due to the COVID-19 pandemic and 

global recession. In 2020, China accounted for nearly 30% of all global emissions, the United 

States accounted for approximately 10% of global GHG emissions, while India and the 

European Union accounted for 6% each. In 2019 (the latest year for which there is sufficient 

data to provide sectoral level detail), GHGs were emitted across the following primary economic 

sectors globally: industry (30%); electric power generation (26%); land use, agriculture, and 

waste (21%); transportation (16%); and buildings (7%) (reference (7)). The proposed action

(mining and combustion) annual emissions represent approximately 0.0024% of 2020 global 

annual GHG emissions.

The Environmental Protection Agency (EPA) tracks GHG emissions in the United States 

through two complementary programs. First is the Inventory of U.S. Greenhouse Gases and 

Sinks, which is the annual GHG emissions inventory published by EPA that represents all 

United States emissions (reference (8)). The second is the Greenhouse Gas Reporting Program 

(GHGRP), which generally applies to facilities that emit more than 25,000 metric tons (MMT) of 

CO2e each year. The facility level emissions reported under GHGRP are published through the 

Facility Level Information on Greenhouse Gases Tool (FLIGHT). EPA estimates that the 

FLIGHT data reported by large emitters reflect 85% to 90% of the total United States emissions 

(reference (9)). 

In 2020, total gross United States GHG emissions were 5,981 MMT CO2e, and net emissions 

were 5,222 MMT CO2e. Net GHG emissions include both anthropogenic and natural emissions 

of GHGs, as well as removals by sinks (e.g., carbon uptake by forests). From 2005 to 2020, net 

GHG emissions in the United States declined 21%. This decline reflects the combined impacts 

of long-term trends in population and economic growth, energy markets, technological changes,

including energy efficiency, and energy fuel choices. Net GHG emissions decreased from 2019 

to 2020 by 11%. The primary driver for the decrease was an 11% decrease in CO2 emissions 

from fossil fuel combustion, primarily due to a 13% decrease in transportation emissions and a 

10% decrease in electric power sector emissions, reflecting both a decrease in demand from 

the COVID-19 pandemic and a continued shift from coal to less carbon intensive natural gas 

and renewables. CO2 is the primary GHG contributing to total United States emissions, 

accounting for 79% of the total GHG emissions in 2020. By comparison, CH4 accounted for 

11%, N2O accounted for 7% of emissions and fluorinated gases accounted for nearly 3% of 

emissions. In 2020, GHGs were emitted across the following primary economic sectors in the 

United States: transportation (27%), electric power/electricity generation (25%), industry (24%), 

agriculture (11%) residential homes (7%), and commercial businesses (6%) (reference (8)). The 

proposed action annual emissions represent approximately 0.02% of 2020 net annual US GHG 

emissions.
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In 2021, total North Dakota GHG emissions were 36.9 MMT CO2e. GHGs were emitted across 

the following primary economic sectors in the North Dakota: electric power/electricity generation 

(76%), chemical producers (10%), petroleum and natural gas systems (6%) mineral mining

(3%), refineries (2%), waste management (2%), and other sources (2%) (reference (9)). The 

proposed action annual emissions represent approximately 3% of 2021 annual North Dakota 

GHG emissions.

Federal lands are responsible for GHG emissions, from activities such as fossil fuel extraction 

and combustion, as well as carbon sequestration, which is the process of capturing and storing 

atmospheric carbon dioxide through uptake into soils, vegetation, aquatic environments, and 

other ecosystems (biologic sequestration) or through injection into porous underground rock 

formations (geologic sequestration). The United States Geological Survey has estimated GHG 

emissions and carbon sequestration on Federal lands for the 10-year period from 2005 to 2014 

(reference (10)). GHG emissions (when considering just CO2) associated with the combustion 

and extraction of fossil fuels from United States Federal lands increased from 1,362 MMT CO2e 

in 2005, to 1,429 MMT CO2e in 2010, and then decreased to 1,279 MMT CO2e in 2014. CH4

and N2O emissions from Federal lands also decreased over the same 10-year period. When the 

Federal lands’ fossil fuel extraction and combustion emissions are combined with ecosystem 

emissions and sequestration estimates, the annual net carbon emissions from Federal lands 

within the Conterminous United States (48 contiguous states) ranged from 683 to 783.5 MMT 

CO2e from 2005 to 2014, indicating a net carbon emission from Federal lands within the 

conterminous United States. The annual net carbon emissions from North Dakota ranged from 

2.5 to 12.4 MMT CO2e from 2005 to 2014, indicating a net carbon emission from North Dakota 

Federal lands (reference (10)). The proposed action annual emissions represent approximately 

10% of North Dakota’s Federal lands 2014 emissions, and 0.1% of national Federal lands 2014 

emissions.

The BLM Specialist Report on Annual Greenhouse Gas Emissions and Climate Trends presents 

the estimated emissions of GHGs attributable to fossil fuels produced on lands and mineral 

estate managed by the BLM. More specifically, the report estimates GHG emissions from coal, 

oil, and gas development that is occurring, and is projected to occur, on the Federal onshore 

mineral estate. BLM estimated a total of 448.30 MMt CO2e from all coal production on Federal

lands in 2021 and 42.44 MMt CO2e from all coal production on Federal lands in North Dakota in 

2021(reference (11)). The proposed action annual emissions represent approximately 0.27% of 

national 2021 Federal coal emissions, and 2.9% of North Dakota’s 2021 Federal coal 

emissions.

3.3.1.2 Emission Goals

The IPCC Special Report Global Warming of 1.5°C estimates with high confidence that to limit 

global warming to 1.5 degrees centigrade (°C), global GHG emissions in 2030 would need to be 

40% to 50% lower than 2010 emissions (reference (12)). Based on the IPCC findings, the 

United Nations Environment Programme (UNEP) Emissions Gap Report estimates global GHG 

emissions in 2030 would need to be 55% lower than currently projected 2030 emissions in order 

to limit global warming to 1.5°C and would need to be 30% lower in order to limit warming to 2°C 
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BNI Coal Ltd. Federal Coal Lease by Application 16

(reference (13)). The Paris Agreement is a legally binding international climate change treaty 

designed to encourage individual countries to pledge specific emissions reductions so that the 

world can meet the necessary GHG reduction levels to limit global warming to 1.5°C 

(reference (14)). Unfortunately, UNEP has estimated that emission reduction pledges from 

individual nations are anticipated to reduce projected 2030 emissions by only 7.5%, far short of 

the 55% reduction needed to limit global warming to 1.5°C (reference (13)). Therefore, global 

temperatures are anticipated to continue to rise well above levels necessary to avoid the worst 

impacts from climate change.

The United States National Climate Task Force (NCTF) was established on January 27, 2021,

by the Executive Order on Tackling the Climate Crisis at Home and Abroad (EO 14008). EO 

14008 was issued to facilitate the organization and deployment of a government-wide approach 

to combat the climate crisis (reference (15)). The NCTF performed an analysis of potential and 

measured impacts of various policies and measures (both potential and existing) at all levels of 

government and in all relevant sectors to develop the United States national determined 

contribution (NDC) under the Paris Agreement. This analysis was conducted using input from all 

Federal government agencies, as well as other stakeholders, such as scientists, activists, local 

and state governments, and various local institutions. For the industrial sector, the NDC outlines 

that the United States government will support research on and implementation of very low- and 

zero-carbon industrial processes and products, including introducing these products to market. 

The United States government will also incentivize carbon capture, utilization, and storage 

(CCUS) and the use of new sources of hydrogen for powering industrial facilities

(reference (16)).

The United States NDC established an economy-wide target of reducing net GHG emissions by 

50% to 52% below 2005 levels in 2030 (reference (16)). The United States has also established 

the goal of net-zero emissions no later than 2050 and 100% carbon pollution-free electricity by 

2035 (references (17); (18)). In 2020, United States net GHG emissions totaled 5,222 MMT 

CO2e, representing a 21% emissions reduction below 2005 level (reference (8)). The United 

States is broadly on-track to meet the 2025 goal of 26% to 28% emissions reductions below 

2005 levels (reference (16)). On August 16, 2022, President Biden signed the Inflation 

Reduction Act of 2022 (IRA) into law, which is the single largest action ever taken by the United 

States government to combat climate change. The IRA included several additional economic 

incentives to support the development of CCUS (reference (19)). However, it should be 

acknowledged that, at this time, CCUS is not yet adequately developed or deployed to fully 

mitigate all GHGs associated with electricity generation from coal. According to analysis from 

the Rhodium Group, the net result of all the provisions in the IRA is anticipated to help United 

States net GHG emissions decline to 32-42% below 2005 levels in 2030, which represents a 

substantial step towards its goals, but still short of the climate target of 50-52% below 2005 

levels in 2030 (reference (20))

The net United States emissions in 2005 were 6,635 MMT CO2e (reference (16)); therefore, the 

2030 net emissions goals are estimated to be between approximately 3,185 and 3,318 MMT 

CO2e. Comparing the 2020 net GHG emissions of 5,222 MMT CO2e to the low end of the 2030 
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estimated emissions of 3,185 MMT CO2e shows that annual net United States GHG emissions 

must be reduced by 2,037 MMT CO2e between 2020 and 2030. Under the proposed action, 

1.22 MMT CO2e would be emitted annually from 2023 to 2029, representing approximately 

0.06% of the necessary emissions reduction of 2,037 MMT CO2e to meet the 2030 emissions 

goals.

North Dakota does not currently have formal GHG emission targets (reference (21)).

3.3.1.3 Carbon Budget

The United States does not currently have a carbon budget with which to compare the proposed 

action’s potential emissions. We also include a discussion of the global carbon budget for 

background. The global carbon budget is an estimate for the total amount of anthropogenic CO2

that can be emitted to have a certain chance of limiting the global average temperature increase 

to below 2°C (3.6 degrees Fahrenheit [°F]) relative to preindustrial levels. IPCC estimates that if 

cumulative global CO2 emissions from 1870 onwards are limited to approximately 1,000 Gt of 

carbon (3,670 Gt CO2), then the probability of limiting the temperature increase to below 2°C 

(3.6°F) is greater than 66 percent (reference (22)). Since this IPCC report was published, 

various studies have produced differing estimates of the remaining global carbon budget; some 

estimates have been larger (reference (23)) and others have been smaller (reference (24)). 

