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ENVIRONMENTAL ASSESSMENT

Marathon Oil Company Bridges Project

Submitted To: Sabine National Forest Angelina/Sabine Ranger District 5050 State Highway 21 East Hemphill, Texas 75948 Submitted By: Golder Associates Inc. 44 Union Boulevard, Suite 300 Lakewood, Colorado 80228 USA May 23, 2011 DRAFT 093-81994

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Table of Contents

1.0 INTRODUCTION .............................................................................................................................. 1

1.1 Background .................................................................................................................................. 1

1.2 Purpose ........................................................................................................................................ 1

1.3 Need ............................................................................................................................................. 2

1.4 Regulatory Authority ..................................................................................................................... 2

1.5 Conformance with the USFS Land Use Plan ............................................................................... 2

1.6 Decisions to Be Made .................................................................................................................. 4

1.7 Public Involvement ....................................................................................................................... 5

1.8 Issues ........................................................................................................................................... 5

2.0 ALTERNATIVES .............................................................................................................................. 7

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

2.2 Alternatives Considered in Detail ................................................................................................. 7

2.2.1 Alternative 1 (No Action) .......................................................................................................... 7

2.2.2 Alternative 2 (Proposed Action) ............................................................................................... 7

2.3 Management Requirements, Design Criteria, and Monitoring ................................................... 24

2.3.1 Management Requirements ................................................................................................... 24

2.3.2 Design Criteria ....................................................................................................................... 25

2.3.3 Monitoring .............................................................................................................................. 26

2.4 Alternatives Considered but Eliminated from Detailed Study .................................................... 27

3.0 ENVIRONMENTAL CONSEQUENCES ........................................................................................ 28

3.1 Introduction ................................................................................................................................. 28

3.1.1 Area Description..................................................................................................................... 28

3.1.2 Effects Analysis Considerations ............................................................................................. 29

3.2 Soil ............................................................................................................................................. 30

3.2.1 Environmental Baseline ......................................................................................................... 30

3.2.2 Effects of Implementation ...................................................................................................... 32

3.3 Water Quality and Quantity ........................................................................................................ 33



3.4 Air ............................................................................................................................................... 40

3.4.1 Criteria Pollutants ................................................................................................................... 40

3.4.2 Greenhouse Gases ................................................................................................................ 41



3.5 Vegetation .................................................................................................................................. 49



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3.6 Wildlife ........................................................................................................................................ 54



3.7 Proposed, Endangered, Threatened and Sensitive Species (PETS) ........................................ 61



3.8 Management Indicator Species.................................................................................................. 77



3.9 Wetlands and Riparian Areas .................................................................................................... 86



3.10 Socio-economics ........................................................................................................................ 87



3.11 Recreation and Visual Resources .............................................................................................. 91



3.12 Cultural Resources ..................................................................................................................... 94



3.13 Public Health and Safety ............................................................................................................ 95



3.14 Noise .......................................................................................................................................... 97



3.15 Transportation .......................................................................................................................... 100

3.15.1 Environmental Baseline ....................................................................................................... 100

3.15.2 Effects of Implementation .................................................................................................... 100

3.16 Minerals .................................................................................................................................... 102

3.16.1 Environmental Baseline ....................................................................................................... 102

3.16.2 Effects of Implementation .................................................................................................... 104

4.0 PREPARERS AND CONTRIBUTORS TO ANALYSIS ................................................................ 106

5.0 REFERENCES ............................................................................................................................. 107

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List of Tables

Table 2.2-1 Access, Gathering Line, and Electric Line Routes for Each Pad ...................................... 10 Table 2.2-2 Disturbed Area Summary .................................................................................................. 14 Table 3.2-1 Soil Disturbance Estimates for the Proposed Action ........................................................ 31 Table 3.3-1 Acres of Land by Ownership in the Bayou Blue and Ragtown Watersheds ..................... 36 Table 3.3-2 Estimated Sedimentation Loads, in Tons of Sediment Per Year, for Baseline,

Present and Proposed Activities ....................................................................................... 36 Table 3.3-3 Acres or Miles of Disturbance per Activity ........................................................................ 40 Table 3.4-1 Center, Texas Mean Monthly Temperature Ranges and Total Precipitation ................... 42 Table 3.4-2 San Augustine Airport, NAAQS and Measured Pollutant Values, January through

December 2006 ................................................................................................................. 44 Table 3.4-3 Construction Phase Estimated Criteria Pollutant Emissions ............................................ 46 Table 3.4-4 Construction Phase Estimated GHG Emissions ............................................................... 46 Table 3.4-5 Operation Phase Estimated Criteria Pollutant Emissions (tons per year) ........................ 48 Table 3.4-6 Operation Phase Estimated Greenhouse Gases (tons per year) ..................................... 48 Table 3.5-1 Land Type Phase Data ..................................................................................................... 52 Table 3.6-1 Common Terrestrial Wildlife Species in the Bridges Project Area .................................... 55 Table 3.6-2 Length of Edge Created by the Bridges Project ............................................................... 59 Table 3.10-1 Estimated Economic Benefits Gas Development ............................................................. 88 Table 3.10-2 Economic Benefits Gas Development, Texas .................................................................. 89 Table 3.10-3 Health Care Services, Shelby County, Texas ................................................................... 89 Table 3.15-1 Anticipated Increase in Vehicle Volume Associated with the Bridges Project ................ 101 Table 3.16-1 Geologic Prognosis for the Bridges Project .................................................................... 103

List of Figures

Figure 1 Project Location Figure 2 Associated Project Infrastructure Figure 3 Access Roads Figure 4 Pipelines Figure 5 Electric Lines Figure 6 Typical Well Pad Layout Figure 7 Hydraulic Fracturing Pond Locations Figure 8 Existing Wells within One Mile Figure 9 Soil and Watersheds Figure 10 Forest Types Figure 11 Locations of Non-Native Invasive species Figure 12 Locations of Bald Eagle Nests Figure 13 National Wetland Inventory Figure 14 High Potential Louisiana Pine Snake Areas Figure 15 Locations of RCW Clusters Figure 16 FEMA Mapped 100-Year Floodplains Figure 17 Shreveport, LA 1989-1993 Wind Rose

List of Appendices

Appendix A Surface Use Data Summary Appendix B Biological Evaluation Appendix C Emissions Calculations Detail

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List of Acronyms

AIAN American Indian and Alaskan Native APD Application for Permit to Drill AQRV Air Quality Related Values ASL Above Sea Level BACT best available control technology BE Biological Evaluation BLM Bureau of Land Management BMP Best Management Practice CAA Clean Air Act CFR Code of Federal Regulations CH4 Methane CO Carbon Monoxide CO2 Carbon Dioxide CO2e Carbon Dioxide equivalent COAs Conditions of Approval dBA Decibel EA Environmental Assessment ECS ecological classification system EPA Environmental Protection Agency F Degrees Fahrenheit FONSI Finding of No Significant Impact GHG Greenhouse Gasses GIS Geographic Information System HDD Horizontal Directional Drilling HUC Hydrologic Unit Code ID Team Interdisciplinary Team IPMP Integrated Pest Management Plan LTP land type phase MA Management Area Marathon Marathon Oil Company mg/L Milligrams per Liter MIS Management Indicator Species MPOD Master Plan of Development MSDS Material Safety Data Sheet MSUPO Master Surface Use Plan of Operations MWD Measurement While Drilling N2O Nitrous Oxide NAAQS National Ambient Air Quality Standards NEPA National Environmental Policy Act NFGT National Forests and Grasslands in Texas NFS National Forest System NFSR National Forest System Road** NNIPS Non-native Invasive Plant Species NO2 Nitrogen Dioxide NOx Nitrogen Oxides NRCS Natural Resources Conservation Service NSPS New Source Performance Standards O3 Ozone OHV Off-Highway Vehicle ORV Off-Road Vehicle OSHA Occupational Safety and Health Administration PM Particulate Matter PSD Prevention of Significant Deterioration

