Study No. 142 March 2015

CANADIAN ECONOMIC IMPACTS OF ENERGY RESEARCH NATURAL GAS DEVELOPMENT INSTITUTE WITHIN THE YUKON TERRITORY

Canadian Energy Research Institute | Relevant • Independent • Objective

ECONOMIC IMPACTS OF NATURAL GAS DEVELOPMENT IN THE YUKON TERRITORY

Economic Impacts of Natural Gas Development in the Yukon Territory

Copyright © Canadian Energy Research Institute, 2015 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute

ISBN 1-927037-26-3

Authors: Peter Howard Jon Rozhon Paul Kralovic

Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to Afshin Honarvar of the Alberta Energy Regulator and all CERI staff that provided insightful comments and essential data inputs required for the completion of this report, as well as those involved in the production, reviewing, and editing of the material, including but not limited to Allan Fogwill and Megan Murphy.

CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca

March 2015 Printed in Canada

Front Cover Photo Courtesy of http://upload.wikimedia.org/wikipedia/commons/thumb/f/f4/Dempsterhighway.jpg/800px-Dempsterhighway.jpg

Economic Impacts of Natural Gas Development iii Within the Yukon Territory Table of Contents

LIST OF FIGURES ...... v LIST OF TABLES ...... vii EXECUTIVE SUMMARY ...... ix Scenario 1 ...... x Scenario 2 ...... xi CHAPTER 1 INTRODUCTION ...... 1 Government, Ownership & Administration of Natural Resources ...... 4 Oil and Gas Infrastructure ...... 5 Other Pipeline Infrastructure ...... 6 Alaska Highway Pipeline Project & Mackenzie Valley Pipeline Project ...... 7 The Yukon’s Electricity Generation and Transmission ...... 7 Mining and Mineral Exploration and Development ...... 11 Yukon Energy Strategy ...... 16 CHAPTER 2 YUKON BASINS: AVAILABILITY AND RISK ...... 21 Available ...... 21 Unavailable ...... 21 Encumbered ...... 22 First Nations-Owned ...... 22 Oil and Natural Gas Potential ...... 23 Eagle Plain Basin ...... 26 Peel Plateau & Plain Basin ...... 29 CHAPTER 3 DESCRIPTION OF ISSUES ...... 33 Supply Abundance ...... 33 Demand Dynamics ...... 33 Market Structure ...... 34 Resource Access ...... 34 Environmental and Societal Pressures ...... 35 Alberta and British Columbia ...... 35 Yukon Territory ...... 35 Diesel vs. Natural Gas Electricity Production ...... 36 CHAPTER 4 METHODOLOGY AND SCENARIOS ...... 39 Assumptions for the Input/Output (I/O) Model ...... 40 Capital Costs ...... 40 Operating Costs ...... 40 Capital Injections ...... 40 Operating Injections...... 41 Scenario 1 – Domestic Pipeline: Eagle Plain to Stewart Crossing ...... 42 Economic Impacts for Scenario 1 ...... 50

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Scenario 2 – Domestic and Export Pipeline: Peel Plateau & Plain + Eagle Plain to US Border ...... 52 Economic Impacts for Scenario 2 ...... 57 CHAPTER 5 KEY FINDINGS AND CONCLUDING REMARKS ...... 59 Key Findings ...... 59 APPENDIX A A NOTE ON THE LIARD, OLD CROW, BEAUFORT-MACKENZIE, BONNET PLUME AND KANDIK OIL AND GAS BASINS ...... 63 Liard Basin ...... 63 Old Crow Basin ...... 66 Beaufort-Mackenzie Plume Basin ...... 69 Bonnet Plume Basin ...... 70 Kandik Basin ...... 71 Whitehorse Trough Basin ...... 73 APPENDIX B THE HISTORY OF MINING IN YUKON ...... 75

March 2015 Economic Impacts of Natural Gas Development v Within the Yukon Territory List of Figures

1.1 Oil and Gas Basins in Western Canada ...... 1 1.2 Topographical Map of Yukon ...... 3 1.3 The Canol Refinery at Whitehorse, October 29, 1943 ...... 6 1.4 Studebaker Truck Loaded with Pipe Moving toward the End of the Line ...... 7 1.5 Yukon Electricity Facilities, 2014 ...... 10 1.6 Exploration and Development Activity in Yukon, 2005-2014 ...... 14 1.7 Map of Mineral Development, Electrical Grid & Pipeline Routes ...... 18 2.1 Current Availability in all Yukon Basins, Percentage of Total Basin Area ...... 23 2.2 Yukon’s Oil and Natural Gas Resource Potential by Exploration Region ...... 24 2.3 Yukon Basin Availability, 2014 ...... 26 2.4 Map of Eagle Plain Basin Exploration Region ...... 27 2.5 Northern Cross Yukon Proposed 2015 Drill Program ...... 28 2.6 Map of the Peel Plateau & Plain Exploration Region ...... 30 3.1 Forecasted Henry Hub Prices ...... 36 3.2 Levelized Cost of Electrical Power Delivered to a 5 MW Mine ...... 37 4.1 Scenario 1 Route Map ...... 42 4.2 Yukon Present and Potential Power Capacity ...... 44 4.3 Levelized Cost of Electrical Power Delivered to the Casino Mine ...... 45 4.4 Eagle Plain Well Requirements for 50 MMcf/d Natural Gas Production ...... 47 4.5 Assumed Production Decline Curve ...... 48 4.6 Jobs Created and Preserved in Canada as a Result of Yukon Natural Gas Development, Scenario 1 – 2017-2041 ...... 50 4.7 Scenario 2 Route Map ...... 52 4.8 Peel Plateau + Eagle Plain Well Requirements for 237.4 MMcf/d Natural Gas Production ...... 56 4.9 Jobs Created and Preserved in Canada as a Result of Yukon Natural Gas Development, Scenario 2 – 2017-2041 ...... 57 A.1 Map of Liard Basin Exploration Region ...... 64 A.2 Schematic of the Geology of the Liard Basin and the Horn River Basin ...... 65 A.3 Map of the Old Crow Exploration Region ...... 68 A.4 Map of the Beaufort-Mackenzie Exploration Region ...... 69 A.5 Map of Bonnet Plume Exploration Region ...... 70 A.6 Map of the Kandik Basin Exploration Region...... 72 A.7 Map of the Whitehorse Trough Exploration Region ...... 74 B.1 Map of Yukon’s Past-Producing Mines ...... 76