Most notably, the IPCC Sixth Assessment Report (reference (25)) detailed the implications of 

methodological advancements in estimating the remaining carbon budget. The report concluded 

that, due to a variety of factors, estimates for limiting warming to 2°C (3.6°F) are about 11 to 14 

Gt of carbon (40 to 50 Gt CO2) higher than estimates in the IPCC Fifth Assessment Report 

(reference (22)). In other words, the global carbon budget presented in IPCC Sixth Assessment 

Report was slightly larger than would have been expected based on the Fifth Assessment 

Report global carbon budget. Estimates of the remaining global carbon budget vary depending 

on a range of factors, such as the assumed conditions and the climate model used 

(reference (26)). Because of underlying uncertainties and assumptions, no one number for the 

remaining global carbon budget can be considered definite. 

Using IPCC’s estimated carbon budget in Sixth Assessment Report, as of 2019, approximately 

655 Gt of carbon (2,403 Gt CO2) of this budget has already been emitted, leaving a remaining 

global budget of 358 Gt of carbon (1,313 Gt CO2) (reference (25)). The emissions reductions 

needed to keep global emissions within this carbon budget would require dramatic reductions in 

all United States sectors, as well as, from the rest of the world. Even with the full implementation 

of global emissions reduction commitments to date, global emissions in 2030 would still be 

roughly 11 Gt CO2e higher than what is consistent with a scenario that limits warming to 2°C 

[3.6 ̊F] from preindustrial levels (reference (13)).

3.3.2 Social Cost of Greenhouse Gases

The social cost of carbon (SC-CO2), social cost of nitrous oxide (SC-N2O), and social cost of 

methane (SC-CH4) – together, the SC-GHG are estimates of the monetized damages 

associated with incremental increases in GHG emissions in a given year. 
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On January 20, 2021, President Biden issued E.O. 13990, Protecting Public Health and the 

Environment and Restoring Science to Tackle the Climate Crisis (reference (27)). Section 1 of 

E.O. 13990 establishes an Administration policy to, among other things, listen to the science; 

improve public health and protect our environment; ensure access to clean air and water; 

reduce greenhouse gas emissions; and bolster resilience to the impacts of climate change

(reference (27)). Section 2 of the E.O. calls for Federal agencies to review existing regulations 

and policies issued between January 20, 2017, and January 20, 2021, for consistency with the 

policy articulated in the E.O. and to take appropriate action.

Consistent with E.O. 13990, the CEQ issued interim National Environmental Policy Act 

Guidance on FederalConsideration of Greenhouse Gas Emissions and Climate Change (2023 

GHG Guidanance) on January 9, 2023, and is seeking public comment through April 10, 2023

(reference (28)). CEQ issued the 2023 GHG Guidance as interim guidance so that agencies 

may use it immediately to assess GHG emissions and climate change effects while they seek 

public comment on the guidance (reference (28)). 

Regarding the use of social cost of carbon or other monetized costs and benefits of GHGs, the 

2023 GHG Guidance noted that NEPA does not require monetizing costs and benefits

(reference (28)). It also noted that “the weighing of the merits and drawbacks of the various 

alternatives need not be displayed using a monetary cost-benefit analysis and should not be 

when there are important qualitative considerations” (reference (28)).

Section 5 of E.O. 13990 emphasized that Federal agencies should “capture the full costs of 

greenhouse gas emissions as accurately as possible, including by taking global damages into 

account” and established an Interagency Working Group (IWG) on the Social Cost of 

Greenhouse Gases ([reference (27)]). In February of 2021, the IWG published Technical 

Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide: Interim Estimates 

under Executive Order 13990 (reference (29)). This is an interim report that updated previous 

guidance from 2016. 

In accordance with this direction, Sections 3.3.3 and 3.3.4 provide estimates of the monetary 

value of changes in GHG emissions that could result from selecting each alternative. Such 

analysis should not be construed to mean a cost determination is necessary to address 

potential impacts of GHGs associated with specific alternatives. These numbers were 

monetized; however, they do not constitute a complete cost-benefit analysis, nor do the SCGHG numbers present a direct comparison with other impacts analyzed in this document. For 

instance, the OSMRE’s overall analysis for this action does not monetize most of the major 

costs or benefits and does not include all revenue streams from the proposed action. SC-GHG 

is provided only as a useful measure of the benefits of GHG emissions reductions to inform 

agency decision-making.

For Federal agencies, the best currently available estimates of the SC-GHG are the interim 

estimates of the social cost of carbon dioxide (SC-CO2), SC-CH4, and SC-N2O developed by the 

IWG on the SC-GHG. Select estimates are published in the Technical Support Document
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BNI Coal Ltd. Federal Coal Lease by Application 19

(reference (29)) and the complete set of annual estimates are available on the Office of 

Management and Budget’s website (reference (30)).

The IWG’s SC-GHG estimates are based on complex models describing how GHG emissions 

affect global temperatures, sea level rise, and other biophysical processes; how these changes 

affect society through, for example, agricultural, health, or other effects; and monetary estimates 

of the market and nonmarket values of these effects. One key parameter in the models is the 

discount rate, which is used to estimate the present value of the stream of future damages 

associated with emissions in a particular year. A higher discount rate assumes that future 

benefits or costs are more heavily discounted than benefits or costs occurring in the present 

(i.e., future benefits or costs are a less significant factor in present-day decisions). The current 

set of interim estimates of SC-GHG have been developed using three different annual discount 

rates: 2.5%, 3%, and 5% (reference (29)). 

As expected with such a complex model, there are multiple sources of uncertainty inherent in 

the SC-GHG estimates. Some sources of uncertainty relate to physical effects of GHG 

emissions, human behavior, future population growth and economic changes, and potential 

adaptation (reference (29)). To better understand and communicate the quantifiable uncertainty, 

the IWG method generates several thousand estimates of the social cost for a specific gas, 

emitted in a specific year, with a specific discount rate. These estimates create a frequency 

distribution based on different values for key uncertain climate model parameters. The shape 

and characteristics of that frequency distribution demonstrate the magnitude of uncertainty 

relative to the average or expected outcome.

To further address uncertainty, the IWG recommends reporting four SC-GHG estimates in any 

analysis. Three of the SC-GHG estimates reflect the average damages from the multiple 

simulations at each of the three discount rates. The fourth value represents higher-thanexpected economic impacts from climate change. Specifically, it represents the 95th percentile 

of damages estimated, applying a 3% annual discount rate for future economic effects. This is a 

low probability, but high damage scenario, and represents an upper bound of damages within 

the 3% discount rate model. The estimates in Sections 3.3.3 and 3.3.4 follow the IWG 

recommendations. Detailed calculations are presented in Appendix A.

3.3.3 Proposed Action

For the proposed action, BNI estimates that there are approximately 6.13 million tons of minable 

Federal coal located in the LBA Tracts. If the 6.13 million tons are mined continuously, the coal

would represent approximately 16 months of coal production at the Center Mine at a mining rate 

of 4.6 million tons per year. However, the actual time to produce the coal from the LBA Tracts 

would be longer than 16 months, and BNI estimates mining will occur over the course of seven 

years. The Center Mine projected mine life and operating plans, whether the LBA Tracts is 

mined or not, extend through the year 2037, so the estimated direct and indirect GHG emission 

rates for the continued operations at the Center Mine or the Milton R. Young Station would be 

substantially unchanged by the proposed action. Therefore, Table 3-2 summarizes only the 

direct and indirect GHG emissions from the mining and combustion of the 6.13 million tons of 
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BNI Coal Ltd. Federal Coal Lease by Application 20

mineable Federal coal located in the LBA Tracts based on the emissions presented in the BLM 

EA (reference (1)).

Because (as noted) lignite coal is difficult to transport; because there is no proximate rail line 

that would, in any event, allow that transport; because the Center Mine provides the 

overwhelming majority of its Coal to the Milton R. Young Station; and because BNI’s purpose in 

seeking OSMRE approval is to facilitate a more efficient mining and reclamation plan and 

construction of fewer CCR disposal cells at the Milton R. Young Station, not to increase the 

supply of its marketable coal for sale, OSMRE is confident, based on the data before it, that the 

proposed action would not result in increased sales of coal from Center Mine (and associated 

GHG emissions) over and above the no action alternative. 

Table 3-2 summarizes the SC-GHGs associated with estimated emissions from the proposed 

action. These estimates represent the present value (from the perspective of 2023) of future 

market and nonmarket costs associated with CO2, CH4, and N2O emissions. Estimates are 

calculated based on IWG estimates of social cost per metric ton of emissions for a given 

emissions year (reference (29)) and the OSMRE’s estimates of emissions in each year. They 

are rounded to the nearest $1,000. The estimates assume emissions would start in 2023 and 

end in 2029, based on the current mining plan.

OSMRE notes that the proposed action does not implicate “perfect substitution” of the type 

discouraged under NEPA. National Environmental Policy Act Guidance on Consideration of 

Greenhouse Gas Emissions and Climate Change, Fed. Reg, 1196, 1205 & nn. 96, 97 (Jan. 9, 

2023). Mining of the LBA tracts may lower marginal costs for the mine, which may be passed on 

to the Milton R. Young power plant and ultimately result in increased coal combustion, which 

could in turn lead to higher emissions. (OSMRE lacks the data and modeling necessary to 

quantify these marginal emissions and reductions, including after soliciting and receiving 

comments on this EA.) Likewise, mining the LBA tracts may lower certain emissions associated 

with re-siting drag lines and coal combustion residue pits. (OSMRE did not quantify these 

potential reductions after concluding that any reductions would be minimal and therefore not 

useful to the decisionmaker.)