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psi Pounds per Square Inch ROD Record of Decision ROW Right-of-Way SCADA Supervisory Control and Data Acquisition SHB Shelby County Road SMZ Streamside Management Zone SNF Sabine National Forest SO2 Sulfur Dioxide SPCC Spill Prevention, Control, and Countermeasure SUP Special Use Permit SWPPP Stormwater Pollution Prevention Plan TAC Texas Administrative Code TCEQ Texas Commission on Environmental Quality TES Threatened, Endangered, or Sensitive The Plan National Forests and Grasslands in Texas Land and Resource Management Plan TMR Travel Management Rule TPWD Texas Parks and Wildlife TxMUTCD Texas Manual on Uniform Traffic Control Devices USDA United States Department of Agriculture USFS United States Forest Service USFWS United States Fish and Wildlife Service VOC Volatile Organic Compound VOQ Visual Quality Objectives

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1.0 INTRODUCTION

1.1 Background

The Sabine National Forest (SNF) proposes to approve a master surface use plan of operations

(MSUPO) submitted by Marathon Oil Company (Marathon) including any terms and Conditions of

Approval (COAs), and issue Special Use Permits for the associated pipelines, electric lines, and access

roads. Marathon has leased minerals from the Bureau of Land Management (BLM) beneath the surface

of the SNF in Shelby County, Texas (Figure 1). Marathon proposes to explore and extract those minerals

by drilling horizontal wells from 21 pads on both National Forest System (NFS) and fee lands. Marathon

proposes to develop the Bridges Project on NFS lands managed by the National Forests and

Grasslands in Texas (NFGT) and adjacent private lands that include privately owned minerals and BLM

split estate minerals (private surface right ownership and federal mineral right ownership). This proposal

consists of constructing, drilling, completing, operating, and abandonment of up to 124 natural gas

production wells and three saltwater injection wells. Marathon proposes to use vertical and directional

drilling technology to drill the 124 natural gas production wells from 21 locations rather than develop a

new pad for each well. As a result, this plan would have much less surface disturbance than if wells were

drilled vertically from individual pads. Assuming a two-acre pad for an individual well, the reduction in

surface area for pads would be about 50 percent.

Additional wells may be drilled from these pads if field rules defined in the Railroad Commission of Texas

(TRRC) Gas Docket change to allow closer spacing of horizontally drilled wells. The wells would be

drilled on 12 new well pads and nine existing operating well pads. Twelve of these well pads would be

located on SNF surface, six well pads located on private surface with BLM minerals being penetrated

(split estate), and three well pads located on private surface with private mineral penetration only (fee).

The proposed project also includes use of existing, improved, or newly developed access roads,

pipelines, communication equipment, and existing and newly installed electric lines required for gas

extraction. The NFGT and the BLM administer the federal mineral estate in the Bridges area.

1.2 Purpose

The purpose of the action is for the United States Forest Service (USFS), SNF to approve the Bridges

Project MSUPO submitted by Marathon and issue special use permits. Marathon proposes to explore

and develop gas resources on Federal Leases TXNM 108071, TXNM 108068, TXNM 105599, TXNM

37867, and TXNM 80155 consistent with existing federal lease rights. Leaseholders retain rights to drill,

extract, remove, and market gas products. National mineral leasing policies, and the regulations by

which they are enforced, recognize the statutory right of leaseholders to develop federal mineral

resources to meet continuing national needs and economic demands while conserving environmental

resources. The proposed project would allow the federal leaseholder, Marathon, to develop the gas

resources on federal leaseholds.

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1.3 Need

The Interdisciplinary Team (ID Team) identified the need for the proposed action after Marathon

submitted a master plan of development (MPOD) and a MSUPO. The application was submitted to the

SNF and BLM to exercise Marathons lease rights in compartments 36, 37, 39-45, 48-50, and 56 and drill

up to 124 natural gas production wells, and associated pipelines, access roads, and electric lines.

Exploration and development of federal mineral resources by private entities is an integral part of the

federal governments national energy policy through the National Energy Policy Act of 2005, which

implements policy for dependable, affordable, and environmentally sound production and distribution of

energy.

1.4 Regulatory Authority

Regulatory authority for the project comes from several different agencies and regulations. BLM is

authorized to lease federal lands for gas development under the authority of the following:

The Mineral Leasing Act of 1920 as amended

The Mining and Minerals Policy Act of 1970

The Federal Land Policy and Management Act of 1976

The National Materials and Minerals Policy

Research and Development Act of 1980

The Federal Onshore Gas Leasing Reform Act of 1987

The wells will be extracting BLM leased minerals, so the wells will be as follows:

Permitted through BLM Application for Permit to Drill (APD) process

Subject to the MSUPO

National Environmental Policy Act (NEPA) Environmental Assessment (EA) which will be submitted through the USFS as lead agency

Subject to BLM Handbook H-3150 (Rel. 3-289 6/7/94)

The USFS will establish the terms and COAs for both the MSUPO and any associated Surface Use

Authorization (36 CFR 228 Part 106 108) because some of the associated well pad, access road, and

pipeline disturbance will occur on SNF land. The USFS has principal responsibility for compliance with

the NEPA on National Forests.

1.5 Conformance with the USFS Land Use Plan

The activities proposed by this project will be accomplished in accordance with the objectives and

guidelines provided in the 1996 Revised Land and Resource Management Plan (the Plan) for the

National Forests and Grasslands in Texas (NFGT) (USFS 1996). The Plan groups lands with similar

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resource characteristics into management areas (MA) and sets goals and objectives for both the entire

NFGT and each MA. Within a given MA, certain activities may be limited, so that desired future

conditions would be met, or at least approached. MAs may be defined by spatial or geographic

characteristics or by related sets of activities. The project area associated with the proposed action falls

within four MAs:

MA-1 Upland Forest Ecosystems

MA-2 Red-Cockaded Woodpecker (RCW) Emphasis

MA-4 Streamside Management Zones

MA-10b Special Use Permit Sites

The Plan describes the general desired future conditions for MA-1 as a range of natural settings, but all

would involve an interrelationship with the forested ecosystems. Management activities would be evident

throughout this area due to a focus on aggressive restoration of longleaf and shortleaf pine communities,

as well as regeneration of all the forest communities. Many recreation activities are obvious throughout

the area and include many motorized and non-motorized activities.

Mineral exploration and production is an approved land use in MA-1. The Plan (page 89) states:

The goals of this management area are to: Provide opportunity for timber production, mineral exploration and development, and limited grazing while maintaining a predominantly rural appearing landscape, clean water, productive soil, little soil erosion, viable populations of wildlife, and habitat for threatened, endangered, or sensitive (TES) species of plants and animals.

In addition, standard MA-1-35 (the Plan page 92) states that, Public owned minerals will be available for

leasing.

The Plan describes MA-2 as Landscapes managed for large, older trees within the longleaf pine-little

bluestem, shortleaf pine-oak, and loblolly pine-oak dominated communities, while offering a wide range of

compatible multiple uses, but primarily for the recovery of the RCW.

The specific goals of MA-2 (page 102, the Plan) include: Provide a range of mature pine forest habitats

that allow populations of TES species dependent on these communities to flourish. Provide the best

possible habitat for recovery of RCW populations and sub-populations, while allowing maximum potential

for effective dispersal and social interaction of individuals between clusters.

Mineral exploration and development is an approved activity, but is subject to the standards MA-2-80-4.6

(the Plan page 120):

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Permanent clearings for non-timber purposes may not occur if the loss of habitat would reduce the capability of the habitat management area (HMA) to support its identified RCW population objective. In management intensity levels (MIL) 3 and 4, clearings are not allowed within 1/4 mile of RCW groups. Clearings are not allowed if foraging habitat is limited, or if the clearing completely severs a cluster or recruitment stand from its foraging habitat.