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March 2015 Economic Impacts of Natural Gas Development vii Within the Yukon Territory List of Tables

1.1 Survey of Advanced Exploration, Development and Producing Projects ...... 13 1.2 Development Investment in Yukon, 2005-2014 ...... 15 1.3 Exploration Investment and Activity in Yukon, 2005-2014 ...... 15 1.4 Active and Prospective Mine Loads ...... 19 2.1 Yukon’s Oil and Natural Gas Resource Potential ...... 25 4.1 New-Build LNG Liquefaction and Gas-fired Power Generation Facilities Costs ...... 43 4.2 Pipeline Costs for Domestic Pipelines ...... 46 4.3 Eagle Plain Basin Characteristics ...... 46 4.4 Well Cost Assumptions ...... 49 4.5 Economic Impacts of Yukon Natural Gas Development, Scenario 1 – 2017-2041 ...... 50 4.6 Federal, Provincial, and Municipal Tax Receipts as a Result of Yukon Natural Gas Development, Scenario 1 – 2017-2041 ...... 51 4.7 Total Natural Gas Volume, Value and Royalty as a Result of Yukon Natural Gas Development, Scenario 1, 2017-2041 ...... 51 4.8 Pipeline Costs for Export Pipeline ...... 53 4.9 Pipeline Costs for Peel Plateau & Plain to Eagle Plain Pipeline ...... 54 4.10 Peel Plateau & Plain Basin Characteristics ...... 54 4.11 Peel Plateau + Eagle Plain Basin Characteristics ...... 55 4.12 Economic Impacts of Yukon Natural Gas Development, Scenario 2 – 2017-2041 ...... 57 4.13 Tax Receipts from Yukon Natural Gas Development, Scenario 2 – 2017-2041...... 58 4.14 Total Natural Gas Volume, Value and Royalty as a Result of Yukon Natural Gas Development, Scenario 2, 2017-2041 ...... 58 5.1 GDP, Taxation and Employment Projections ...... 59 A.1 Liard Basin Characteristics ...... 65 A.2 Pipeline Costs for Export Pipeline from Liard ...... 66 B.1 Hard Rock Mining – Principal Historical Producers ...... 75

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March 2015 Economic Impacts of Natural Gas Development ix Within the Yukon Territory Executive Summary

The Western Canadian Sedimentary Basin (WCSB) does not end at the 60th parallel, which demarcates the northern borders of Alberta and British Columbia. There is every reason, and increasing evidence, to believe that rich deposits of oil and gas extend into the Yukon Territory and the Northwest Territories as well. In the case of Yukon, there has been little exploration within the territory’s eight oil and gas basins, so the available geological data is sparse. This study has two aims: to describe the conventional natural gas resource in Yukon and to consider the potential of conventional natural gas production and infrastructure development in the territory. Unconventional resources, such as shale gas,1 are not considered in the report, nor are recent innovations in production, such as hydraulic fracturing. Data and economic analysis have been taken from a variety of sources, including the Canadian Energy Research Institute’s (CERI) North American Natural Gas Pathways study,2 CERI’s proprietary economic models, findings published by the Government of Yukon, and consultants’ reports.

Operating and capital expenditures have been calculated using CERI’s US Canadian Multi- Regional I/O 3.0 model in order to estimate GDP, employment, and taxation over the period 2017-2041. For capital expenditures, CERI assumes the majority of spending will occur in the mature, oil- and gas-focused Alberta economy, with the much smaller Yukon economy receiving less. For operating expenditures, CERI assumes that most spending would occur in Yukon where the sites, facilities, and maintenance staff would be located. Specialized operational expertise would be sourced from Alberta. The injection assumptions are explained in detail in Chapter 4 of this report. We assume that all capital and operational spending outside of Yukon occurs in Alberta.

The GDP, employment, royalties, and taxation projections in this report should be considered as lower-bound economic impact estimates. They reflect a Yukon oil and gas sector that is presently in a nascent stage and has not yet developed robust economic linkages to other sectors in the territory or the other provinces and territories in Canada. In the future, assuming Yukon’s oil and gas sector begins to grow and infrastructure is built, those linkages will materialize. The linkages will generate more oil and gas investment in Yukon’s economy generally. Economic linkages with other provinces would expand also, with GDP, taxation, and employment all increasing at greater rates than today. In short, as the oil and gas industry and economy grow in Yukon, there will be more economic activity and jobs for the same amount of investment.

The report includes two gas industry development scenarios. Scenario 1 represents modest domestic development. Scenario 2 offers more significant development of Yukon’s resources, whereby domestic needs are met and surplus gas is exported.

1 Though there is likely potential for shale gas development in the Yukon, this report is limited to consideration of the conventional resource in the territory, which has been researched to a greater extent. 2 CERI Study 138, “North American Natural Gas Pathways”, June 2013. Available at http://ceri.ca/images/stories/2013-09-05_CERI_Study_No__138_-_North_American_Natural_Gas_Pathways.pdf

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Consideration of natural gas development in Yukon will continue to take place within the broader context of global energy dynamics as explored in CERI’s North American Natural Gas Pathways study. Notably, natural gas as a share of global energy consumption3 has grown by 32 percent over the past 40 years. Of the other two leading energy sources worldwide, coal grew by 11 percent while oil demand grew by 32 percent over the same period. In 1973, all fossil fuels accounted for 94 percent of global energy consumption; by 2013, the percentage had decreased, but fossil fuels still accounted for 87 percent of global energy consumption. Natural gas is an increasingly important energy source in a world economy that remains largely driven by hydrocarbons.