Table 3-2 SC-GHGs Associated with Mining LBA Tracts and Coal Combustion under 

the Proposed Action

Social Cost 

Metric

5% Average

Discount Rate

3% Average

Discount Rate

2.5% Average

Discount Rate

3% Average

Discount Rate,

95th Percentile

SC-CO2 $127,947,441 $447,773,450 $665,980,514 $1,344,568,350

SC-CH4 $684,014 $1,544,583 $2,028,295 $4,088,395

SC-N2O $848,280 $2,703,392 $3,975,569 $7,134,708

Total $129,479,735 $452,021,425 $671,984,378 $1,355,791,453 

3.3.4 No Action

Under the no-action alternative, the OSMRE would not recommend approval of the MPDD to 

the ASLM. Without ASLM’s approval, the PSC’s proposed permits would revert to the previous 
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BNI Coal Ltd. Federal Coal Lease by Application 21

permits. Under the previous permits, the Federal coal reserves in the LBA Tracts would not be 

recovered and mining would continue in other permitted areas until available coal reserves are 

mined out. Mining of the Federal coal would not occur, and the specific direct emissions 

associated with the Federal coal would not occur. However, mining of the equivalent 6.13 million 

tons of non-Federal coal would occur at the exiting rate of 4.6 million tons per year in other 

permitted areas similar to the proposed action. Furthermore, the Milton R. Young Station would 

continue to combust coal from other Center Mine production areas at current rates. The Milton 

R. Young Station would operate, as needed, independent of the coal in the LBA Tracts. 

Therefore, the no-action alternative would not materially change the estimated direct or indirect 

GHG emission rates for existing conditions. Table 3-3 summarizes the direct and indirect SCGHG associated with the continued operations at the Center Mine or the Milton R. Young 

Station under the no-action alternative.

Table 3-3 SC-GHGs for the No-Action Alternative of Coal Combusted at an Electric 

Generating Utility associated with the No-Action Alternative

Social Cost 

Metric

5%

Average

Discount Rate

3%

Average

Discount Rate

2.5%

Average

Discount Rate

3%

Average 

Discount Rate,

95th Percentile

SC-CO2 $127,947,441 $447,773,450 $665,980,514 $1,344,568,350

SC-CH4 $684,014 $1,544,583 $2,028,295 $4,088,395

SC-N2O $848,280 $2,703,392 $3,975,569 $7,134,708

Total $129,479,735 $452,021,425 $671,984,378 $1,355,791,453 

Estimated SC-GHG costs for the no-action alternative (Table 3-3) and the proposed action 

(Table 3-2) are identical because the mining rate, direct mining equipment emissions, and 

indirect coal combustion rate at the Milton R. Young Station would be the same for both 

alternatives. Therefore, the proposed action does not result in an incremental direct or indirect

increase in the SC-GHGs from the no-action alternative. 

3.3.4.1 Unavoidable Adverse, Irretrievable, and Irreversible Effects

The Center Mine does not currently employ any CCUS technology, and there are no permit 

requirements to employ CCUS or reduce GHG emissions through other means; therefore, GHG 

emissions from the proposed action and their contribution to cumulative GHG levels and climate 

change are unavoidable and irretrievable throughout the life of the mine. Cumulative climate 

change impacts may be irreversible, depending on what future steps are taken to address future 

cumulative GHG emissions worldwide, i.e., if the world is unable to limit GHG emissions some 

climate change impacts may be irreversible. Impacts on the long-term sustainability of area 

resources is dependent on the steps taken by the international community to limit GHG 

emissions, e.g., long-term sustainability of hydrologic resources will depend on the degree to 

which climate change induces drought and/or flooding which depends on the degree to which 

the planet warms which is directly related to the degree to which the international community 

does or does not limit GHG emissions.
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3.3.4.2 Conclusion

BNI would haul coal from the LBA Tracts in trucks via a direct corridor passing through 

undisturbed areas and the Permit BNCR 9401 area to the Milton R. Young Station’s coal 

crushing facility (Section 1.2). The Milton R. Young Station has current operating permits 

through May 2025, with the ability to renew every 5 years, and the Center Mine is anticipated to 

operate through the permitted lifetime of the Milton R. Young Station. The Center Mine has nonFederal coal leases sufficient to supply the Milton R. Young Station through 2037. While the 

Center Mine could supply the Milton R. Young Station with non-Federal coal sources, BNI has 

applied to mine coal within Federal leases through 2037 because this would make for a more 

efficient mine plan. The Center Mine is expected to have a mining rate of 4.0 to 4.6 million tons 

per year and a life of mine through 2037, regardless of whether the proposed action is approved 

or not (Section 1.2). As such, annual GHG emissions from the proposed action will be 

approximately the same as emissions under the no-action alternative. Therefore, regardless of 

whether the proposed action is approved or not, average annual emissions (primarily indirect) 

are expected to be approximately, 0.0024% of 2020 global emissions, 0.02% of 2020 United 

States net emissions, 3% of 2021 North Dakota emissions, 10% of North Dakota’s Federal

lands 2014 emissions, 0.1% of 2014 national Federal lands emissions, 0.27% of national 2021 

Federal coal emissions, and 2.9% of North Dakota’s 2021 Federal coal emissions. Additionally, 

the proposed action does not result in an incremental increase in the SC-GHG from the noaction alternative. 

The global carbon budget is discussed in Section 3.3.1.3. The United States does not currently 

have a carbon budget with which to compare this project’s potential emissions, however, as 

discussed in Section 3.3.1.3, the United States has set specific emissions reduction goals. 

Under the proposed action, 1.22 MMT CO2e would be emitted annually from 2023 to 2029, 

representing approximately 0.06% of the necessary emissions reduction of 2,037 MMT CO2e to 

meet the 2030 emissions goals. The EPA has not set specific thresholds for GHG emissions. 

Disapproving the proposed action would not reduce global emissions in any meaningful way 

because the no-action alternative has a very similar emissions profile. Therefore, while climate 

change does significantly impact the environment and the proposed action would produce 

climate changing emissions, there is no indication that the amount of GHG emissions from the 

proposed action as compared to the no-action alternative would have a significant impact on 

climate change.

3.4 Biological Assessment

Section 7 of the ESA requires consultation with the U.S. Fish and Wildlife Service (FWS) for 

projects requesting Federal funding and/or regulatory agency authorization to ensure that the 

proposed Federal action(s) do not jeopardize the continued existence of any threatened, 

endangered, or proposed species or result in the destruction or adverse modification of 

designated critical habitat. Barr Engineering Co. prepared a BA on behalf of the OSMRE to 

support agency coordination with the FWS and compliance with Section 7 of the ESA of 1973, 

as amended (16 U.S.C. §§ 1531 et seq.) for its MPDD recommendation for the LBA Tracts.
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The BA analyzed how mining the LBA Tracts could affect threatened and endangered species 

and designated critical habitat. Two endangered species and four threatened species were

identified as having the potential to occur in the action area (a 50-kilometer [(km)] radius area). 

The species considered in the BA include the following:

• Dakota skipper (Hesperia dacotae), threatened

• Northern long-eared bat (Myotis septentrionalis), threatened (On November 29, 2022 the 

FWS published a final rule to reclassify the Northern long-eared bat as endangered 

under the ESA. The FWS extended the effective date of the listing reclassification from 

January 30, 2023 to March 31, 2023.)

• Pallid sturgeon (Scaphirhynchus albus), endangered

• Piping plover (Charadrius melodus) and its critical habitat, threatened

• Red knot (Calidris canutus rufa), threatened

• Whooping crane (Grus americana), endangered

The OSMRE conservatively (protectively) determined that the proposed action, may affect, but 

is not likely to adversely affect the species (and critical habitat) listed above.

The “may affect, but not likely to adversely affect” determination for the Pallid sturgeon, 

Northern long-eared bat, Piping plover, Red knot, and Whooping crane are based on potential 

indirect impacts to surface waters, including wetlands and riparian corridors, related to mercury 

and metal (e.g., selenium) emissions from the Milton R. Young Station burning Center Mine coal 

(Sections 3.4, 3.5, and 3.6). 

Surveys conducted for the LBA Tracts where mining would occur in 2023 indicate no suitable 

habitat present for the Dakota skipper. However, the “may affect, but not likely to adversely 

affect” determination for the Dakota skipper is based on observations over the last 3 years of 

individuals in central and eastern Oliver County, with several sightings of Dakota skippers within 

5 miles of the Center Mine. There is also the potential for selenium emissions from the Milton R. 

Young Station to be contributed to Dakota skipper habitat, therefore a may affect but not likely 

to adversely affect determination is partly due to selenium deposition.

The BA was submitted to the FWS on February 10, 2022, for review and concurrence. The FWS 

provided informal comments to the OSMRE on April 14, 2022. The OSMRE then submitted an 

updated BA to the FWS to address the FWS informal comments on January 6, 2023. The FWS 

concurred with the OSMRE’s effects determinations on January 31, 2023. On March 31, 2023 

OSMRE obtained a new list of species from the FWS Information for Planning and Consulting 

(IPaC) system confirming that there were no changes to listed species or critical habitat other 

than the NLEB being listed as endangered. Accordingly, OSMRE ran the updated IPaC tool for 

NLEB which stated that the project was, “not reasonably certain to cause incidental take of the 

NLEB”, confirming the findings within the BA, and formal consultation was not reinitiated.
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3.5 Mercury Deposition

Mercury is a naturally occurring element that is a neurotoxin and therefore a health and 

environmental concern as it accumulates within the food chain. The primary human exposure to 

mercury is through fish consumption. Mercury is deposited from the atmosphere to land and into 

waterbodies. When inorganic mercury enters an aquatic ecosystem, under certain conditions, it 

can undergo a process known as methylation resulting in methylmercury (MeHg) 

(reference (31)). Biomagnifying up through the food chain, MeHg ultimately leads to elevated 

concentrations in the tissue of top predator fish, with exposure to the general public occurring 

when those fish are consumed. MeHg is a potent toxin because of its high solubility in fatty 

tissue in animals, resulting in significant potential for bioaccumulation and biomagnification. As a 

result, MeHg is considered the most hazardous form of mercury.

Coal-fired power plants are one of the main sources of mercury emissions within the United

States. There is scientific evidence that shows a positive relationship between mercury 

emissions from electric generating units in the United States and local mercury deposition and 

the associated response within ecosystems (reference (32)). 