The Plan defines MA-4 (streamside management zones (SMZ)) as including perennial and intermittent

streams, rivers, and riparian areas. Most of these areas occur as streamside corridors cutting through

other management areas. Within the project area, this MA occurs almost exclusively as mesic forests

along intermittent springs. These areas will be managed to maintain the role and function of aquatic,

riparian, and wetland ecosystems while providing opportunities for compatible multiple uses (the Plan

p. 151).

Management objectives relative to MA-4 include standard MA-4-62, which states; make public owned

leasable minerals available for leasing.

Forest-wide Standard-104 (FW-104) states that; All APDs a well (federally owned minerals), operating

plans or permits (privately owned minerals), and seismic exploration permit applications will be subject to

a site-specific analysis appropriate to the rights involved and activity proposed. This analysis considers

the anticipated effects on other resource values, mitigating measures, and applicable law, regulation and

policy.

The Plan allocates special use permit sites, such as the project proposed by Marathon, to MA-10b. This

MA provides authorization and management of specific uses on NFGT land by private parties for activities

beneficial to the public or for exercising basic rights. The desired future condition [for MA-10b] is a

pattern of special uses established to provide facilities, services, or opportunities that are in the general

public interest and, at the same time, reflect environmental sensitivity to other resource values. These

permanent or long-term uses are ordinarily those which, due to the nature of the use and the location of

the affected US land, cannot logically be accommodated on private land (the Plan, page 281).

1.6 Decisions to Be Made

The decision to be made is whether to approve the MSUPO including any terms and COAs, and issue

Special Use Permits for the associated pipelines, electric lines, and access roads. If the USFS decides to

approve the MSUPO, the BLM will be notified, and the BLM must approve the MPOD before Marathon

may begin any surface disturbing activities. The decision would apply only to activities proposed on lands

administered by the SNF.

The responsible official must also determine if the selected alternative would or would not be a major

federal action, significantly affecting the quality of the human environment. If the responsible official

determines that this project would not significantly affect the quality of the human environment, then the

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responsible official can prepare and sign a finding of no significant impact (FONSI) that would approve

the project and allow it to proceed. If the responsible official determines that the selected alternative

would significantly affect the quality of the human environment, then an environmental impact statement

and a record of decision must be prepared and signed before the project may proceed.

1.7 Public Involvement

Project scoping was conducted by the ID Team to determine the issues related to the proposed action

and to help develop potential alternatives. Public notification began on January 14, 2011, when the SNF

District Ranger mailed a scoping letter to interested and affected agencies, organizations, and individuals,

and posted the notification letter on the NFGT website. The letter outlined the proposed action and

requested input.

Nine responses to the public notification letter were received. Of the nine responses, seven raised issues

of concern, one was supportive, and one was neutral. Nine issues raised in the eight responses received

include the following:

1. Access and transportation issues related to construction and development traffic

2. Noise during construction, completion, and production, particularly compressor noise during production

3. Impacts to cultural and/or historic resources

4. Inspection and maintenance of pipelines

5. Federal mineral royalties

6. Consideration of above ground vs. buried power lines

7. Impacts to soil and water

8. Recouping value of the timber removed

9. Fragmentation effects on wildlife

1.8 Issues

We separated the issues into two groups: significant and non-significant issues. Significant issues were

defined as those directly or indirectly caused by implementing the proposed action. Non-significant

issues were identified as those: (1) outside the scope of the proposed action; (2) already decided by law,

regulation, the Plan, or other higher level decision; (3) irrelevant to the decision to be made; or

(4) conjectural and not supported by scientific or factual evidence. NEPA regulations require this

delineation in Sec. 1501.7, identify and eliminate from detailed study the issues which are not

significant or which have been covered by prior environmental review (Sec. 1506.3)

The ID Team identified sixteen significant resource concerns to be evaluated in this environmental

assessment (EA): soil, water, air, vegetation, wildlife, TES species, Management Indicator Species,

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riparian/wetland habitat, socio-economics, recreation and visual resources, cultural resources, public

health and safety, noise, transportation, and minerals.

As for significant issues, the USFS identified 12 issue topics from the nine issues raised during scoping.

These issue topics include the following:

Issue 1: The proposed activities may affect biological diversity by clearing existing forest communities. Addressed in Section 3.5.

Issue 2: The proposed activities may affect terrestrial and aquatic wildlife by altering vegetation communities and increasing fragmentation. Addressed in Sections 3.5 and 3.6.

Issue 3: Increased traffic during construction and well completion may affect wildlife due to mortality from collisions with vehicles or increased noise. Addressed in Sections 3.6.

Issue 4: The proposed activities may affect species protected under the Endangered Species Act or USFS Sensitive Species; of particular concern is the RCW. Addressed in Section 3.5.

Issue 5: The proposed activities may affect water quality due to increased soil erosion, spills of chemicals or contaminated water from natural gas development. Addressed in Sections 3.3.

Issue 6: Water use for drilling and completions may affect local water supply. Addressed in Sections 3.3.

Issue 7: Noise from the proposed activities may affect the public. Addressed in Section 3.14.

Issue 8: Air emissions from the proposed activities may reduce air quality, visibility or contribute to Greenhouse Gas emissions. Addressed in Section 3.4.

Issue 9: The proposed activities may affect visual quality and aesthetics. Addressed in Section 3.11.

Issue 10: Increased traffic may cause delays and/or degrade roads. Addressed in Section 3.15.

Issue 11: The proposed activities may affect mineral claims of nearby mineral and land owners. Addressed in Section 3.16.

Issue 12: There is the potential for explosions or fires from the natural gas pipelines. Addressed in Section 3.13.

The following issues would be considered non-significant and would not be discussed further in this

document:

1. Effects to parklands, roadless areas, wilderness, municipal watersheds, or wild and scenic rivers. None of these areas would be impacted from proposed actions described in this EA.

2. Effects to civil rights and minority groups. None of the proposed activities would treat or affect any groups differently than any other groups.

3. No federal, state, or local laws would be violated with implementation of the proposed actions described in this EA. The Plan standards would be implemented for all actions.

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2.0 ALTERNATIVES

2.1 Introduction

The ID Team examined the issues and developed alternatives to the proposed action. The team

considered, in detail, alternatives that addressed one or more of the major issues identified in scoping

and also met the need for action. Two alternatives were selected for detailed study: the proposed action

and the no action alternative. The no action alternative may not meet the need for action, but provides a

baseline for comparison of the action alternative.

2.2 Alternatives Considered in Detail

2.2.1 Alternative 1 (No Action)

Under this alternative, SNF would not approve the MSUPO and BLM would not approve the MPOD. No

new wells, access roads, or gathering pipelines would be constructed. Marathon acquired the lease

rights under the authority of the Mineral Leasing Act for Acquired Lands of 1947. If this alternative is

selected, Marathon would not be able to exercise their lease rights.

2.2.2 Alternative 2 (Proposed Action)

The SNF has authority to approve only the surface activities proposed on NFS land. This would include

pads A, B, D, E, G, H, I, II1, II2, O, Q, R, and S. The remaining nine pads (AA, C, F, J-N, and P) would

be on private surface (see MPOD). These pads and their infrastructure would be integral to the proposed

action and meet the definition of similar actions. Similar actions are defined in the Council on

Environmental Quality Regulations Implementing NEPA (40 CFR Part 1508):

Similar actions, which when viewed with other reasonably foreseeable or proposed agency actions, have similarities that provide a basis for evaluating their environmental consequences together, such as common timing or geography. An agency may wish to analyze these actions in the same impact statement.

Therefore, they are included in the proposed action for analyses.