This report’s findings include the following:

 Natural gas development is driven in part by increased demand from mining investment.  Basin availability and land access must be addressed in advance of energy infrastructure development in Yukon.  36 percent of Yukon’s sedimentary basins that are oil and/or gas prospective, representing 5.4 percent of the territory’s land area, are available for development in 2014.  A further 40 percent of hydrocarbon prospective areas in Yukon, representing 6 percent of the territory’s land area, are temporarily unavailable but may be made available in the future.  Eagle Plain basin is the most feasible area for development in 2014, with 73 percent of the land area available. The second most feasible area is Peel Plateau & Plain basin, with 36 percent of the land area available.4  Liard basin in southeast Yukon is a promising third basin that could see development when more of its land becomes unencumbered and accessible.  The analysis outlines economic benefits, including fiscal impacts, to Yukon and the rest of Canada associated with natural gas development.

Scenario 1

This scenario considers a domestic pipeline option from Eagle Plain basin to Stewart Crossing, with a lateral line to the Casino mine site (see Figure 4.1). This pipeline would be constructed and operated over the 2017-2041 timeline.  Natural gas development capital and operating investment under Scenario 1 would equal C$9,7585 million in all Canadian provinces.

3 Primary energy consumption grew from 5,710.29 MTOE in 1973 to 12,730.43 MTOE in 2013, according to the 2014 BP Statistical Review of World Energy. Within that period, natural gas consumption increased from 1,046.16 MTOE to 3,020.38 MTOE; coal consumption rose from 1,558.97 to 3,826.71 MTOE; and oil grew from 2,763.56 to 4,185 MTOE. 4 Since the development of this analysis, Yukon government has made public statements that indicate all of the Peel Plateau & Plain basin is likely to be 100% encumbered/unavailable while judicial action relating to the area is concluded. The analysis in this report does not account for this reduction in available oil and gas lands. 5 Unless otherwise stated, all currency amounts are in 2013 Canadian dollars.

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 Scenario 1 could provide the territory with 50 MMcf/d of natural gas for 80 years, assuming no further exploration or development.  Natural gas development under Scenario 1 would create a total of C$10,506 million of GDP impact in Canada, with C$875 million of that GDP impact in Yukon over the 2017- 2041 timeline.  Natural gas development under Scenario 1 would create and preserve a total of 62,000 person years of employment in Canada, with 6,000 person years of the employment created and preserved in Yukon over the 2017-2041 timeline. 6  Natural gas development under Scenario 1 would create total tax receipts of C$2,077 million in Canada, with C$101 million of those receipts in Yukon over the 2017-2041 timeline.  Natural gas development under Scenario 1 would create royalty income for Yukon of $452.9 million from $3,870 million in sales gas value over the 2017-2041 timeline.

Scenario 2 Scenario 2 offers a domestic and export pipeline option to move natural gas from Peel Plateau & Plain basin and Eagle Plain basin to Stewart Crossing and then further south to the US border near Haines, Alaska; a lateral line would also be built between Stewart Crossing and the Casino mine site (see Figure 4.7). A generation and liquefaction facility at Stewart Crossing would provide on-grid supply and serve other off-grid mines. The export pipeline would feed a small LNG plant to be constructed in Haines. All pipelines and facilities would be built and operated over the 2017-2041 timeline.  Under Scenario 2, estimated total capital and operating investment in all Canadian provinces from 2017-2041 would equal C$27,653 million.  Scenario 2 could provide the territory with 50 MMcf/d of natural gas and the Haines plant with 180 MMcf/d of natural gas for 24 years, assuming no further exploration or development.  Natural gas development under Scenario 2 would create a total of C$32,791 million in GDP impact in Canada, with C$2,712 million of that GDP impact felt in Yukon over the 2017-2041 timeline.  Natural gas development under Scenario 2 would create and preserve 191,000 person years of employment in Canada with 19,000 of the person years created and preserved in Yukon over the 2017-2041 timeline.  Natural gas development under Scenario 2 would create tax receipts of C$6,497 million, with C$314 million of those receipts in Yukon over the 2017-2041 timeline.  Natural gas development under Scenario 2 would create royalty income for Yukon of $1,360 million from $13,530 million in sales gas value over the 2017-2041 timeline.

6 Person years of employment does not equal total jobs. For example, 6,000 person years of employment could be 6,000 jobs for one year, 3,000 jobs for two years or 1,000 jobs for six years. Person years equals the number of jobs times the number of years each job will exist.

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March 2015 Economic Impacts of Natural Gas Development 1 Within the Yukon Territory Chapter 1 Introduction

Yukon is famous for its beautiful, rugged landscape and its challenging climate. Equally well known are Yukon’s mining industry and mineral deposits. The territory’s hydrocarbon resources have not attracted as much attention, however. Though it is widely assumed Yukon is home to significant oil and gas resources, the development costs are high in Canada’s north – both the remoteness of the area and its weather extremes contribute to those costs. Oil and gas exploration and production have been minimal in Yukon to date. But the WCSB, long a proven hydrocarbon producing region, extends into Yukon, so the territory is a logical place to look for resources (see Figure 1.1).

Figure 1.1: Oil and Gas Basins in Western Canada

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This study briefly discusses Yukon’s oil resource but focuses more closely on natural gas. Natural gas holds potential to displace diesel power in the territory, meet new demand for energy associated with mineral development, and may also be exported to markets in North America and beyond. More specifically, this study:

 Determines under what conditions natural gas resources could be economically developed to feed domestic demand.  Considers if natural gas can be developed and converted to LNG with the intent of supplying current and future communities and mine sites, some of which rely on diesel power generation.  Characterizes energy demand drivers and outlook.  Establishes key economic, fiscal, and infrastructure investment opportunities associated with natural gas development and production in Yukon.