Mercury air emissions generally exist as one of three species: elemental, ionic or oxidized, and 

particle bound. Understanding which species are present in air emissions is the key to 

determining mercury’s atmospheric pathway, transport, and fate. The majority of anthropogenic 

mercury emissions and the most common species present in the atmosphere is gaseous 

elemental mercury (reference (33)). Elemental mercury has an atmospheric lifetime of several 

months to a year and is transported great distances (reference (34)). Upon emission to air from 

combustion sources, very little gaseous elemental mercury is directly deposited to the earth’s 

surface due to its elemental properties and slow reaction with common atmospheric oxidants

(reference (33)). Research findings indicate dry deposition of background elemental mercury 

occurs via vegetation uptake or in throughfall (precipitation passing through a forest canopy and 

washing off materials deposited on leaf and branch surfaces) being an important pathway for 

delivery of mercury to boreal forest soils (reference (35); (36); (37); (38)). Terrestrial 

environments are considered net sinks for elemental mercury (i.e., elemental mercury is 

retained and stored in the watershed (reference (36)). However, due to known loss mechanisms

of elemental mercury (i.e., volatilization), the amount of this dry deposited elemental mercury 

that is actually retained in a watershed is a fraction of that deposited (reference (36)); (39)), and

an even smaller amount is mobilized within a watershed and reaches aquatic systems to 

become methylated and actually contribute to fish tissue mercury concentrations 

(reference (36); (40)). Therefore, in regard to fish tissue mercury concentrations, the important 

pathway for mercury is direct deposition to the water body via precipitation (primarily oxidized 

mercury), with a small contribution from mercury derived from the watershed (reference (41)). 

Large lake systems tend to reflect mercury having isotopic signatures reflective of atmospheric 

precipitation, suggesting that more of the mercury exported to the lake water originated from 

precipitation (and, hence, from gaseous oxidized mercury or particulate mercury) that fell onto 

the catchment (reference (41)).
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The upper Missouri River system seems to be an exception to the conclusion that large lake

systems tend to reflect atmospheric precipitation. For the Missouri River basin, prior research 

indicates the majority of mercury (~93%) delivered to reservoirs in the upper part of the basin is 

associated with suspended solids in river water, with atmospheric deposition (wet and dry) only 

contributing about 4 to 6% (reference (42)). Erosion and scouring that occur during high flow 

events mobilize mercury (as soil-bound mercury) in the watershed and in surficial river 

sediments and create a pulse in mercury movement (reference (42)). Land management 

practices that control erosion and leaching have a large effect on the mercury delivered to the 

reservoirs in the upper Missouri River basin (includes the Missouri River upstream of Lewis and 

Clark Lake in South Dakota) (reference (42)).

Atmospheric mercury deposited to water is predominantly in the form of oxidized mercury 

compounds. These may be gaseous oxidized mercury or oxidized mercury attached to particles, 

both of which are due to the direct deposition of gas phase species and through wet deposition 

in precipitation (reference (33)). Further, gaseous oxidized mercury is highly reactive with other 

environmental constituents and is deposited within a few miles of its emission point

(reference (34)). Locally deposited oxidized mercury in waterbodies can interact with 

microorganisms where they change it into MeHg. MeHg accumulates within fish tissue. Elevated 

mercury concentrations in fish tissue have been documented in several regions of the United 

States, for example in the southeast (reference (34)) and in New England (reference (43)). In 

the evaluation by the Florida Department of Environmental Protection, oxidized mercury 

accounted for more than 50% of the emissions from the facilities being evaluated

(reference (34)). King et al. found that local mercury deposition due to emissions of oxidized 

mercury was a factor of 4 to 10 times greater than rural background deposition (reference (44)). 

Associated with increased local deposition of oxidized mercury, fish tissue mercury 

concentrations were elevated in nearby water bodies (reference (34); (44)). The available 

literature clearly concludes that when a significant portion of air emissions are oxidized mercury, 

there will be increased local mercury deposition.

Particle-bound mercury has a short atmospheric life due to its physical characteristics (mass, 

increased wind resistance, interaction with precipitation) and is thought to be deposited within a 

range of 50 to 80 km (30 to 50 miles) from the emission point (reference (34)).

In North Dakota, electric generating stations do not contribute significantly to local or regional 

mercury deposition due to the predominance of elemental mercury emitted from tall stacks

(reference (45)). Sullivan et al. conducted a mercury deposition modeling study of three power 

plants (reference (46)). Oxidized mercury emissions were estimated at 20% and 60%. They 

found that less than 2% of total mercury emissions deposited within 15 km (with the highest 

deposition occurring within 10 km), of the power plants they evaluated. The small percentages 

of incremental deposition from the respective power plants resulted in minor contributions to 

background mercury levels and no correlation with vegetation or soil concentrations. Estimated 

total mercury deposition ranged between 0.3% to 1.7% of background. Sullivan et al. also 

concluded that their modeling results were consistent with the literature they reviewed that 

found no “hot spots” of deposition close to power plants (reference (46)). Additionally, a 
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modeling analysis was conducted for a proposed baseload coal-fired power plant with total 

mercury emissions of approximately 136 pounds per year (lb/yr) after controls (activated carbon 

and particulate control technology), with primarily elemental mercury emissions (97%). The 

modeling results identified that the highest estimated deposition was about 2% of background 

deposition, with the authors concluding that very little deposition of mercury was likely to occur

due to the predominance of elemental mercury air emissions (reference (47)). 

Atmospheric mercury deposition estimates are available for North and South Dakota that are 

considered applicable to the Project area. The National Atmospheric Deposition Program 

(NADP) collects wet deposition concentrations around the United States through the Mercury 

Deposition Network. The two closest stations to the Milton R. Young Station are the Lostwood 

National Wildlife Refuge in North Dakota and Eagle Butte in South Dakota. Table 3-4

summarizes the average wet deposition from 2016-2020. Dry deposition values in Table 3-4 are

based on results from Engel et al. that conclude dry mercury deposition is approximately 35% of 

the total deposition and wet deposition is approximately 65% of the total deposition

(reference (48)). Estimates for other areas in nearby states indicate dry deposition can be as 

high as 50 to 80% of total deposition (reference (49); (38); (50)). Therefore, an estimate of dry 

deposition being approximately 35% of total deposition may be on the low side but is a 

representative estimate for this analysis.

Table 3-4 Estimated Background Total (wet + dry) Mercury Deposition to the Area

Category

Lostwood National 

Wildlife Refuge, ND

(ID = ND01)[1]

Eagle Butte, SD

(ID = SD18)[1]

Distance from Milton R. Young Station (km) 193 225

Average Annual Wet Mercury Deposition [2]

(2016-2020), micrograms per square meter per year 

(μg/m2/yr)

5.04 6.93

Annual Wet Mercury Deposition Standard Deviation[3]

(2016-2020), μg/m2/yr

1.44 1.25

Calculated Annual Dry Mercury Deposition[2], μg/m2/yr 2.71 3.73

Annual Total Mercury Deposition (Wet + Dry), μg/m2/yr 7.75 10.66

Annual Total Mercury Deposition (Wet + Dry) Standard 

Deviation[3], μg/m2/yr

2.21 1.92

[1] Wet deposition data from the National Atmospheric Deposition Program, Mercury Deposition Network.

http://nadp.slh.wisc.edu/data/sites/siteDetails.aspx?net=MDN&id=ND01

[2] Partitioning of total mercury deposition between wet (65%) and dry (35%) is based on the results from Engle et al. 

(reference (48)).

[3] The standard deviation of wet deposition based on the reported annual mercury deposition for each site from the National 

Atmospheric Deposition Program, Mercury Deposition Network. The standard deviation for total (wet + dry) deposition 

includes the estimated contribution of dry deposition to annual deposition. In this case, dry deposition is 53.8% of wet 

deposition, and this percentage is used to estimate the dry deposition component of the standard deviation. For example, the 

standard deviation of wet deposition at Lostwood is 1.44 μg/m2

/yr; 1.44 μg/m2/yr x 0.538 = 0.77 μg/m2/yr dry deposition; 1.44 

μg/m2

/yr + 0.77 μg/m2/yr = 2.21 μg/m2/yr. The standard deviation for total mercury deposition for Eagle Butte was estimated 

in the same manner as estimated for Lostwood.

Background concentrations of mercury in North Dakota surface waters and wetlands is limited.

Data from the Lostwood National Wildlife Refuge indicates total mercury in wetland and lake 

surface waters are primarily in the dissolved phase, with concentrations in whole-water (data 
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from unfiltered samples) ranging from 0.87 nanograms per liter (ng/L) to 17.2 ng/L 

(reference (51)). Most whole-water total mercury concentrations (middle 80%) were between 

1.60 and 8.71 ng/L (reference (51)). Median whole-water total mercury concentrations ranged 

from 1.58 to 2.37 ng/L for lake wetlands, 4.52 to 6.48 ng/L for temporary wetlands, 3.95 to 

6.99 ng/L for semipermanent wetlands, to 4.52 to 7.92 ng/L for seasonal wetlands. Generally, 

whole-water total mercury concentrations for the North Dakota lakes and wetland waters are 

within the range reported for other lakes and wetland waters in rural and agricultural areas 

(reference (52); (53); (54)).

3.5.1 Proposed Action

A screening assessment for potential deposition of the proposed action direct and indirect 

mercury air emissions was conducted. Potential direct mercury emissions from the proposed 

action at the Center Mine are small, related to fuel combustion in mine vehicles, and overall not 

significant on a local, regional, or national scale. The majority of anthropogenic mercury 

emissions in North Dakota are from coal combustion (reference (55)).

The Milton R. Young Station, that combusts coal from the Center Mine, has been in operation 

since 1970 and is estimated to currently emit approximately 178 pounds of mercury per year (5-

year average). Mercury emissions for the 2015 to 2019 time period (five years) from the Milton 

R. Young Station are summarized in Table 3-5. The Milton R. Young Station has a mercury 

emission limit of 0.004 lbs/MMBTU for both Boiler 1 and Boiler 2. Applicable Maximum 

Achievable Control Technology standards described in Section 3.2.5 of the BLM EA restrict 

emissions of hazardous air pollutants such as mercury.