2.2.2.1 General

The Bridges Project area would be located approximately 20 miles east-southeast of Center, Texas, in

Shelby County (Figure 1). The project would have up to 124 natural gas wells and three saltwater

injection wells on 21 total well pads: 12 well pads on USFS surface and nine well pads on nearby private

lands. The wells would be located south of Farm-to-Market Road (FM) 139 and FM 3184 and

immediately north and south of FM 2261. Access roads would connect the well pads to National Forest

System Road (NFSR) 106, 125, 126, 126A, 126C, 126D, 141, 148, Shelby County Road (SHB) 2922, and

FM 2261. If the wells would be successful, gathering pipelines would be installed. All gathering lines

from the wells may connect to the anticipated Tenaska midstream pipeline system. The anticipated

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Tenaska pipeline system and project is a separate project and proposed action from Marathons Bridges

proposed action. The anticipated Tenaska midstream pipeline would take Marathons produced natural

gas from the Bridges Project to market.

Operations would occur on federal leases TXNM 108071, TXNM 108068, TXNM 105599, TXNM 37867,

and TXNM 80155 and would include the following actions:

Clearing and leveling five-to-seven acre sites for each well pad to accommodate drilling equipment. Approximately 30.6 acres (6.9 acres on NFS land) of existing pad area would be utilized and approximately 90.0 acres (61.3 acres on NFS land) would be new disturbance.

Approximately 26.1 miles (22.7 miles on NFS land) of existing roads would be improved and approximately 0.7 miles (0.6 miles on NFS land) of new road would be constructed for the proposed action.

Approximately 11.0 miles (4.9 miles on NFS land) of existing one-phase electric line would be upgraded to three-phase. Approximately 23.3 miles (18.8 miles on NFS land) of new electric lines collocated with access roads and approximately 0.4 miles of new greenfield electric line would be needed to bring power to the well pads.

Approximately 5.6 miles (3.2 miles on NFS land) of existing pipeline would be utilized. Approximately 17.4 miles (14.9 miles on NFS land) of pipeline would be co-located with access roads and approximately 0.5 miles of greenfield pipeline would be installed for the proposed action.

Moving in and rigging up drilling equipment.

Conducting drilling operations for approximately 45 days for each well, until the well is drilled to the target horizon.

Testing for production capability.

Installation of short-term aboveground water pipelines.

Completions of the well for production purposes would take approximately one month following drilling and testing.

Installing pipeline and production facilities including tank battery and compressor.

Maintaining the access roads, pipelines, and electric lines.

Reducing the well pads footprint once drilling is completed to an area necessary for production activities and equipment.

Revegetating areas in the well pad site no longer needed during the production phase.

Plugging wells and reclaiming all disturbed areas if the wells are not productive.

The proposed size of the developed well pads would be five-to-seven acres to accommodate drilling

equipment and facilities, including: pad construction equipment; drilling equipment; drilling fluid

containers; well completion equipment such as the fracture process water storage tanks; support facilities

including a tank battery for condensate liquid storage; and stockpiled topsoil for future site reclamation. It

would be necessary to remove all the trees within the well pad developed areas. The USFS would be

reimbursed at fair market value for all merchantable trees removed. After the trees are removed, stumps,

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slash, and brush would be mulched as stated in the MSUPO or removed from NFS land. The topsoil from

the well pad areas would be stockpiled on site and protected from erosion. The well pad areas would

then be graded to ensure proper drainage and to construct the necessary berms and barriers to capture

all potential contaminants on the well pads. The well pads would be stabilized with an appropriate depth

of rock aggregate and appropriate best management practices (BMPs) would be installed.

All NFS roads used for access would be stabilized with aggregate to accommodate trucks and heavy

equipment involved. All necessary road improvements would comply with SNF specifications. New and

upgraded access roads would require tree harvesting and vegetation removal in order to connect the well

pad with one of the maintained NFSR, FM, and/or SHB roads (Figures 2 and 3).

The natural gas gathering lines for each well pad would be constructed and buried to a minimum depth of

48 inches (four feet). The gathering lines for all pads, except Pad I, would follow existing NFSR, FM,

and/or SHB roads, utility rights-of-way (ROW), and newly cleared access roads to connect to the trunk

line. The gathering line for Pad I would head westerly until it connects to the gathering line for Pad H.

These gathering lines would be located to reduce the linear disturbance by taking the shortest pathway or

following already disturbed areas (along roads) to the trunk line (Figures 2 and 4). Pipelines along

existing access roads would only require tree removal if the existing access road ROW is not wide

enough for pipeline installation. A trenching machine would be used during pipeline construction to

minimize soil and contour disturbance. The stormwater pollution prevention plan (SWPPP) submitted

with the MSUPO by Marathon must be implemented during and after well pad and infrastructure

construction. Monitoring described in the SWPPP would be conducted throughout the life of the wells.

Overall, the project area would result in occupying a total of 105.1 acres of pre-disturbed land and 223.4

acres of newly disturbed land on the SNF. Additionally, the project area would result in occupying a total

of 47.8 acres of pre-disturbed land and 67.0 acres of newly disturbed land on private land. A total of

443.4 acres would be disturbed for the project and 162.0 acres would go through interim reclamation

during the production phase of the project. Approximately 281.4 acres would be un-reclaimed during the

production phase for the life of the project.

Planned activities for each pad are summarized in Table Error! No text of specified style in

document.-1, below.

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Table Error! No text of specified style in document.-1 Access, Gathering Line, and Electric Line Routes for Each Pad

Site Name Pad

# of Wells

Surface Ownership

Mineral Ownership Directions to the Well Pad Pipeline Route Electric Line Route

Bridges AA 10 Private Federal From TX-87, travel 2.5 miles east on FM 139 to FM 2427. Travel 3.5 miles southeast on FM 2427 to NFSR 125. Turn left on NFSR 125 and travel 1.5 miles northeast. Turn left on SHB 2922 and travel 0.5 mile north to Pad AA on the left.

The gathering line follows the access road from Pad AA east to SHB 2922, then follows SHB 2922 south and NFSR 125 southwest to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

Existing line would be upgraded to three-phase from the junction of FM 2427 and NFSR 106, traveling northeast along NFSR 125. New line would tie in to existing line along NFSR 125 approximately 0.75 mile northeast of the intersection of NFSR 125 and FM 2427. New line would follow NFSR 125 northeast and SHB 2922 north to Pad AA.

A 8 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Travel 3.5 miles southeast on FM 2427 to NFSR 125. Turn left on NFSR 125 and travel 1.5 miles northeast. Turn left on SHB 2922 and travel 1.0 mile north. Turn right onto the unnamed access road to Pad A.

The gathering line follows the access road from Pad A southeast to SHB 2922, then follows SHB 2922 south and NFSR 125 southwest to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

New line would tie in to new line at Pad AA. New line would follow SHB 2922 north, and an unnamed access road northeast to Pad A.

B 8 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a right on NFSR 126 and then an immediate left onto NFSR 126C. Travel 0.5 mile on NFSR 126C, then bear left onto NFSR 126C2 heading east to Pad B.

The gathering line from pad B follows NFSR 126C2 west, NFSR 126C west, and NFSR 126 northeast to the anticipated Tenaska Pipeline at the intersection of NFSR 126 and NFSR 126B.

New line would tie in to existing line at the intersection of NFSR 126 and NFSR 126A. From the tie in, new line would follow NFSR 126 southwest, NFSR 126C southeast, and NFSR 126C2 east to Pad B.

C 10 Private Federal and Fee

From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a right on NFSR 126 and then an immediate left onto NFSR 126C. In less than 0.5 mile, take the second right off NFSR 126C NFSR 126C1 heading south to Pad C.

The gathering line from Pad C follows an unnamed access road north, NFSR 126C west, and NFSR 126 northeast to the anticipated Tenaska Pipeline at the intersection of NFSR 126 and NFSR 126B.