Yukon is the westernmost of Canada’s three territories; and at 482,442 km2, it is also the smallest.1 Comprising 4.8 percent of Canada’s total area, Yukon is larger than the provinces of Newfoundland and Labrador, New Brunswick, Nova Scotia, and Prince Edward Island.2

In economic terms, Yukon is Canada’s second-smallest economy with a 2013 GDP of $2,283 million,3 half the size of Canada’s smallest provincial economy, Prince Edward Island. In 2013, government expenditures made up 49.85 percent of Yukon GDP – the second highest rate of government expenditures as a share of GDP in Canada, after Nunavut.4 Mining accounted for 22 percent of GDP in 2013, up from 6 percent in 2007,5 accompanying significant investment from the mining industry in both exploration/development, as well as production at three new mines. Tourism accounted for approximately 4 percent of GDP in 2012.6

Yukon is bordered by the Northwest Territories to the east, British Columbia to the south, and the state of Alaska to the west. The triangular-shaped territory follows 141⁰ west longitude on its western border with Alaska, while its eastern border roughly tracks the Yukon River Basin and Mackenzie River watershed, bordering the Northwest Territories. Yukon’s southern border with British Columbia runs along the 60th parallel. On its northern edge lies the Beaufort Sea. The nearest port is in Tuktoyaktuk in the Northwest Territories. In the winter months, this port may be accessed from the Yukon via the Dempster Highway.

Figure 1.2 shows the major geographical features of Yukon.

1 Statistics Canada, Land and freshwater area, by province and territory, http://www.statcan.gc.ca/tables- tableaux/sum-som/l01/cst01/phys01-eng.htm 2 Ibid. 3 Statistics Canada, CANSIM Table 384-0038, Gross domestic product, expenditure-based, provincial and territorial 4 Data: Statistics Canada, CANSIM Table 384-0038, Gross domestic product, expenditure-based, provincial and territorial. Canada-wide, government spending as a share of GDP (at market prices) was 20.42% in 2013. 5 Economic Outlook, July 2014, Department of Economic Development, Yukon Government 6 Ibid.

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Figure 1.2: Topographical Map of Yukon

Source: Energy, Mines & Resources, Yukon Government

With the exception of the coastal plain on the Beaufort Sea, most of Yukon is part of the Cordillera geological region, or Canadian Cordillera. The Cordillera is a chain of mountain ranges that form the “backbone” of North America, Central America, and South America. Canada’s highest mountain, Mount Logan, is located in Yukon, and the territory is also home to 8 of the 10 highest mountains in the country.

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Government, Ownership & Administration of Natural Resources As one of Canada’s three territories, Yukon has no inherent jurisdiction but powers are delegated from the federal government.7 While Yukon is led by a Premier, it has a Commissioner instead of a Lieutenant-Governor. The elected legislative assembly has 19 members and a cabinet appointed by the majority party.8 Yukon elects a single Member of Parliament and is represented by one Senator.

In November 1998, the Yukon government assumed the responsibility of developing its oil and gas resources. The balance of provincial-like authority for natural resources was devolved to the Government of Yukon on April 1, 2003.9 In 1987, the Government of Canada devolved authority over the assets of the Northern Canada Power Commission to Yukon.10 Yukon then established the Yukon Energy Corporation (YEC), a public utility and subsidiary of the Yukon Development Corporation, and transferred the assets to YEC.11

Yukon’s Department of Energy, Mines and Resources is responsible for regulating and granting permits and licenses for mineral exploration and development projects.12 The Department regulates exploration and mining activity. There are three legislative regimes governing mining in Yukon: Placer Mining Act and regulations, Quartz Mining Act and regulations, and the “Coal Regulation” under the Territorial Lands (Yukon) Act.13

In terms of its oil and gas resources, Yukon grants permits and leases, collects royalties, regulates the oil and natural gas industry, monitors oil and natural gas activities, and enforces regulations under its jurisdiction.14 This is done by means of the Oil and Gas Act which was passed in 1998. The Department of Energy, Mines, and Resources is responsible for development of the oil and gas industry, for disposition of oil and gas interests, for the development and administration of the fiscal regime governing the taxation of oil and gas production, and is the main regulatory authority in Yukon.15 Developments in Yukon may be subject to impact assessments under the

7 Government of Canada, Justice Laws Website, Yukon Act S.C. 2001, c. 7, http://laws.justice.gc.ca/eng/acts/Y- 2.01/FullText.html Accessed June 19, 2014. 8 Infoplease website, “Yukon: History and Government”, http://www.infoplease.com/encyclopedia/world/yukon- territory-canada-history-government.html Accessed June 19, 2014. 9 Energy, Mines & Resources Website, Yukon Government, http://www.emr.gov.yk.ca/oilandgas/oil_gas_history.html 10 “History, Yukon Energy Corporation”, YEC http://www.yukonenergy.ca/about-us/profile/history/ 11 “About YDC”, Yukon Development Corporation, http://ydc.yk.ca/about_ydc/corporate_governance/ 12 Government of Yukon, Energy, Mines and Resources, http://www.emr.gov.yk.ca/mining/exploration.html Accessed June 19, 2014. 13 Ibid. 14 Ibid. 15 Government of Yukon, Energy, Mines & Resources http://www.emr.gov.yk.ca/oilandgas/index.html Accessed November 19, 2014

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Yukon Environmental and Socioeconomic Assessment Act (Canada), a regime that applies throughout Yukon on federal, territorial and First Nation lands.16

While Yukon has the authority to grant dispositions on Crown Land, Yukon First Nations are responsible for development of oil and gas resources where they own the subsurface rights. First Nations own both surface and subsurface rights on lands categorized as Category A Settlement Lands. At present, 11 percent of Yukon’s prospective oil and gas lands are owned by Yukon First Nations. Except where First Nations maintain a common regime with Yukon, the First Nations are responsible for issuing interests and regulation of activity on their lands. On lands categorized as Settlement B, First Nations own the surface rights and the Yukon government exercises authority over subsurface rights. While subsurface interests will be issued by Yukon Government, additional surface rights provisions may apply on Category B Settlement Lands.17

Oil and Gas Infrastructure Yukon has seen limited oil and gas exploration and development. The only production in Yukon to date has been from the Liard Basin, with continuous production from three wells between 1991 and 2012. This production was delivered to North American markets via the Spectra (Painted Mountain) Pipeline. Yukon has seen the development of hundreds of kilometers of pipeline infrastructure and the scoping of pipeline corridors in association with three main projects – the Canol Pipeline, built and operated for 15 months during World War II, the Haines- Fairbanks Pipeline, and the planning of corridors for the proposed Alaska Highway Pipeline and the Mackenzie Valley Pipeline, which both included two versions of a corridor referred to as the “Dempster Lateral”.