Table 3-5 Annual Total Indirect Mercury Emissions at Milton R. Young Station, 2015-

2019

Emissions 2015 2016 2017 2018 2019 Unit

Mercury, total 179 156 201 180 174 Pounds

Note: Table 3-9 of reference (56)

Total mercury deposition from the Milton R. Young Station’s air emissions, considered here to 

be an incremental or additional deposition, was estimated within a 50-km radius. For this 

analysis, it is assumed that mercury speciation for elemental (Hg(0)), oxidized (Hg(II)), and 

particle-bound (Hg-p) are 89%, 10%, and 1%, respectively (reference (57)). Additionally, each 

mercury species has a different settling velocity based on its physical and chemical attributes, 

and therefore a different cumulative fraction value is applied to each mercury species based on 

generic modeling of power plants conducted by Cohen et al. (reference (58)). The cumulative 

deposition fractions that are applied to the 50-km radius based on the modeling conducted by 

Cohen et al. (reference (58)) are as follows: 0.2 for Hg(II), 0.01 for Hg-p, and 0.0015 for Hg(0). 

Table 3-6 summarizes the estimated potential deposition within 50 km of the Milton R. Young 

Station. 
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Table 3-6 Potential Incremental Total (wet + dry) Mercury Deposition within 50-

Kilometer Radius of the Milton R. Young Station

Item Value Unit[1]

50-km radius area[2] 7.85E+09 m2

MR Young, mercury emissions (5-year average; 2015-2019) 178 lb/yr

Mercury speciation Not 

applicable

Not 

applicable

Hg(0), 89% of total 158 lb/yr

Hg(II), 10% of total 17.8 lb/yr

Hg-p, 1% of total 1.78 lb/yr

Incremental deposition Not 

applicable

Not 

applicable

Hg(II) (0.2 cumulative fraction deposited; over 50-km radius) 1.61E+09 μg/yr

Hg-p (0.01 cumulative fraction deposited; over 50-km radius) 8.07E+06 μg/yr

Hg(0) (0.0015 cumulative fraction deposited; over 50-km radius) 1.08E+08 μg/yr

Total Mercury Deposition (sum for Hg(II), Hg-p, and Hg(0) 1.73E+09 μg/yr

Incremental Annual Total Mercury Deposition Rate over 50-km Radius Area

(Deposition Rate = total mercury deposition, μg/yr / area, m2)

0.22 μg/m2/yr

[1] Unit conversions:

1 pound = 435.6 grams (g)

1 gram = 1,000 milligrams (mg)

1 milligram = 1,000 micrograms (μg)

1 kilometer (km) = 1,000 meters (m)

[2] Area of a circle = πr

2 (where π = 3.14159; r2 = radius squared)

If considered an incremental deposition, the estimated deposition rate of 0.22 μg/m2/yr within 

50-km of the Milton R. Young Station is approximately 2.8% of the background total mercury 

deposition rate of 7.75 μg/m2/yr estimated for this area based on data from the Lostwood NADP 

monitoring site. This potential deposition from the Milton R. Young Station is not likely to be 

discernible from the variability in background mercury deposition. For example, the standard 

deviation for background total mercury deposition at the Lostwood NADP monitoring site for the 

most recent 5-year time period (2016 to 2020) is estimated to be 2.21 μg/m2

/yr (when 

accounting for wet and dry deposition). Therefore, a potential contribution of 0.22 μg/m2

/yr from 

the Milton R. Young Station is within the variability of background deposition such that it would 

not likely be a detectable change in deposition.

Atmospheric mercury deposited to terrestrial watersheds can be sequestered and generally only 

slowly released over time to waterbodies (reference (36); (40)), whereas atmospheric mercury 

deposited directly to waterbodies can accumulate rapidly within the food chain (reference (40)). 

Once deposited in waterbodies, some portion can be rapidly changed to MeHg by 

microorganisms (reference (40)) where it then accumulates within the food chain, with 

accumulation in fish tissue being of most concern to wildlife and humans. 

The largest waterbody within the 50-km radius of the Milton R. Young station is the Missouri 

River (~13,000 acres), which is a habitat for the Pallid sturgeon fish species, listed as an 

endangered species under the ESA. There are also several lakes and numerous ponds and 

wetlands within 50 km of the Milton R. Young Station. Whooping cranes are a migratory bird 

listed as an endangered species under the ESA, and could use these ponds and wetlands for 
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stopover foraging and roosting habitat on their spring (April to mid-May) and fall (September to 

early November) migrations. Table 3-7 summarizes the acreages of waterbodies within the 50-

km radius area.

Calculations were conducted to estimate a potential change in surface water mercury 

concentration based on the estimated potential incremental mercury deposition from the Milton 

R. Young Station to open water areas. A change in mercury surface water concentration is 

expected to result in a change in fish tissue mercury concentrations (reference (40)). Whooping 

cranes feed mostly on frogs, fish, plant tubers, insects, crayfish, and waste grains during 

migration. Because the Whooping crane relies on species that inhabit ponds and wetlands for a 

portion of their diet (i.e., frogs, fish, and crayfish), assessing the potential change in mercury 

surface water concentrations provides an indicator of potential effects to the Whooping crane. 

The estimated potential change in mercury concentration to surface waters within 50 km of the 

Milton R. Young Station, including the Missouri River, is small (Table 3-7). For surface waters in 

general, on an annual basis, the estimated incremental change in surface water total mercury 

concentration is approximately 0.22 ng/L, compared to median background concentrations 

ranging from about 1.6 to 9 ng/L.

For the Missouri River, the estimated potential incremental change is 0.07 ng/L, also small 

compared to median background total mercury concentrations ranging from about 1.6 to 9 ng/L.
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Table 3-7 Estimated Incremental Surface Water Mercury Concentrations Associated 

with Potential Total Mercury Deposition from the Milton R. Young Station

Item Value Unit[1]

Estimated Incremental Mercury Deposition within 50-kilometer Radius of 

the Milton R. Young Station

0.22 μg/m2/yr

Water Bodies (Lakes, Ponds, or Wetlands) Within 50 Kilometers Not 

applicable

Not 

applicable

Total Surface Area of Waterbodies [2] 236,049,993 m2

Total Annual Mercury Deposited on Waterbodies 

(Annual deposition = deposition rate, μg/m2 * area, m2)

52,014,370 μg/yr

Average Depth of Water for Lakes and Wetlands 1 meter

Total Volume of Water 

(volume, m3 = surface area, m2 * water depth, m)

2.36E+08 m3

Estimated Hg Concentration 

(Hg concentration = Total annual Hg deposition, μg/yr / water volume, m3) 

0.22 μg/m3/yr

Estimated Hg Concentration per 1 Liter of water 0.22 ng/L

Missouri River Segment Within 50 Kilometers of Milton R. Young Station Not 

applicable

Not 

applicable

Total Surface Area of the River 52,947,082 m2

Total Annual Hg Deposited on this Stretch of the River 11,667,059 μg/yr

Average Depth of Water in this Stretch of the River 3 meter

Total Volume of Water 1.59E+08 m3

Estimated Hg Concentration

(Hg conc = Total annual Hg deposition, μg/yr / water volume, m3)

0.07 μg/m3/yr

Estimated Hg Concentration per 1 Liter of water 0.07 ng/L

Notes: μg/m2/yr - micrograms per square meter per year; m2 - square meters; μg/yr - micrograms per square meter per year; 

m3 - cubic meters; μg/m3

/yr - micrograms per cubic meter per year; ng/L - nanograms per liter

[1] Unit conversions

1 cubic meter (m3

) = 1,000 liters (L)

1 microgram (μg) = 1,000 nanograms (ng)

[2] Surface water area estimated using the National Hydrography Dataset (reference (59)) and the National Wetland Inventory 

Data (reference (60)).

Total Waterbodies (not associated with the Missouri River) = 58,329 acres

Missouri River segment within 50 km of the Milton R. Young Station = 13,083 acres

Overall, the potential contribution of mercury from the Milton R. Young Station to surface waters 

(0.22 ng/L for lakes, ponds, and wetland waters; 0.07 ng/L in the Missouri River) is not 

significant when compared to the variability in background concentrations (range of about 1 to 

17 ng/L). Based on the estimated small potential contribution of the Milton R. Young Station to 

deposition to lakes/ponds/wetlands and in the Missouri River, mercury deposition may affect, 

but is not likely to adversely affect, the Whooping crane and Pallid sturgeon (reference (61)).

3.5.2 No Action

Background total mercury deposition in the 50-km analysis area, based on available data from 

the Lostwood National Wildlife Refuge mercury monitoring site (Table 3-4), will continue to 

occur at a rate of about 7 to 8 μg/m2/yr. The year-to-year variability (standard deviation) in 

mercury deposition, based on wet deposition data (Table 3-4 will likely be about 1.4 to 

2.2 μg/m2/yr (and could be larger depending on variability of dry deposition). 
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The Milton R. Young station anticipates operating to the same capacity for the reasonably 

foreseeable future even without the coal mined from the LBA Tracts. Therefore, there is no 

expected change in facility operations, mercury air emissions (other than the variability 

associated with year-to-year operations), or speciation of mercury emissions. Under the 

assumption that indirect mercury air emissions from the Milton R. Young Station result in 

incremental mercury deposition, the Milton R. Young Station would continue to contribute some 

amount of mercury to local deposition, as estimated in this analysis, about 0.22 μg/m2/yr of total 

(wet + dry) mercury deposition within the 50-km analysis area (Table 3-6). Therefore, no 

changes are expected to existing total mercury deposition within a 50-km radius of the Milton R. 

Young Station for a no-action alternative.

If considered an incremental deposition, the estimated deposition rate of 0.22 μg/m2

/yr within a

50-km radius of the Milton R. Young Station (Table 3-6) is approximately 2.8% of the 

background total mercury deposition rate of 7.75 μg/m2/yr estimated for this area based on data 

from the Lostwood NADP monitoring site. This potential deposition from the Milton R. Young 

Station is not likely to be discernible from the variability in background mercury deposition. For 

example, the standard deviation for background total mercury deposition at the Lostwood NADP 

monitoring site for the most recent 5-year time period (2016 to 2020) is 2.21 μg/m2

/yr (when 

accounting for wet and dry deposition). Therefore, a potential contribution of 0.22 μg/m2

/yr from 

the Milton R. Young Station is within the variability of background deposition such that it would 

not likely be a detectable change in deposition.