New line would tie in to the new line to Pad B at NFSR 126C. From the tie in, new line would follow an unnamed access road south to Pad C.

D 8 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a right on NFSR 126 and then an immediate left onto NFSR 126C. Travel 0.75 mile along NFSR 126C to Pad D.

The gathering line from pad D follows NFSR 126C northwest, and NFSR 126 northeast to the anticipated Tenaska Pipeline at the intersection of NFSR 126 and NFSR 126B.

New line would tie in to the new line to Pad B at NFSR 126C. From the tie in, new line would follow NFSR 126C southeast to Pad D.

E 6 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a left onto NFSR 126 and travel 1.5 miles northeast. Turn right onto NFSR 126A and travel 1.0 mile to Pad E on the west side of the road.

The gathering line from Pad E follows NFSR 126A northwest and NFSR 126 west to the anticipated Tenaska Pipeline at the intersection of NFSR 126 and NFSR 126B.

Existing line would be upgraded to three-phase at the intersection of NFSR 126 and NFSR 126A, following NFSR 126A southeast. New line to Pad E would tie in to existing line off NFSR 126A.

F 6 Private Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a left onto NFSR 126 and travel 1.5 miles northeast. Turn right onto NFSR 126A and travel 2.0 miles to Pad F on the west side of the road.

The gathering line for Pad F travels northwest along NFSR 126A to pad E.

Existing line would be upgraded to three-phase from Pad E following NFSR 126A southeast. In addition, the existing line travelling south from Pad F to electric lines connecting to Pads N and O would be upgraded to phase 3 lines.

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Site Name Pad

# of Wells

Surface Ownership


G 6 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a left onto NFSR 126 and travel 2.0 miles to NFSR 141. Turn right onto NFSR 141 and travel 1.25 miles southeast. Turn right onto an unnamed access road heading south to pad G.

The gathering line from pad G follows an unnamed access road north, NFSR 141 northwest and NFSR 126 west to the anticipated Tenaska Pipeline at the intersection of NFSR 126 and NFSR 126B.

New line would tie in to existing line at the intersection of NFSR 126 and NFSR 126A. From the tie in, new line would follow NFSR 126 east, NFSR 141 southeast, and a proposed unnamed access road south to pad G.

H 6 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a left onto NFSR 126 and travel 2.0 miles to NFSR 141. Turn right onto NFSR 141 and travel 1.5 miles southeast to pad H on the east side of the road.

The gathering line from pad H follows NFSR 141 northwest and NFSR 126 west to the anticipated Tenaska Pipeline at the intersection of NFSR 126 and NFSR 126B.

New line would tie in to the new line to Pad G at NFSR 141. From the tie in, new line would follow NFSR 141 southeast to pad H.

I 6 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a left onto NFSR 126 and travel 2.5 miles to NFSR 126D. Turn right onto NFSR 126D and travel 2.0 miles southeast. Turn right onto NFSR 126D6 heading southwest to Pad I.

The gathering line travels west from the southern edge of pad I to NFSR 141, then follows NFSR 141 northwest and NFSR 126 west to the anticipated Tenaska Pipeline at the intersection of NFSR 126 and NFSR 126B.

New line would tie in to the new line to Pad G at NFSR 141. From the tie in, new line would follow NFSR 126 north east, NFSR 126D southeast, and NFSR 126D6 southwest to pad I.

II1 (Main option)

12 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a left onto NFSR 126 and travel 2.5 miles to NFSR 126D. Turn right onto NFSR 126D and travel 2.0 miles southeast to Pad II1 on the north side of the road.

The gathering line would travel southwest along FS Road 126 D6 to pad I.

New line would tie in to the new line to Pad I at the intersection of NFSR 126D and NFSR 126D6. From the tie in, new line would follow NFSR 126D southeast to Pad II1.

II2 (Secondary

option)

12 USFS Federal From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a left onto NFSR 126 and travel 2.5 miles to NFSR 126D. Turn right onto NFSR 126D and travel 2.5 miles southeast to Pad II2 on the west side of the road.

The gathering line would travel north along NFSR 126D to Pad II1.

New line would tie in to the new line to Pad I at the intersection of NFSR 126D and NFSR 126D6. From the tie in, new line would follow NFSR 126D southeast to Pad II2.

J 6 Private Federal and Fee

From TX-87, travel east on FM 139 for 2.5 miles to FM 2427. Turn right on FM 2427 and travel 3.5 miles southeast to NFSR 125. Turn left on NFSR 125 and travel 3.0 miles to the end of NFSR 125. Take a right on NFSR 126 to NFSR 169. Turn right onto NFSR 169 and travel 1.0 miles west. Turn left heading south along an unnamed access road to Pad J.

The gathering line travels north from the northeast corner of Pad J to the trunk line just south of NFSR 169. The trunk line continues northwest to NFSR 125, then follows NFSR 125 southwest along NFSR 125 to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

Existing phase three line to pad J would tie in to existing line traversing private land east of NFSR 106.

K 6 Private Fee1

From TX-87, travel east on FM 2261 for 9.0 miles to NFSR 106. Turn left onto NFSR 106 and travel 2.25 miles north west to NFSR 141. Turn right onto NFSR 141 heading northeast and travel 0.75 mile to pad K on the south side of the road.

The gathering line for Pad K consists of a trunk line traveling a northwesterly route to NFSR 169 northeast of the intersection with NFSR 135E. The trunk line continues northwest to NFSR 125 and southwest along NFSR 125 to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

New line would tie in to existing line at the intersection of NFSR 106 and NFSR 141. From the tie in, new line would follow NFSR 141 north to Pad K.

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Site Name Pad

# of Wells

Surface Ownership


L 3 Private Federal and Fee

From TX-87, travel east on FM 2261 for 9.0 miles to NFSR 106. Turn left onto NFSR 106 and travel 2.25 miles north west to NFSR 141. Turn right onto NFSR 141 heading northeast and travel 1.25 mile, then turn right onto the unnamed access road to Pad L.

The gathering line travels from the western edge of Pad L west to Pad K where it connects with a trunk line traveling a northwesterly route to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

New line would tie in to the new line to Pad K at NFSR 141. From the tie in, new line would follow NFSR 141 east to Pad L.

M 3 Private Fee From TX-87, travel east on FM 2261 for 9.0 miles to NFSR 106. Turn left onto NFSR 106 and travel 2.25 miles north west to NFSR 141. Turn right onto NFSR 141 heading northeast and travel 1.75 to a four-way intersection of NFS roads. Turn right onto NFSR 148 heading southeast for 0.5 mile to Pad M on the south side of the road.

The gathering line travels from the western edge of Pad M west to pad K where it connects with a trunk line traveling a northwesterly route to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

New line would tie in to the new line to Pad L at NFSR 141. NFSR 141. From the tie in, new line would follow NFSR 141 northeast and NFSR 148 southeast to Pad M.

N 4 Private Fee From TX-87, travel east on FM 2261 for 9.0 miles to NFSR 106. Turn left onto NFSR 106 and travel 2.25 miles north west to NFSR 141. Turn right onto NFSR 141 heading northeast and travel 2.0 miles to a four-way intersection of NFS roads. Turn right onto NFSR 148 heading southeast and travel 1.0 mile to Pad N on the south side of the road.

The gathering line from Pad N travels west along NFSR 148 to pad M, then continues west to pad K where it connects with a trunk line traveling a northwesterly route to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

New line to Pad N would tie in to existing line off NFSR 148.

O 4 USFS Federal and Fee

From TX-87, travel east on FM 2261 for 9.0 miles to NFSR 106. Turn left onto NFSR 106 and travel 2.25 miles north west to NFSR 141. Turn right onto NFSR 141 heading northeast and travel 2.0 miles to a four-way intersection of NFS roads. Turn right onto NFSR 148 heading southeast and travel 1.25 miles to NFSR 148B. Turn right onto NFSR 148B and travel 0.25 miles northeast to NFSR 148B1. Turn right onto NFSR 148B1 and travel southeast to Pad O.