Yukon saw significant, but short-lived infrastructure development during World War II. The construction of the Canol Pipeline from Norman Wells to Whitehorse, and a refinery in Whitehorse (pictured in Figure 1.3) were undertaken to ensure wartime supplies sourced at Norman Wells, Northwest Territories, could be delivered for the war effort in the Pacific theatre based in Alaska.

Over 50,000 people worked on the Canol project, which cost US$134 million (US$1.8 billion real dollars). Having been in service only 15 months, the refinery and pipeline were largely dismantled and sold shortly after the end of the war, in 1947.18

16 Yukon Environmental and Socioeconomic Assessment Board, http://www.yesab.ca/submit-a-project/do-i-need- an-assessment/ 17 Section 5.4, Settlement Land, Umbrella Final Agreement http://www.eco.gov.yk.ca/pdf/umbrellafinalagreement.pdf 18 “The Alaska Highway: A Yukon Perspective”, 49-53, Government of Yukon, 1992, http://www.alaskahighwayarchives.ca./en/chap5/index.php

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Figure 1.3: The Canol Refinery at Whitehorse, October 29, 1943

Source: Finnie Family Fonds, 81-21 #456 PHO141, Yukon Archives

The Canol system saw the development of a total of 2,600 kilometers (km) of pipeline. A span of 925 km of supply pipeline connected Norman Wells oil to the refinery in Whitehorse. A distribution line connected Whitehorse to Fairbanks (960 km). A secondary supply and distribution line connected Skagway to Whitehorse, via Carcross (175 km), and Skagway to Watson Lake, also via Carcross (425 km).

Other Pipeline Infrastructure Other pipeline infrastructure developed during the Cold War era includes a now- decommissioned pipeline from Haines, Alaska to Fairbanks, Alaska. The pipeline traversed a portion of southeast Yukon.

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Figure 1.4: Studebaker Truck Loaded with Pipe Moving toward the End of the Line Pipe already welded is alongside road, Mile 155 from Canol Camp, 21 January 1944

Source: Finnie Family Fonds, 81-21 #478 PHO141, Yukon Archives

Alaska Highway Pipeline Project & Mackenzie Valley Pipeline Project The Alaska Highway Pipeline Project (AHPP) saw planning for the addition of 2,816 kilometers of pipeline, 30 percent of which (832 km) would have traversed Yukon. This project also included the proposal for a “Dempster Lateral”, whereby 1,200 km of pipeline would bring gas from the Mackenzie Delta to the AHPP,19 lending itself to the potential for development of gas in Yukon.

The second generation of planning for the Mackenzie Valley Pipeline (MVP) Project saw a proposed reverse-Dempster Lateral that would allow gas from north Yukon to connect to the MVP from Eagle Plain.20

The Yukon’s Electricity Generation and Transmission Yukon’s electrical system is a stand-alone system that is managed by two entities – the Yukon Energy Corporation (YEC) and ATCO Electric Yukon (AEY). The YEC is the territory’s main producer of electricity while the AEY is the main power distributor, purchasing most of its power from the YEC. The YEC, a subsidiary of the Yukon Development Corporation, is a Crown Corporation established in 1987. While the AEY is the main power distributor in Yukon, it owns and operates its own hydro facility as well as a number of community diesel generating facilities. The AEY is an investor-owned private electrical utility and is owned by ATCO.

19 The Northwest Passage: Arctic Straights, Pharand Donat & Leonard Legault, Martins Nijhoff Publishers, 1984 20 “Yukon Looking Laterally—Interest Growing for Dempster Gas Line”, Northern News Service, p. 73, September 5, 2003 http://www.nnsl.com/frames/newspapers/2003-09/sep5_03pip.html

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The YEC has the capacity to generate 132 MW of power, 92 MW of which are provided by hydro and 39 MW by diesel generators.21 The Whitehorse-based utility has three hydro plants, the largest being the facility in Whitehorse. The Whitehorse Rapids Plant, located at Schwatka Lake Dam, produces 40 MW through four units.22 The oldest two units date back to 1958, while the other two units were added in 1969 and 1985.23 The 1985 20 MW unit doubled net capacity. That capacity is reached in the summer when river flows are higher; in winter the capacity is rated at approximately 25 MW.24 The Aishihik Hydro Facility has three generating units that produce up to 37.5 MW.25 The first two units began service in 1975 while the third unit was added in 2011. The Aishihik Lake facility was built to serve the large lead-zinc mine at Faro, in central Yukon.26 Yukon’s third hydroelectric project is the Mayo, also located in central Yukon. It is the smallest capacity at 15 MW, and the oldest, with the original two units dating back to 1951. The facility was built to power the United Keno Hill Mine. After the mine was shut down in 1989, YEC built a 232-kilometer transmission line from Mayo to Dawson City.27 The Mayo B project, along with the newly-completed Carmacks to Stewart transmission line, added 10 MW in 2011. This service helped to satisfy growing demand for renewable power for residential, commercial and mining load growth on the hydro-based grid.28

YEC uses diesel generators for backup, particularly for the winter months when river flows are lower. Yukon Energy operates 19 diesel generators in total.29 There are eight diesel generators at the Whitehorse Rapids Plant; the utility operates seven fixed back-up units and a single movable unit. Total capacity is approximately 25 MW.30 YEC operates another six units in Dawson, including a single unit that is mobile.31 In addition, YEC operates three diesel units in Faro and two units in Mayo. Due to their high cost, the YEC is proposing to replace several diesel units with natural gas or LNG at an anticipated substantial cost savings. The YEC directly serves retail customers in Dawson City, Mayo and Faro.