If considered an incremental deposition, a potential local total mercury deposition of 0.22 

μg/m2

/yr from the Milton R. Young Station is estimated to contribute about 0.22 ng/L to surface 

waters (lakes, ponds, and wetlands) and about 0.07 ng/L of mercury to the Missouri River 

(Table 3-7). This potential incremental contribution of mercury from the Milton R. Young Station 

to surface waters (0.22 ng/L for lakes, ponds, and wetland waters; 0.07 ng/L in the Missouri 

River) is not significant when compared to the variability in background concentrations (range of 

about 1 to 17 ng/L). Based on the estimated small potential contribution of the Milton R. Young 

Station to deposition in the Missouri River, mercury deposition may affect, but is not likely to 

adversely affect, the Pallid sturgeon. Furthermore, this small potential contribution of mercury 

loading to lakes/ponds/wetlands and the surrounding Missouri River watershed within 50 km 

may affect, but is not likely to adversely affect, the Whooping crane (reference (61)).

3.6 Selenium Deposition

Selenium is a trace element typically present in surface waters at low concentrations, less than 

3 micrograms per liter (μg/L). At slightly higher concentrations, around 5 μg/L, it can 

bioaccumulate in aquatic food chains and become a concentrated dietary source of selenium 

that is highly toxic to fish and wildlife (reference (62)). 

However, while selenium is considered an environmental contaminant in locations where it 

occurs in excessive abundance, it is imperative to recognize selenium’s role as an essential 

nutrient that is required to support life. All forms of animal life that have nervous systems require 

selenium in their diet, to protect against oxidative damage and regulate redox balance in 
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support of healthy brain, endocrine and immune functions. Although harmful effects accompany

exposure to excessively high environmental selenium, it is important to recognize that far more

locations have adverse biological consequences because of too little, rather than too much,

selenium present in the environment (reference (63)).

The atmosphere is a primary pathway for the distribution, cycling, and deposition of selenium in 

the environment (reference (64)), with about 40% of selenium originating from anthropogenic 

sources such as coal combustion, metal smelting, and biomass burning (reference (65).

However, selenium, which is found in the soils of the Great Plains, has been derived from 

geological formations, especially those formations deposited during Cretaceous time 

(reference (66)). As described by Alvin M. et al., “... The sedimentary rocks which make up the 

Cretaceous formations are the most important selenium bearers. They were deposited in a 

shallow sea which covered the Great Plains area during the Mesozoic era. ... The selenium 

which was laid down in these sedimentary formations has been carried through the soil-forming 

processes and is found in the soils of certain areas. ...”.

Cretaceous formations with high selenium concentrations in the Missouri River watershed 

include the Pierre Shale and Niobrara Shale (reference (67); reference (68)). Both formations 

are present in the upper Missouri River watershed with surface exposure of the Pierre Shale 

occurring south of Fort Yates (reference (69)), with overlying soils tending to also have high 

selenium concentrations (reference (66)). Selenium concentrations are typically highest in the 

oxygenated zone of soils (typically the upper 15 to 30 centimeters (~6 to 12 inches), with lower 

concentrations in the lower part of the soil profile (reference (70)). However, as shown in other 

studies, the presence of shales with high selenium content can result in higher concentrations of 

selenium with soil depth (reference (67)).

The Missouri River watershed is described as being prone to erosion, with the primary source of 

selenium in river water and sediments related to bluff and soil erosion. Studies conducted on the 

Missouri River in northern Nebraska / southern South Dakota identified erosion of bluffs and 

subsequent sediment transport by tributary rivers and within the main stem of the river as 

contributing soil-bound (particle-bound) selenium to river sediment (reference (71)). Selenium 

concentrations in river sediment were found to be generally low (7 of 9 sites), typically less than 

2 milligrams per kilogram (mg/kg or part per million), with the interpretation that potential release 

of selenium into solution for uptake by biota from these 7 sites would be minimal 

(reference (71)). Two of the 9 sites had concentrations greater than 4 mg/kg and were in the 

“high” category for potential food-chain based affects. However, the authors expressed 

concerns that even though selenium concentrations in sediment were low for 7 of the 9 sites, 

concentrations may be sufficiently high to cause biological impacts on fish and bird species prior 

to remobilization of additional sequestered selenium (reference (71)).

Previous studies in the North Dakota portion of the Missouri River have found elevated 

concentrations of selenium in sediment and in fish, but concentrations were below levels 

considered toxic to aquatic organisms and/or fish (reference (72)). The conclusion from this 

study was that selenium is primarily from soil erosion in the watershed and not due to 

atmospheric deposition of selenium or from point-source water discharges. 
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A more recent 2019 study by the FWS assessed selenium levels within the Missouri River to 

identify potential harmful contaminants to the Pallid sturgeon (reference (73)). Samples were 

collected from river water, sediment, and sturgeon tissues from past studies. The 2019

assessment found that levels of selenium exceeded the benchmarks in 53 of the 496 collected 

river water samples (~11% of river water samples had selenium concentrations greater than the 

benchmark). However, none of the sediment samples or samples of Pallid sturgeon tissue

exceeded the benchmark values (reference (73)).

3.6.1 Proposed Action

A screening assessment for potential deposition from direct and indirect selenium air emissions 

originating from the proposed action was conducted because air emissions and atmospheric 

deposition is the most likely pathway to contribute selenium to the Missouri River. Potential 

direct selenium air emissions from the proposed action at the Center Mine are small, related to 

fuel combustion in mine vehicles, and overall not significant on a local, regional, or national 

scale. For the proposed action, the majority of anthropogenic indirect selenium air emissions are 

expected to be from coal combustion at the Milton R. Young Station.

Speciation of selenium emissions from the Milton R. Young Station is expected to be primarily 

particle-bound selenium based on speciation studies. Some gas-phase selenium is likely to be 

emitted, but this is expected to be a smaller percent of total selenium emissions, ranging from 

about 20% to possibly as high as 40% (reference (74)). Volatile inorganic selenium is relatively 

unstable and has a limited lifetime, with the tendency to condense on particulate matter 

(reference (64)). Therefore, only the volatile organic selenium fraction, a small percent of total 

emissions from coal combustion, seems to be available for long-range transport, with the 

majority of selenium emissions being associated with particulates either in flue gas or in the 

atmosphere shortly after release from a stack (reference (74)).

When assessing the potential deposition of chemicals emitted to the air from a specific facility, 

researchers have concluded that dry deposition is the primary contributor to local deposition 

(reference (75)). Dry deposition of particulate metals at the Milton R. Young Station is 

associated with emissions of particulate matter less than 10 microns in size (PM10) and less 

than 2.5 microns in size (PM2.5). PM2.5 are fine particles that can remain airborne for long 

periods of time and are generally associated with long range atmospheric transport and not 

associated with local deposition (reference (70)). PM10 are coarser particles with a shorter 

atmospheric residence time and therefore tend to deposit closer to an emission source. The 

Milton R. Young Station has numerous pollution control systems including an electrostatic 

precipitator, flue gas desulfurization systems, and activated carbon injection system all of which 

serve to capture a portion of the pollutants that would otherwise be emitted. Given that the 

average PM10 emissions at the Milton R. Young Station are approximately 300 tons per year, 

there is some potential for local deposition of particulate metals (reference Evans et al. 2012).

However, given the pollution control measures in place at the Milton R. Young Station and its 

stack height, local deposition of particulate metals is likely very minimal.
Supplemental Environmental Assessment April 2023 Chapter 3

BNI Coal Ltd. Federal Coal Lease by Application 34

To provide additional perspective on the potential for particle-bound pollutants, such as 

selenium, to affect nearby ecological receptors, particulate metal emissions for the Milton R. 

Young Station were compared to the lowest available EPA (reference (76)) screening emission 

rates. Table 3-8 indicates all estimated particulate metal emissions are below the lowest 

available screening emission rates (per EPA 1980 guidance), including selenium.

As shown in Table 3-8, indirect air emissions of selenium (0.17 tons per year) from the Milton R. 

Young Station were a factor of 10 below EPA’s threshold screening emission rate (1.7 tons per 

year) (ratio of selenium air emissions to the screening emission rate = 0.1; guideline value for 

potential significance = 1). The results from the screening emission rate assessment are 

interpreted to mean that no significant deposition of selenium is expected to occur within the 50-

km analysis area, either to receptors close to (i.e., within 3 km), or distant from (> 3 km), the 

Milton R. Young Station. Similarly, no significant effects are expected to occur from potential 

deposition of selenium air emissions from the Milton R. Young Station close to, or distant from, 

the source. Therefore, based on the screening results in Table 3-8, the potential deposition of

indirect selenium air emissions from the Milton R. Young Station to the Missouri River 

watershed is expected to be insignificant and is expected to have no effect on the 2 mg/kg 

surface water benchmark established by FWS, and therefore no effect on the Pallid sturgeon.

Furthermore, the small potential contribution of selenium loading to the lakes/ponds/wetlands 

and surrounding Missouri River watershed within a 50-km radius is expected to have no effect 

on the Whooping crane (reference (61)).

Table 3-8 Milton R. Young Station Metal Emissions and Comparison to EPA (1980) 

Screening Emission Rates

Pollutant Station Emissions 

(TPY) 

Screening Emission 

Rate (TPY)(1)

Ratio (Project 

Emissions / 

Screening Emission 

Rate) 

Arsenic 0.038 0.24 0.16

Beryllium 0.001 0.057(2) 0.02

Cadmium 0.005 0.037 0.14

Chromium 0.35(3) 1.10 0.32

Cobalt 0.008 1.20 0.01

Copper NA 0.21 NA

Manganese 0.42 1.13(4) 0.37

Mercury 0.1 61 0.002

Nickel 0.12 67 0.002

Selenium 0.17 1.70 0.1

Vanadium NA 0.33 NA

Zinc NA 63 NA

NA = Not applicable/Data not available

(1) Lowest screening emission rate from Table 5.7 of reference (76), unless otherwise noted.

(2) Screening emission rate for beryllium is from Table 5.6 of reference (76).

(3) Emissions are a sum of Chromium III and Chromium VI.