The gathering line from Pad O travels northwest along NFSR 148B1, then southwest along NFSR 148B, and west along NFSR 148 to pad M. The gathering line continues west to Pad K where it connects with a trunk line traveling a northwesterly route to NFSR 169 northeast of the intersection with NFSR 135E. The trunk line continues southwest for approximately 1000 feet then travels northwest to NFSR 125 and southwest along NFSR 125 to the anticipated Tenaska Pipeline at the intersection of FM 2427 and NFSR 125.

New line would tie in to existing line at the intersection of NFSR 148B and NFSR 148B1. From the tie in, new line would follow NFSR 148B1 southeast to Pad O.

P 4 Private Federal From TX-87, travel east on FM 2261 for 8.5 miles to Pad P on the north side of the road.

The gathering line from Pad P follows FM 2661 east to NFSR 1161 and then north to Pad Q.

New line to Pad N would tie in to existing line off FM 2261.

Q 4 USFS Federal From TX-87, travel east on FM 2261 for 9.0 miles to NFSR 106. Turn left onto NFSR 106 and travel 0.25 mile north to pad Q on the west side of the road.

The gathering line from Pad Q follows NFSR 106 northwest to pad K.

New line would tie in to existing line at the intersection of FM 2261 and NFSR 106. From the tie in, new line would follow NFSR 106 north to Pad Q.

R 2 USFS Federal From TX-87, travel east on FM 2261 for 9.05 miles to NFSR 106. Turn left onto NFSR 106 and travel 0.40 mile north to NFSR 1161, then 0.36 miles north to NFSR 106G. Turn right traveling east on NFSR 106G for 0.75 mile to pad R on the south side of the road.

The gathering line from pad R follows NFSR 106G3 west north to NFSR 1161 where it heads south to Pad Q.

New line would tie in to the new line to Pad Q at NFSR 1161. From the tie in, new line would follow NFSR 1161 north and NFSR 106G east to Pad R.

S 2 USFS Federal From TX-87, travel east on FM 2261 for 10.0 miles to Pad S on the south side of the road.

The gathering line from Pad S follows FM 2661 west to NFSR 106 and then north to Pad Q.

New line to Pad S would tie in to existing line off FM 2261.

Notes: 1. Pad K includes three potential laterals that penetrate federal minerals prior to private mineral penetration north of the proposed well pad. If Marathon intends to drill these laterals at a future date, BLM on sites would be sought and three APDs submitted to ensure compliance with federal minerals law.

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2.2.2.2 Facilities

New production facilities proposed as part of the Bridges Project would include multiple well pads, wells,

reserve drilling cuttings pits (if necessary due to closed loop drilling systems), well surface facilities,

access roads, gathering pipelines, waste water pipelines, and electric lines.

Construction of the well pads, access roads, pipelines, and electric lines would result in an estimated

290.4 acres of new short-term surface disturbance (223.4 acres on SNF surface). Total operational

disturbance is estimated at 281.4 acres following interim reclamation (205.5 acres on SNF surface).

Table Error! No text of specified style in document.-2 presents the estimated disturbance area on

federal and private land. Appendix A (Surface Use Data Summary) provides a detailed breakdown of

disturbance associated with each pad.

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Table Error! No text of specified style in document.-2 Disturbed Area Summary

Facility

USFS Private Project Total

Existing Disturbance

New Construction Disturbance

Total Surface

Disturbance

Operational Disturbance



Total Surface

Disturbance




Total Surface

Disturbance


Pads 6.9 61.3 68.1 50.2 23.7 28.7 52.4 38.3 30.5 90.0 120.5 88.6

Pipelines 15.7 38.4 54.2 33.9 11.7 6.1 17.8 8.9 27.4 44.5 71.9 42.8

Access Roads 82.5 72.3 154.9 92.8 12.5 12.2 24.7 15.2 95.0 84.5 179.6 107.9

Electric Lines 0.0 51.4 51.4 28.6 0.0 20.0 20.0 13.5 0.0 71.4 71.4 42.1

Grand Total 105.1 223.4 328.5 205.5 47.8 67.0 114.8 75.9 153.0 290.4 443.4 281.4

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Facilities would be relatively similar on each well pad and a basic description of each type (and quantity)

of production facilities is described below.

Multiple Well Pads Well pads included in the Bridges Project would be constructed by harvesting and

clearing vegetation, stripping and stockpiling topsoil, and leveling the pad area using cut-and-fill

techniques. The Bridges Project would have up to 12 well pads on USFS surface and nine well pads on

nearby private lands. Figures 1 and 2 provide the locations of each well pad. The working surface of the

newly constructed well pads would average 500 feet by 500 feet, and with cut and fill slopes, disturbance

per pad would be approximately five-to-seven acres. Construction of the well pads would result in an

estimated 90.0 acres (61.3 acres on NFS land) of new short-term surface disturbance. Following interim

reclamation, a working area of about four acres per pad would remain clear to facilitate the long-term

production phase of the well pad. Total disturbance for well pads during the production phase of the

project is estimated at 88.6 acres (50.2 acres on NFS land) following interim reclamation.

The proposed well pads would be constructed from the native soil and rock materials present using a

bulldozer, grader, front-end loader, and/or trackhoe. Prior to clearing and grading, merchantable trees

would be logged and removed from the site. Non-merchantable trees and other woody vegetation would

be mulched or removed from NFS land. The pads would be constructed by clearing all vegetation and

leveling the pad area using cut-and-fill techniques. Top soil would be stripped and stockpiled at a depth

appropriate to retain biologic viability. Interim reclamation practices and BMPs would be utilized to control

stockpiled topsoil erosion during well production. Cut slopes associated with pad construction would be

left rough to provide a seed catchment surface and would be terraced when slope heights exceed 10 feet.

Cut and fill slopes for pad construction would follow the following guidelines unless approved otherwise by

the responsible official:

Cut slopes would not be steeper than 2:1 (horizontal to vertical)

Fill slopes should be no steeper than 3:1

The tops of cut slopes and pad corners may be rounded to improve their appearance and reduce the

volume of cut-and-fill. Detailed engineering and land survey designs would be provided to the USFS for

review prior to construction of individual pads.

Up to 124 production wells would be constructed on 21 pads as well as three saltwater injection wells for

the project. Each proposed well pad would be large enough to contain up to a maximum of 12 wells.

Surface facilities at each well pad location would consist of wellheads, separator/dehydrator units, gas-

metering units, communication towers, and aboveground condensate and produced water tanks.

Production facilities would be located and arranged to facilitate safety and maximize reclamation

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opportunities. All permanent aboveground structures not subject to safety considerations would be

painted a color specified by the NFGT.

Drilling Pits (if necessary) Marathon plans to utilize a closed loop drilling system to eliminate any pit

requirements. Marathon retains the right to use drilling pits to contain drill cuttings and muds. Pits would

be designed so that at least 60 percent of the volume is placed in the cut portion of the slope and line with

an impermeable liner to meet USFS standards.

Production Tanks Up to 10 production tanks may be located on each well pad. Tanks would be

surrounded by an engineered secondary containment unit designed to hold 150 percent of the total

volume. Tanks would be 500 barrels (one barrel equals 42 gallons) in size and not exceed 25 feet in

height.

Compression Equipment Gas compression would be needed for the Bridges Project to be able to get

produced gas to the transmission pipeline for export. Two gas-powered wellhead compressors would be

installed at each pad. Gas powered compressors would be needed until all wells on a pad would be fully

developed and electric lines would be completed. Electric-powered compressors would be used once

electric lines are operational.

Communication Tower A communication tower would be located on each pad to facilitate remote

monitoring using Supervisory Control and Data Acquisition (SCADA) remote process monitor units.