YEC also manages two wind turbines on Haeckel Hill. Located near Whitehorse, the older is a Bonus 0.15 MW turbine which began service in 1993 while the other is a Vestas V47-660 turbine

21 Yukon Energy website, “Profile”. http://www.yukonenergy.ca/about-us/profile/ Accessed June 19, 2014. 22 Ibid. 23 Yukon Energy website, “Our Projects and Facilities”, http://www.yukonenergy.ca/energy/facilities/hydro/ Accessed June 19, 2014. 24 Ibid. 25 Ibid. 26 Ibid. 27 Ibid. 28 Ibid. 29 Yukon Energy website, “Diesel Facilities”, http://www.yukonenergy.ca/energy/facilities/diesel/ Accessed June 19, 2014. 30 Yukon Energy, Mines and Resources, “Energy for Yukon: The Natural Gas Option”, November 2010, pp. 20, http://www.emr.gov.yk.ca/oilandgas/pdf/e4yfinal.pdf. Accessed June 19, 2014. 31 Yukon Energy website, “Diesel Facilities”, http://www.yukonenergy.ca/energy/facilities/diesel/ Accessed June 19, 2014.

March 2015 Economic Impacts of Natural Gas Development 9 Within the Yukon Territory that went online in 200032 with a capacity of 0.66 MW.33 The YEC is currently studying the viability of additional wind farms at Tehcho, near Stewart Crossing and Mt. Sumanik.34 Solar energy and geothermal resources are currently being identified in Yukon.

With almost 17,000 customers in 19 communities in Yukon, the AEY is the main distributor of electricity to Yukon.35 While its headquarters are in Whitehorse, the AEY is a member of the Alberta-based ATCO Group of Companies. The company purchases power from YEC and distributes it to its consumers in Whitehorse, Marsh Lake, Tagish, Teslin, Haines Junction, Carmacks, Carcross, Pelly Crossing, Stewart Crossing, Keno, and Ross River.36 The AEY also maintains back-up generating plants in communities with electrical loads larger than 1 MW; and in Carmacks, Teslin, Haines Junction and Ross River in the event of a major transmission or generation outage.37 The company generates and distributes its own power in Old Crow, Beaver Creek, Destruction Bay, Upper Liard, Lower Post, Burwash, Watson Lake, and Swift River.38 The AEY generating capacity is approximately 16 MW, of which 15 MW is diesel. The exception is the Fish Lake Hydro plant, on the outskirts of Whitehorse.39 The three largest diesel facilities are located in Watson Lake (5 MW), Haines Junction (1.5 MW) and Carmacks (1.5 MW).

32 Yukon Energy website, “Wind Energy Project”, http://www.yukonenergy.ca/energy/facilities/wind/ Accessed June 19, 2014. 33 Ibid. 34 Ibid. 35 Atco Electric Yukon website, “About Us”, http://www.atcoelectricyukon.com/About-Us/ Accessed June 19, 2014. 36 Ibid. 37 Ibid. 38 Ibid. 39 Yukon Utilities Board website, “Yukon Electrical Company Limited”, http://yukonutilitiesboard.yk.ca/utilities/yecomp/ Accessed June 19, 2014.

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Figure 1.5: Yukon Electricity Facilities, 2014

Source: Yukon Energy Corporation and the Yukon Electrical Company Limited.

Figure 1.5 illustrates Yukon’s electricity system. Until the completion of the 138 kV Carmacks- Stewart Transmission line, Yukon had two separate grids – the Whitehorse-Aishihik-Faro (WAF) and the Mayo-Dawson (MD). While both are owned and operated by the YEC, the former is in the southern Yukon while the latter is further north. The WAF grid is a 138 kV line that is approximately 510 kilometers in length.40 The initial purpose of the line was to join the hydro generating plants of Whitehorse Rapids and Aishihik to the mine at Faro.41 The MD transmission line, on the other hand, runs at 69 kV and extends 229 kilometers.42 It connects the Mayo hydro

40 Energy for Yukon: The Natural Gas Option, Yukon Energy, Mines and Resources, November 2010, pp. 6, http://www.emr.gov.yk.ca/oilandgas/pdf/e4yfinal.pdf Accessed June 19, 2014. 41 Ibid. 42 Ibid.

March 2015 Economic Impacts of Natural Gas Development 11 Within the Yukon Territory plant to Dawson City, which primarily relied on diesel power from 1966 to 2004. The two grids were joined on June 17, 2011, when the transmission line between Stewart Crossing and the AEY- served Pelly Crossing were completed.

While the completion of the Carmacks-Stewart Power Line between Stewart Crossing and Pelly Crossing has reduced the dependence on diesel plants, the YEC and the Yukon Government have stated further reduction in the use of diesel generation would be considered. Citing high costs and high GHG emissions, the YEC is proposing to shift backup generation from diesel to natural gas. The YEC predicts that demand from the mining industry, in which the mine sites are often located off the hydro grid, could be as high as 200 MW by 2021.43 Historically, mining operations at a distance from the grid relied on diesel. Casino Mining Corporation and the proposed Casino mine alone will use nearly twice the electricity available from all of the YEC’s hydroelectric generation.44

The YEC is installing two new LNG-burning generators to replace aging diesel generators near the Whitehorse Rapids hydro facility45 to meet existing and new demands. The short term plan is to truck LNG from British Columbia or Alberta. In the long term, it is possible that the natural gas could be sourced locally from Yukon, as will be discussed in further detail later.

Presently under construction, the new LNG power generation facility will serve Yukon with a scheduled in-service date of spring 2015. The facility is located adjacent to the existing hydro and diesel generating facilities in Whitehorse. The YEC has indicated the cost of the project will total C$34 million: C$10.5 million to purchase two generators and C$23.5 million to prepare the site and build a storage facility on the land beside Robert Service Way and the railway tracks.46

A second LNG facility is being proposed by the AEY. An LNG facility license has been issued to AEY for a bi-fuel plant to serve Watson Lake. This project will be proceeding with additional authorizations.