(4) The original EPA (1980) emission rate was adjusted by a factor of 3.43 based on Table 5.8 of reference (76); a 30 m stack, 

“cold”.
Supplemental Environmental Assessment April 2023 Chapter 3

BNI Coal Ltd. Federal Coal Lease by Application 35

3.6.2 No Action

Atmospheric deposition of selenium in the 50-km analysis area will continue to occur and 

existing conditions watershed processes (e.g., soil erosion) will continue to deliver selenium to 

the Missouri River surface water and sediments even without coal mined from the LBA Tracts.

The Milton R. Young station anticipates operating to the same capacity for the reasonably 

foreseeable future even without the coal mined from the LBA Tracts. Therefore, there is no 

expected change in facility operations, indirect selenium air emissions (other than the variability 

associated with year-to-year operations), or primarily particle-bound indirect selenium 

emissions. Under the assumption that selenium air emissions from the Milton R. Young Station 

result in incremental selenium deposition, the Milton R. Young Station would continue to 

contribute some amount of selenium to local deposition, but the amount is insignificant given the 

screening analysis results shown in Table 3-8 (selenium emissions a factor of 10 below the 

screening emission rate). Therefore, no changes are expected to existing selenium deposition 

within a 50-km radius of the Milton R. Young Station for a no-action alternative. Based on the 

screening results in Table 3-8 for selenium, no indirect effects to the Pallid sturgeon or 

Whooping crane are expected from the no-action alternative.
Supplemental Environmental Assessment April 2023 Chapter 4

BNI Coal Ltd. Federal Coal Lease by Application 36

Chapter 4 List of Preparers

Table 4-1 shows a list of the preparers of this supplemental EA and those who participated in 

the preparation of this supplemental EA from the OSMRE. 

Table 4-1 List of Preparers

Organization Name Title/ Project Responsibility

OSMRE Roberta Martinez Hernandez Natural Resource Specialist/ Project Manager, 

internal scoping, review of EA

OSMRE Edward Vasquez Ecologist, review of EA

Table 4-2 shows a list of the preparers of this EA and those who participated in the preparation 

of this supplemental EA from the third-party consultants Barr Engineering Co.

Table 4-2 Contractors

Organization Name Title/ Project Responsibility

Barr Engineering Co. Rachael Shetka Senior Environmental Specialist/Project Manager EA 

author

Barr Engineering Co. Cliff Twaroski Vice President and Senior Environmental Scientist, EA 

author

Barr Engineering Co. Allison Serakos Environmental Scientist, mercury deposition analysis/EA 

author

Barr Engineering Co. Matthew Metzger Senior Civil Engineer, Social Cost of Carbon 

analysis/EA author
Supplemental Environmental Assessment April 2023 References

BNI Coal Ltd. Federal Coal Lease by Application

37

Chapter 5 References

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Supplemental Environmental Assessment April 2023 Appendix A

BNI Coal Ltd. Federal Coal Lease by Application

Appendix A

Social Cost of Greenhouse Gasses Calculations
This calculator was developed by Rebecca Moore, Senior Economist, BLM 970-226-9246 rmoore@blm.gov

Social Cost of Carbon Dioxide Calculator

Base Year: 2023 (the Base Year is often the current year and can be no later than the first year of emissions)

Year 1: 2023: (the first year of emissions)

Year of emissions CO2 emissions (metric tons)[1] Average, 5%[2,3,4] Average, 3%[2,3,4] Average 2.5%[2,3,4] 95th Percentile, 3%[2,3,4] Average, 5%[5,6] Average, 3%[5,6] Average 2.5%[5,6] 95th Percentile, 3%[5,6]

2023 1216367.14 $16 $54 $80 $162 $19,391,325 $66,032,923 $97,721,720 $197,220,552

2024 1216367.14 $16 $55 $82 $166 $19,034,408 $65,370,877 $96,888,093 $195,622,541

2025 1216367.14 $17 $56 $83 $169 $18,666,409 $64,691,378 $96,036,998 $193,949,162

2026 1216367.14 $17 $57 $84 $173 $18,291,346 $63,996,006 $95,169,782 $192,207,308

2027 1216367.14 $18 $59 $86 $176 $17,909,676 $63,287,341 $94,287,739 $190,403,467

2028 1216367.14 $18 $60 $87 $180 $17,522,878 $62,564,618 $93,392,107 $188,540,599

2029 1216367.14 $19 $61 $88 $183 $17,131,399 $61,830,307 $92,484,075 $186,624,721

[1] Annual GHG Estimates from Air Resource Specialist

[2] Per ton SC-CO2 Value (2020$/metric ton CO2)

[3] Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide, Interim Estimates under E.O. 13990. Interagency Working Group on Social Cost of Carbon, United States Government. February 2021.

[4] Social Cost estimates for emissions years beyond 2050 are estimated using an annual growth rate equal to the average annual growth in social cost estimates for the last five years of available estimates from the TSD (2046-2050)

[5] Present Value (in Base Year) of Estimated SC-CO2 by emissions year (2020$)

[6] The SCC estimates from the IWG represent the present value of damages from that year's emissions discounted back to the year of emissions. These columns take that value and discount to the base year to facilitate the total NPV calculation.

Present Value (in Base Year) of Estimated SC-CO2 for all CO2 emissions, 2020$)

Average, 5% Average, 3% Average 2.5% 95th Percentile, 3%

$127,947,441 $447,773,450 $665,980,514 $1,344,568,350
Social Cost of Methane Calculator

Base Year: 2023 (the Base Year is often the current year and can be no later than the first year of emissions)

Year 1: 2023: (the first year of emissions)

Year of emissions CH4 emissions (metric tons)[1] Average, 5%[2,3,4] Average, 3%[2,3,4] Average 2.5%[2,3,4] 95th Percentile, 3%[2,3,4] Average, 5%[5,6] Average, 3%[5,6] Average 2.5%[5,6] 95th Percentile, 3%[5,6]

2023 136.67 $747 $1,626 $2,120 $4,292 $102,143 $222,208 $289,673 $586,526

2024 136.67 $775 $1,673 $2,175 $4,420 $100,823 $221,964 $290,000 $586,481

2025 136.67 $802 $1,720 $2,230 $4,548 $99,397 $221,545 $290,139 $585,941

2026 136.67 $829 $1,767 $2,286 $4,677 $97,879 $220,963 $290,098 $584,935

2027 136.67 $856 $1,814 $2,341 $4,805 $96,279 $220,227 $289,887 $583,490

2028 136.67 $884 $1,861 $2,397 $4,934 $94,610 $219,346 $289,513 $581,633

2029 136.67 $911 $1,908 $2,452 $5,062 $92,882 $218,330 $288,986 $579,390

[1] Annual GHG Estimates from Air Resource Specialist

[2] Per ton SC-CH4 Value (2020$/metric ton CH4)

[3] Technical Support Document: Social Cost of Carbon, Methane, and Nitrous Oxide, Interim Estimates under E.O. 13990. Interagency Working Group on Social Cost of Carbon, United States Government. February 2021.

[4] Social Cost estimates for emissions years beyond 2050 are estimated using an annual growth rate equal to the average annual growth in social cost estimates for the last five years of available estimates from the TSD (2046-2050)

[5] Present Value (in Base Year) of Estimated SC-CH4 by emissions year (2020$)

[6] The SCC estimates from the IWG represent the present value of damages from that year's emissions discounted back to the year of emissions. These columns take that value and discount to the base year to facilitate the total NPV calculation.

Present Value (in Base Year) of Estimated SC-CH4 for all CH4 emissions, 2020$)

Average, 5% Average, 3% Average 2.5% 95th Percentile, 3%

$684,014 $1,544,583 $2,028,295 $4,088,395
Social Cost of Nitrous Oxide Calculator

Base Year: 2023 (the Base Year is often the current year and can be no later than the first year of emissions)

Year 1: 2023: (the first year of emissions)

Year of emissions N2O emissions (metric tons)[1] Average, 5%[2,3,4] Average, 3%[2,3,4] Average 2.5%[2,3,4] 95th Percentile, 3%[2,3,4] Average, 5%[5,6] Average, 3%[5,6] Average 2.5%[5,6] 95th Percentile, 3%[5,6]

2023 20.08 $6,385 $19,717 $28,801 $51,879 $128,240 $395,976 $578,423 $1,041,912

2024 20.08 $6,587 $20,154 $29,358 $53,087 $125,996 $392,965 $575,224 $1,035,114

2025 20.08 $6,789 $20,591 $29,914 $54,295 $123,676 $389,794 $571,836 $1,027,828

2026 20.08 $6,991 $21,028 $30,471 $55,502 $121,290 $386,474 $568,271 $1,020,088

2027 20.08 $7,193 $21,465 $31,028 $56,710 $118,852 $383,017 $564,541 $1,011,927

2028 20.08 $7,395 $21,902 $31,585 $57,918 $116,370 $379,433 $560,654 $1,003,376

2029 20.08 $7,597 $22,339 $32,141 $59,125 $113,856 $375,733 $556,621 $994,465

Present Value (in Base Year) of Estimated SC-NO for all N2O emissions, 2020$)

Average, 5% Average, 3% Average 2.5% 95th Percentile, 3%

$848,280 $2,703,392 $3,975,569 $7,134,708
Supplemental Environmental Assessment April 2023 Appendix B 

BNI Coal Ltd. Federal Coal Lease by Application

Appendix B

Public Comments 
Commenter Comment OSMRE Response to Comment

L. David Glatt

(North Dakota 

Department of 

Environmental Quality)

Care is to be taken during construction activity near any 

water of the state to minimize adverse effects on a water 

body. This includes minimal disturbance of stream beds 

and banks to prevent excess siltation, and the 

replacement and revegetation of any disturbed area as 

soon as possible after work has been completed. Caution 

must also be taken to prevent spills of oil and grease that 

may reach the receiving water from equipment 

maintenance, and/or the handling of fuels on the site. 

Guidelines for minimizing degradation to waterways during 

construction are attached.