Towers would be expected to be up to 100 feet, but would be no higher than required to extend

approximately eight feet above the surrounding trees. Towers would be 12-inch diameter triangle lattice.

The majority of the towers would consist of one 10-foot section buried five feet in the ground with 10-foot

sections on top. A final one-inch diameter 10-foot pole would be mounted two feet down in the top

section. Remote monitoring would reduce the volume of traffic required to monitor the wells during

operations. No guy wires would be used.

Ancillary Facilities and Equipment All other surface equipment, including wellheads, would be

permanently fenced or housed in enclosed jackets or small locked buildings such that moving parts and

controls would be inaccessible. Telemetry equipment would be used to remotely monitor wells. The use

of telemetry would minimize traffic to and from the well locations in order to minimize impacts on wildlife

and plants.

Self-contained mobile home trailers would be used on site during drilling and completion operations.

These units would be used as field offices and temporary housing for Marathon employees and up to forty

contractor personnel. These units would meet federal, state, and local regulations that directly pertain to

temporary employee housing.

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Access Roads Approximately 26.9 miles of new roads and existing road upgrades would be required

for the construction of the well pads on private and public surface. All roads would be built to the

specifications provided in the USFS Gas Guidelines for the NFGT and for the anticipated traffic flow and

all-weather requirements. Road construction and upgrading would be conducted using standard

equipment and techniques approved by the USFS, which could include ditching, draining, crowning,

surfacing, sloping, and dipping the roadbed as necessary. Figure 3 provides a detailed map of both new,

reconstructed, and existing roads and their association with each well pad.

Roads would be designed and maintained to an appropriate standard no higher than necessary to

accommodate their intended functions. Detailed road design and construction standards are included in

the Transportation Plan (Appendix I of the Bridges Project MPOD).

Gathering Pipelines Approximately 23.6 miles of new and existing gathering lines on private and public

surface would be constructed or maintained to deliver gas to the proposed Tenaska pipeline system. The

Tenaska pipeline system and project is a separate project from the Bridges Project proposed action.

Proposed gathering lines would be constructed within or immediately adjacent to existing, upgraded, or

proposed roads (approximately 17.4 miles). Some greenfield pipeline construction (new in areas not

previously disturbed) would be required (approximately 0.5 miles) which would not be constructed along

or within existing ROWs. Gathering lines would be six- to 24-inch diameter lines designed to move gas

from gathering lines to the greater natural gas market system. Maximum pressures for these pipelines

would not exceed 1,440 pounds per square inch. All gathering lines would have risers, pig launchers, and

associated manifolds contained within the permitted ROW.

Marathon proposes to install a large 14-inch pipeline in an existing pipeline ROW that currently runs

through compartments 43, 44, and 49 that is used for the Ellora pipeline (Figure 4). The USFS special

use permit issued for this original easement required the maintenance of a cleared 40-foot ROW. The

cleared, maintained sections now range between 10 and 30 feet depending on past maintenance and

vegetation structure adjacent to the ROW. Marathons proposed action would require clearing some

sections back to the original 40-foot width to allow for installation of their 14-inch pipeline.

Pipeline routes for each pad are described in Table Error! No text of specified style in document.-1.

Construction of pipelines would proceed in a planned sequence of operations. Vegetation would be

removed from the ROW. The pipeline trench would be excavated mechanically to a depth that would

allow approximately four to five feet of earth to be placed on the top of the pipeline. Pipeline segments

would be welded together and tested, lowered into the trench, and covered with excavated material.

Each pipeline would be pressure tested with freshwater and/or nitrogen gas from an off-site source to

locate any leaks. After testing, the water would be transported and injected at a water saltwater injection

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facility or discharged into drainages off NFS land, if approved by the BLM. The nitrogen would be

released to the atmosphere. Generally, a mile of pipeline would be constructed in four-to-six days.

Excavated topsoil from pipeline installation activities would be windrowed separately from the underlying

subsoil and stored along the road until the trench is backfilled. All pipelines would be buried to a

minimum depth of 48 inches from surface to top of pipe.

Horizontal directional drilling (HDD) techniques would be used to bore beneath drainages, wetlands, and

bottomland hardwood forest.

Marathon or the HDD contractor would perform HDD as outlined below:

Staging and equipment areas and the entry and exit boring locations would be a minimum of 50 feet from the stream channel.

A pit would be constructed at the entrance and exit of the drill bore to contain returned drilling fluid. The drilling fluid would be bentonite-based with no potentially hazardous additives.

Recovered drilling fluids, with only bentonite in the fluids, would be applied on the HDD drilling site and erosion and siltation barriers, such as silt fence, berms, hay bales, and wattles, would be placed down gradient of the bore to prevent fluid from entering streams or wetlands.

The Spill Prevention Control and Countermeasure (SPCC) Plan would include a contingency plan with response procedures to contain any accidental spills.

The appropriate depth below the streambed to minimize the potential to dewater streams or wetlands would be determined prior to construction. A depth of 20 feet below the streambed is considered adequate to protect water crossings (Willoughby 2005).

Flowback and Product Water Pipelines Flowback is fracing fluid and water from completion activities

that returns to the surface. Marathon estimates that about 30 percent of the fracing fluid would return to

the surface. Most of the flowback water would be reused in the fracing process. The water would be

temporarily stored in above ground tanks. Excess flowback water would be transferred by poly-line

adjacent to gathering pipelines installed in the same ROWs for injection into the Rodessa Formation at

saltwater injection wells on Pads F, J, or P. The Rodessa Formation is at a depth of approximately 5,800

feet below ground surface and is hydraulically isolated by impermeable overlying strata. Marathon

reserves the right to use water tanker trucks to transport wastewater if pipeline or saltwater injection well

construction is not feasible or practical.

Electric Transmission Lines Electric utility lines would be upgraded and/or constructed to provide

electricity to the well pads. Approximately 11.0 miles of existing one-phase electric line would be

upgraded to three-phase electric lines for the development of the Bridges Project. In addition,

approximately 0.4 miles of greenfield three-phase electric lines and approximately 23.3 miles of new

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collocated three-phase electric lines would be needed to provide connectivity between the existing electric

grid and the well pads (Figure 5). The Deep East Texas Electrical Cooperative requires one-phase

electric lines to have a 20 feet wide ROW and three-phase electric lines require a 30 feet wide ROW.

Upgrading existing one-phase to three-phase electric line would require vegetation removal from

approximately 10 additional feet to the required 30-foot ROW width, replacing old poles as necessary and

spooling and tightening new lines across the poles. Sale prices and removal criteria for mature trees that

are removed would be discussed in COAs. New line construction would involve clearing a 30-foot ROW,

installing poles and spooling, and tightening the electric line. Some electric line sections would be

installed underground within the existing ROW in areas where vegetation clearing is restricted to protect

RCW habitat (see Section 3.5).

The new electric transmission line construction would consist of wood pole H-frame structures, three

electrical conductors, and two shield wires on top of the poles that provide lightning protection. Poles

would be 46-to-74 feet tall. It is anticipated that Deep East Texas Electric Coop would design and permit

the electric lines. The poles would be similar in size to existing three-phase power lines along FM2427.

Electric line corridors would require periodic vegetation maintenance conducted by Deep East Texas

Electric Coop to remove encroaching vegetation from electric lines for safety and function of the lines.

This maintenance could include trimming or removal of new vegetation growth, but would not cause large

amounts of additional soil disturbance.

2.2.2.3 Well Pad Construction

The 21 well pads would average six acres in size, including spoil piles and topsoil piles (see Appendix A).

All surface disturbing activities would be supervised by a qualified company representative to ensure that

the terms and conditions of the APD, as well as specifications in the approved plans, would be in

compliance.