Mining and Mineral Exploration and Development Yukon’s mining sector is a key driver of electricity and natural gas demand. Yukon’s mining has its roots in alluvial placer mining.47 In 2013, placer gold mining in Yukon reached the highest level since 2006, with production of 59,562 ounces of gold – valued at $72.3 million (USD) – although

43 Ibid. pp. 2. 44 Yukon News Website, “Yukon Bullish on Natural Gas”, July 10, 2013, http://yukon-news.com/news/yukon- energy-bullish-on-natural-gas Accessed June 19, 2014. 45 Ibid. 46 Whitehorse Star website, “Yukon Energy eyes May 2014 for LNG project start”, August 29, 2013, http://www.whitehorsestar.com/archive/story/yukon-energy-eyes-may-2014-for-lng-project-start/ Accessed June 19, 2014. 47 Popularly known as “panning for gold”, alluvial placer mining today is often done on a much larger scale, with heavy equipment helping to accomplish the task.

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still well-short of the long-term annual average of 146,000 ounces/year.48 For more information about the history of mining in Yukon, please see Appendix B.

Diesel has played a sustained role in providing energy for mining in Yukon, particularly for the off-grid hard rock producers and placer miners. However, the long supply chain and relatively high oil prices have imposed a high cost on those miners relying on diesel.

The current generation of mineral development and production projects in Yukon resulted from exploration investments and discoveries made several decades ago.

Table 1.1 provides a survey of current advanced exploration, mineral development projects, and producing mines. Information is included as to when the deposit was first staked, principal economic commodities, and the status of the project in relation to key stages in advanced exploration, mineral deposit appraisal, and development (technical, National Instrument 43-101 compliant-resource estimates; preliminary economic assessment, pre-feasibility, feasibility, permitting, construction, and production).

48 Energy, Mines & Resources, personal communication & Yukon Placer Mining Industry 2010-2014

March 2015 Economic Impacts of Natural Gas Development 13 Within the Yukon Territory

Table 1.1: Survey49 of Advanced Exploration, Development and Producing Projects

First Prod Deposit Commodities Company Staked Pre-feas Feas Permits Construct Start

Capstone 1971 1996 1997 2006 2007 Minto Ag, Au, Cu Mining Corp Ag, Au,Cu, Pb, Yukon Zinc 1973 2000 2006-07 2010 2011 Wolverine Zn Corp Alexco 1996, Resources 1919 2009/10 2009 2011 2013 Bellekeno50 Ag, Au, Pb, Nn Corp 1901, Eagle Gold Victoria Gold restaked 2012 2013 2015 (Dublin Gulch) Au Corp 1973/78 Golden Predator 1987 PEA 2014 1995 1996 1997-01 Brewery Creek Au Mining Corp

Ni-PGE, Au, Cu, Wellgreen 1952 PEA 2014 Wellgreen Co Platinum Ltd 1994, Carmacks Copper North 1970 2007, Copper Ag, Au, Cu Mining Corp 2012 North American Technical 1962 2013 Tungsten 2009 Mac Tung W, WO3 Corp 1911, Western 2008, restaked Copper & 2014 Casino Ag, Au, Cu, Mo Gold Corp 1965 Chihong Resource Canada 1972 est. 2012 Howard's Pass Pb, Zn Mining, Ltd Northern Largo 1976 PEA 2011 Dancer Mo, W, WO3 Resources Whitehorse Eagle Copper Tailings Industrial 1898 1900-20, Reprocessing Ag, Au, Cu, Mo Minerals Resource Kaminak Gold 2006 est. 2013 1924-29, Coffee Gold Au Corp & 14 ATAC Initial Rackla Gold Resources, 2006 resource 1967-82 (Rau Trend) Ag, Au Ltd est White Gold Initial (Golden Kinross Gold 2003 resource Saddle, Arc) Au Corp est Source: Yukon MINFILE, 2014, Accessed Nov 18-2, 2014, company websites

49 This survey includes a number of advanced exploration projects, although it is not intended to be exhaustive. 50 Bellekeno is currently under temporary closure due to market conditions. A preliminary economic assessment for production at Bellekeno, Lucky Queen, Flame and Moth mines (referred to as Eastern Keno Hill District) was completed in November 2013.

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For Yukon’s mineral sector outlook, the most recent upturn in the minerals and metals markets has resulted in a sustained period of growth in exploration and deposit appraisal investment, with annual spending since 2005 exceeding the long term average by 5.15 percent (compared to 5.9 percent for the 1968-1982 period). Growth during this period has been predominantly driven by the development of the “BRIC” economies (Brazil, Russia, India and China).51 This period of sustained, well-above-average investment rates for Yukon has resulted in $1.55 billion in spending in mineral exploration and development.52 The peak year for investment during the period 2005-2014 was 2011, with $367 million53 of spending.

The upwards movement in metal prices since 2005-2006 has spurned a turn-around in investment in mineral exploration and deposit appraisal in Yukon. Recent developments in exploration and deposit appraisal spending in Yukon are outlined in Figure 1.6.

Figure 1.6: Exploration and Development Activity in Yukon, 2005-2014

350 $300

300 Millions $250 250 $200 200

$150

150 # of Projects of #

$100 100

$50 50

$- 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Exploration Development # of Projects

Source: Energy, Mines & Resources, Yukon Government

As reserves have been mined out in regions closer to infrastructure and markets, exploration investment has increasingly moved to greenfield exploration in “frontier” regions such as Canada’s three territories.