Section 3.7 and Appendix D of the BLM’s 2020 EA 

(reference (1)) assesses the potential for impacts to 

water resources. Appendix B of the BLM’s 2020 EA 

(reference (1)) provides the extended Mine Plan and 

describes environmental protection measures for the 

Center Mine. BNI would implement erosion control 

measures, as needed, along stream channels to 

establish vegetation and reduce soil erosion. Once a 

stream channel has been deemed ready for reclamation, 

a professionally engineered stream reclamation plan 

would be submitted to the NDPSC for approval. Stream 

channel reclamation or reconstruction plans would be 

submitted and reviewed by the NDPSC, as well as by 

the State Water Commission and NDDEQ as members 

of the PSC’s advisory review committee. All runoff that 

would be in contact with disturbed soils would be 

controlled in sediment ponds. The water would be 

released from the ponds following testing and meeting 

compliance levels (reference (1)).

As previously noted, OSMRE incorporates by reference 

the water resources analyses from BLM’s 2020 EA, and 

they are not discussed further in this EA.

L. David Glatt

(North Dakota 

Department of 

Environmental Quality)

BNI Coal, Ltd. currently has North Dakota Pollutant 

Discharge Elimination System (NDPDES) permits to 

discharge stormwater and wastewater from its mining 

activities. Mining of the Federal coal tracts would be 

subject to the conditions of the permits in accordance with 

state rules and policies.

Comment noted. In addition, Section 3.7 and Appendix 

D of the BLM’s 2020 EA (reference (1)) assesses the 

potential for impacts to water resources. As previously 

noted, OSMRE incorporates by reference the water 

resources analyses from BLM’s 2020 EA, and they are 

not discussed further in this EA.

L. David Glatt

(North Dakota 

Department of 

Environmental Quality)

All solid waste materials must be managed and 

transported in accordance with the state's solid and 

hazardous waste rules. Appropriate efforts to reduce, 

reuse and/or recycle waste materials are strongly 

encouraged. As appropriate, segregation of inert waste 

from non-inert waste can generally reduce the cost of 

waste management. Further information on waste 

management and recycling is available from the 

department's Division of Waste Management at (701) 328-

5166.

Appendix B of the BLM’s 2020 EA (reference (1)) 

provides the extended Mine Plan and describes waste 

management for the Center Mine. BNI disposes of all 

non-coal waste in compliance with NDAC 69-05.2-19-04 

(disposal of non-coal waste). BNI is exempt from the 

Resource Conservation and Recovery Act (RCRA) (42 

U.S.C. 6901) because of their minimal use of products 

and/or recycling efforts in place for products covered by 

RCRA. As previously noted, OSMRE incorporates by 

reference the BLM’s 2020 EA; therefore, waste 

management is not discussed further in this EA.
Commenter Comment OSMRE Response to Comment

Steven Best (North 

Dakota Department of 

Water Resources)

There are no FEMA National Flood Insurance Program 

(NFIP) floodplains identified or mapped where the 

proposed project is to take place. No permit relative to the 

NFIP are likely required based on the current effective 

Flood Insurance Rate Map and State minimum standards. 

However, flood risk has been identified through the North 

Dakota Risk Assessment Mapservice and Base Level

Engineering (BLE) (ndram.dwr.nd.gov). In the absence of 

FEMA NFIP data, BLE is often considered best available 

data and is recommended to be considered in the design 

process. North Dakota has no formal NFIP permitting 

authority as all NFIP permitting decisions are considered 

by impacted NFIP participating communities, the 

community with zoning authority for the area in question. 

Please work directly with the local floodplain 

administrators of the zoning authorities impacted.

Section 3.7 and Appendix D of the BLM’s 2020 EA 

(reference (1)) assesses the potential for impacts to 

water resources. Appendix B of the BLM’s 2020 EA 

(reference (1)) provides the extended Mine Plan and 

describes environmental protection measures for the 

Center Mine. BNI would implement erosion control 

measures, as needed, along stream channels to 

establish vegetation and reduce soil erosion. Once a 

stream channel has been deemed ready for reclamation, 

a professionally engineered stream reclamation plan 

would be submitted to the NDPSC for approval. Stream 

channel reclamation or reconstruction plans would be 

submitted and reviewed by the NDPSC, as well as by 

the State Water Commission and NDDEQ as members 

of the PSC’s advisory review committee (reference (1)).

As previously noted, OSMRE incorporates by reference 

these analyses from BLM’s 2020 EA, and they are not 

discussed further in this EA.

Furthermore, OSMRE sent the Oliver County Planning 

Administrator/Director (local floodplain administrator) an 

outreach letter on January 23, 2023, but did not receive 

a response.

Steven Best (North 

Dakota Department of 

Water Resources)

In accordance with North Dakota Century Code §61-16.1-

38, any new construction or construction modifications on 

water storage impoundments, including dams or ponds,

may require a construction permit from the Department of 

Water Resources (DWR) based on the storage volume 

and hazard classification. Similarly, if any dams or ponds

are to be removed, we request that the DWR Regulatory 

Division be notified. Please contact the DWR Regulatory 

Division at 701-328-4956 if you have any questions.

Section 3.7 and Appendix D of the BLM’s 2020 EA 

(reference (1)) assesses the potential for impacts to 

water resources. Several stock water impoundments 

and dugouts would be removed by mining, and BNI 

provides adequate plans for their replacement in the 

post-mining environment (reference (1)). BNI is 

responsible for consultation with the DWR regarding any 

required permits.

As previously noted, OSMRE incorporates by reference 

these analyses from BLM’s 2020 EA, and they are not 

discussed further in this EA.
Commenter Comment OSMRE Response to Comment

Steven Best (North 

Dakota Department of 

Water Resources)

The Department of Water Resources’ (DWR) Engineering 

and Permitting Section reviewed the project location and 

determined that the project likely does not require a

surface drain permit or construction permit unless the 

project impacts sloughs, ponds, lakes (i.e., wetlands) or so 

long as Hagel Creek is not modified (i.e., deepened, 

widened, rerouted, etc.) Also, a permit may be required if 

the project will modify or impact the 4 dams (BNI Coal P20-1, P-20-2, P-20-3, Albers Dam) located within the T142 

N R84 W Section 20, or the drain (Drain Permit #2699 –

BNI COAL DRAIN) located within T141 N R83 W Section 

8. For more information on these requirements, please 

visit the Regulation & Appropriation tab on the DWR’s 

website (dwr.nd.gov) or contact the DWR’s Regulatory 

Division at 701-328-4956 or dwrregpermits@nd.gov.

Section 3.7 and Appendix D of the BLM’s 2020 EA 

(reference (1)) assesses the potential for impacts to 

water resources. The Proposed Action does not include 

direct modifications to Hagel Creek. Several stock 

water impoundments and dugouts would be removed by 

mining, and BNI provides adequate plans for their 

replacement in the post-mining environment (reference 

(1)). BNI is responsible for consultation with the DWR 

regarding any required permits.

As previously noted, OSMRE incorporates by reference

these analyses from BLM’s 2020 EA, and they are not 

discussed further in this EA.

Steven Best (North 

Dakota Department of 

Water Resources)

Initial review indicates the project does not require a 

conditional or temporary permit for water appropriation. 

However, if surface water or groundwater will be diverted 

for construction of the project, a water permit will be 

required per North Dakota Century Code § 61-04-02. 

Please consult with the Department of Water Resources 

Water Appropriation Division if you have any questions at 

701-328-2754 or appropinfo@nd.gov.

Section 3.7 and Appendix D of the BLM’s 2020 EA 

(reference (1)) assesses the potential for impacts to 

water resources. BNI has a North Dakota State Water 

Commission Conditional Water Permit (No. 3973) for 

160 acre-feet of water that is identified for industrial 

water use (reference (1)). 

As previously noted, OSMRE incorporates by reference 

these analyses from BLM’s 2020 EA, and they are not 

discussed further in this EA.

Steven Best (North 

Dakota Department of 

Water Resources)

The Department of Water Resources maintains a network 

of observation wells across the state for monitoring the 

water levels and quality in glacial and bedrock aquifers.

These wells are often installed in road and highway rightsof-way to limit inconvenience to the adjacent landowners. 

Department of Water Resources observation wells have a

yellow protective casing extending between 1 and 3 feet 

above ground surface, and their locations are marked with 

a stake. If an observation well is encountered during 

project activities and must be removed, please contact the 

Water Appropriation Division. The Department of Water 

Resources hopes to keep all observation wells, but 

otherwise will ensure the well is properly abandoned.

Comment noted, BNI is responsible for consultation with 

the Department of Water Resources regarding potential 

impacts to observation wells. Section 3.7 and Appendix 

D of the BLM’s 2020 EA (reference (1)) assesses the 

potential for impacts to water resources. As previously 

noted, OSMRE incorporates by reference these 

analyses from BLM’s 2020 EA, and they are not 

discussed further in this EA.
Commenter Comment OSMRE Response to Comment

Steven Best (North 

Dakota Department of 

Water Resources)

In section 1.5.2 (Outreach), the incorrect year is listed. It 

should be 2023 rather than 2026.

This typographical error has been corrected.

Chad Orn (North 

Dakota Department of 

Transportation)

This project should have no adverse effect on the North 

Dakota Department of Transportation highways.

However, if because of this project any work needs to be 

done on highway right of way, appropriate permits and risk 

management will need to be obtained from the 

Department of Transportation District Engineer, Larry 

Gangle at 701-328-6955

Comment noted. BNI is responsible for consultation with 

the Department of transportation regarding potential 

work within highway rights of way. 

As previously noted, the BLM’s 2020 EA (reference (1)) 

eliminated transportation from further analysis. OSMRE 

incorporates the BLM’s 2020 EA by reference.

Dennis Barnhart Dennis Barnhart contacted OSMRE via telephone on 

January 31, 2023. He said he had questions but was able 

to resolve them on his own. He lives by the Center Mine 

and has no project concerns. He also said he also spoke 

to BNI representatives. Lastly, he asked that OSMRE 

contact his sister-in-law Marylynn Barnhart because she 

also had questions. 

Comment noted. OSMRE attempted to contact Marylynn 

Barnhart but did not receive a return phone call.

Sharon and George 

Bullinger

Sharon Bullinger contacted OSMRE via telephone on 

January 31, 2023. 

OSMRE returned the telephone call and spoke with 

George Bullinger. He has rights to coal near the Center 

Mine and he wanted to know if this action meant that the 

mine was interested in leasing his coal. OSRME

explained that this action only covered already leased 

federal coal. He appreciated the clarification and had no 

further comment.