Prior to clearing and grading, merchantable trees would be logged and removed from the site. Non-

merchantable trees and other woody vegetation would be mulched for use in reclamation activities or

removed from NFS land. Diversion ditches and berms would be constructed with a motor grader to

manage well pad stormwater run-on and run-off. The SWPPP would be followed during construction,

completion, testing, and production. Energy dissipaters such as weed-free straw bales, rock gabions, and

silt fences may be used in areas where the possibility of down cutting exists. All cut and fill slopes would

be constructed so slope stability would be maintained for the life of the project.

A bulldozer, grader, front-end loader, and/or trackhoe would strip whatever topsoil is present (six-to-12

inches) on the pad and reserve pit and stockpile it along the edge of each well pad for use during

reclamation. Topsoil would be stored in a windrow on the uphill side of the well pads. All topsoil would be

May 2011 DRAFT

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stockpiled to minimize soil loss and loss of biological activity/viability. Interim seeding of stockpiled topsoil

would be implemented to stabilize the pile and maintain organic matter and biological viability.

Well pads would require periodic maintenance as specified in the MPOD and COAs to keep drainages

open and free of debris. Areas not revegetated would be properly managed to reduce erosion, fugitive

dust, and effects to adjacent areas. A typical layout for a proposed well pad is presented in Figure 6.

2.2.2.4 Drilling Operations

The initial wells drilled from surface locations in the Bridges Project area would be drilled into the James

Lime Formation, at an approximate average depth of 6,214 feet below the ground surface (bgs), in

accordance with field rules defined in the TRRC Gas Docket No. 06-0262000, approved December 15,

2009. After initial gas recovery, wells would be deepened or new wells would be drilled to reach

additional formations. The two additional zones that would be developed are the Haynesville Shale at an

average drill depth of 12,216 feet bgs and the Middle Bossier Shale at an average drill depth of 11,910

feet bgs.

Following construction of a well pad, a rotary platform-drilling rig with a drilling capability matched to the

depth requirements of the proposed well, and available at Marathons drilling schedule, would be moved

by truck to the pad. The main function of the rig is to drill a hole (well bore) from the surface to the

hydrocarbon-producing formation below. The drilling rig is portable and would be assembled and made

ready for drilling. Once drilling rig setup is completed, drilling can begin.

A steel bit with either very hard tungsten steel teeth or industrial diamonds, would be attached to a length

of steel drill pipe (usually 30 feet long), lowered to the ground and rotated to drill the well bore. As the

well bore increases in depth, additional pieces of steel drill pipe would be attached continue drilling at

greater depths. The drill bit has a larger diameter than the drill pipe. Drilling fluid (mud) would be

pumped down hole through the drill pipe to: reduce friction between the bit/drill pipe and the subsurface

formations, bring the drill cuttings to the surface, and keep underground pressures under control.

Wells would be drilled by utilizing a combination of directional and horizontal drilling techniques. An S-

shaped directional design would be used to reach the targeted kick-off point (where horizontal drilling

begins). Specific directional plans for each well would be included with the APDs. The directional portion

of the wells would be drilled with a measurement while drilling (MWD) system. The actual bottom hole

locations would be horizontally separated from the surface pad positions by a maximum of approximately

4,000 feet.

Directional drilling would reduce the number of surface locations required to effectively produce the

reservoir by collocating surface locations. Horizontal drilling would provide greater reservoir contact with

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the well bore to allow more advanced completion and stimulation activities resulting in more production

from fewer wells.

The vertical portion of the well bore would be drilled through the lowermost potential freshwater-bearing

geologic unit then a surface casing (steel pipe of a larger diameter than drill pipe) would be installed to

seal off and prevent hydraulic communication with these shallower geologic units. The vertical portion of

the well bore would be drilled down to the kick-off point.

Horizontal drilling would begin at a subsurface location just above the target kick-off point. The well bore

would deviate from the vertical plane by curving to intersect the reservoir at the entry point with a near-

horizontal inclination and remain within the reservoir until the desired bottom hole location is reached.

From the kick-off point to the entry point, the curved section of a horizontal well would be drilled using a

hydraulic motor mounted directly above the bit and powered by the drilling fluid. Steering the hole would

be accomplished through the employment of a slightly bent or steerable downhole motor. By orienting

the bend in the motor and drilling forward without rotating the pipe, known as slide drilling, the hole would

be steered around a curve from horizontal to vertical and/or to the left or right. This would cause the hole

to be directionally drilled along an arc to ultimately become horizontal in the targeted horizon. Then, the

horizontal leg of the hole would be drilled to the targeted distance. The production casing and the

annulus would be cemented similar to the surface casing. This process would secure the production

casing in the production zone. At this point, the drilling rig would be moved to another location.

Final depthwould be determined by examining cuttings for their geological characteristics or results

from well logs.

Drilling Waste Management

Drilling would be done using a closed system where the cuttings would be filtered out of the drilling fluid

and the majority of the fluid is reused in the drilling process. Cuttings would be temporarily stored before

transported to an approved site not located on federal land for land farming and/or transported to an

approved landfill. The proposed short-term drilling waste storage areas (lined sump) would be

constructed on each pad and would consist of matting lined with a liner impermeable to drilling waste.

The area would be trenched so that fluids spilled and/or stormwater would flow to a lined sump. The

sumps would be periodically vacuumed and all fluids would be hauled to a TRRC approved commercial

storage facility on private land. Used drilling muds would be temporarily stored in tanks within secondary

containment until re-used or transported to an approved site off federal land.

Marathon would comply with Statewide Rule 8, which allows disposal of drill cuttings by land farming,

provided:

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The wastes would be disposed of on the same lease where they would be generated.

The operator has the written permission of the surface owner of the tract where land farming would occur.

The cuttings were obtained while using water-based drilling fluids with a chloride concentration of 3,000 mg/liter or less.

Marathon would test cuttings for chloride. If chloride concentrations are less than 3,000 mg/L, cuttings

would be transported to a site for land farming on private land. Marathon would obtain a land farming

permit from TRRC in compliance with Statewide Rule 8. TRRC would not issue the permit unless they

determine that the disposal would not result in the pollution of surface or ground water. If chloride

concentrations exceed 3,000 mg/L, Marathon would transport the cuttings to a TRRC approved

commercial storage facility.

Dump trucks used to haul cuttings would be covered and the tailgate sealed with insulating foam to

prevent spills during hauling. Trucks would be loaded inside the lined and trenched area to reduce

potential impacts to water quality.

A series of blowout preventers would be installed on the well bore to prevent down hole pressures from

spewing gas, oil, or saltwater to the surface, and, if gas is present, to prevent an explosion and fire.

2.2.2.5 Completion Activities

Once a well is drilled, Marathon would evaluate the data obtained from MWD logs to decide whether to

set production casing and complete the well or to plug and abandon it. If Marathon decides to produce

the well, completion operations would commence within 30 days after drilling rig release and would take

45 days per well or possibly longer if the flow test period is extended. Completion operations would

include setting production casing, perforating, fracturing, and flow testing.

Production casing would be set and cemented to a depth below the pay zone (target geological horizon).

This would temporarily seal off the producing zone until perforations would be made in the production

string and cement by firing a gun to the productive zone. The gun is a tool that penetrates the casing

and cement to allow hydrocarbons to enter the casing. Often the hydrocarbons would be flowed to the

surface through small diameter tubing that is inserted in the production casing. A packer would be used

to force the produced hydrocarbons into production tubing.

If a formation contains oil or gas in commercial quantities but the permeability of the hydrocarbon-

producing zone is too low to permit good recovery, Marathon would fracture (frac) the well. No diesel fuel

would be used during fracing. Sand or other fine materials (proppants) would be mixed with the fracing

fluid to hold the fractures open to allow the passage of hydrocarbons into the well. Fracturing would occur

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in the producing formation, several thousand feet below formations that provide drinking water.

Fracturing would not pose a human health threat to drinking water wells.

The

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