51 Unlike the 1970’s, this investment period was not accompanied by major changes in tax provisions for exploration and development in Canada. 52 Corporate Policy & Planning, Energy, Mines & Resources 53 Yukon Geological Survey (data) & Corporate Policy & Planning (analysis), Energy, Mines & Resources

March 2015 Economic Impacts of Natural Gas Development 15 Within the Yukon Territory

The majority of development investment in Yukon since 2005 has been in the base metals sector, as outlined in Table 1.2. During the 2005-2014 period, Yukon has seen several mines into production and several projects advance to feasibility, permitting, financing, and construction. Since 2011, with the contraction of equity markets, and contraction in metal prices, several advanced projects have slowed down their pace of development. One producing mine, Bellekeno, has temporarily ceased production, and both the Wolverine and Minto mines have scaled back operations.54

Table 1.2: Development Investment in Yukon, 2005-2014 Total $ 599,190,000.00 % Precious Metals (Au, Ag) 14.6% % Base Metals (Cu, Mo, Zn, Pb) 85.4%

Source: Analysis: Corporate Policy & Planning; Data, ArcsGIS & Access Database, Energy, Mines & Resources, Yukon Government

In exploration terms, investment aligns with general trends for exploration investment elsewhere in Canada, with just over half of investment targets focused on precious metals (Table 1.3). In association with this investment, there were close to 2 million combined metres of diamond and reverse circulation drilling over the 10 year-period.55

Table 1.3: Exploration Investment and Activity in Yukon, 2005-2014 Total $ 951,267,068.00 % Precious Metals (Au, Ag) 52.8% % Base Metals (Cu, Mo, Zn, Pb) 38.0% % Nickel-Platinum Group Metals 3.4% % Tungsten 2.3% % Other 3.5% Meters Diamond Drilling 1,786,303 # Diamond Drilling Holes 1,786,30312,400 Meters Reverse Circulation Drilling 232,96512,400 # Reverse Circulation Holes 232,96511,958

Source: Analysis: Corporate Policy & Planning, Energy, Mines & Resources, Yukon Government 11,958

54 Personal communications. Corporate Policy & Planning, Energy, Mines & Resources 55 Ibid

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Recent sustained investment in mineral exploration and development has influenced Yukon’s overall economy. Driven by mineral exploration and development spending, business investment as a share of GDP at market prices rose from 13.4 percent in 2001 to 35.7 percent in 2011.56 Over the 2005-2014 period, business investment averaged 26 percent annually in Yukon, comparing favourably to the Canadian average of 19 percent.57

Yukon Energy Strategy In 2009, the Yukon government approved the Yukon Energy Strategy.58 Responsible development of Yukon oil and gas resources for local use and export is among the goals established by the strategy. Strategies articulated for achieving this goal include:

 Developing an oil and gas sector in a way that will deliver the greatest benefits to Yukon;  Promoting efficiency and conservation for the use of oil and gas resources;  Reducing Yukon’s reliance on imported fossil fuels;  Promoting private sector investment in the development of Yukon’s oil and gas resources; and  Preparing for northern pipeline development.

The Oil and Gas Resources Branch of the Yukon government administers the issuance of oil and gas interests, and ensures the management and development of the resource overall within this policy framework.

The YEC system is currently at capacity, with two industrial users in recent years, Minto and Bellekeno mines connected to the grid. At 273 kilometers from the grid, Wolverine mine has relied on diesel generation to power operations. In 2011, YEC produced a 20-year Resource Plan covering the period 2011-2030, to explore options for facility enhancement and system development.

A consideration not at issue in Yukon prior to the devolution of NCPC (Northern Canada Power Commission) assets is the borrowing constraint on the Yukon government and its agencies. Federal legislation prohibits Yukon from borrowing in excess of $400 million.59 This constraint may have implications for Yukon’s energy development.

Coinciding with a period of escalating diesel costs, declining natural gas prices in North America, and significant barriers to entry and risk associated with major capital investments such as new hydro, the YEC 20-year Resource Plan examines LNG as an option. The 20-year Resource Plan

56 Corporate Policy & Planning, Energy, Mines & Resources. Data: Statistics Canada, CANSIM Table #382-0038: Gross domestic product, expenditure-based, provincial and territorial, annual (chained 2007 dollars unless otherwise noted). Accessed December 15, 2014. 57 As a greater number of projects move to sustained production, exports are likely to represent a larger share of GDP, all other things being equal. 58 Yukon Energy Strategy, Yukon Government http://www.energy.gov.yk.ca/pdf/energy_strategy.pdf 59 “Territorial Borrowing Limits”, Department of Finance, Government of Canada, http://www.fin.gc.ca/fedprov/tbl-pet-eng.asp

March 2015 Economic Impacts of Natural Gas Development 17 Within the Yukon Territory examines LNG to meet load requirements over the short-, medium- and long-term, as no current Yukon or regional production is available to supply growth. In the short-term, this has resulted in the development of an LNG plant in Whitehorse to displace end-of-life diesel generators providing peaking capacity, and a proposed bi-fuel project under development to displace diesel generation in Watson Lake.

The current estimate for the delivered cost of LNG to Whitehorse from Delta, BC is approximately $18.15/MMcf ($4.25 for the commodity; $4.40 liquefaction charge and $9.50 transportation cost). Future LNG sources or regulatory approval for cost-reducing transportation alternatives may reduce the cost of transportation to $5.70/MMcf, resulting in a delivered cost of $14.35/MMcf.60

As part of the YEC planning exercise, a forecast of load requirements was completed, including an assessment of requirements for a number of prospective mineral developments. Key to this planning process was the fact that the Yukon system is an isolated grid, with a number of prospective mineral development projects at some significant distance from the existing grid.

In the past, diesel was considered in the course of economic evaluation of mineral development projects, but mining companies have moved to consider LNG for baseline power in their economic assessments. This development has emerged in tandem with the significant downward trends in North American natural gas prices in recent years.

60 Personal communication, Yukon Energy Corporation; analysis Corporate Policy & Planning, Energy, Mines & Resources

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Figure 1.7: Map of Mineral Development, Electrical Grid & Pipeline Routes

Source: Energy, Mines & Resources, Yukon Government

Three producing mines have met their energy requirements from the following sources:

 Minto: Hydro61 through grid connection  Bellekeno: Hydro through grid connection  Wolverine: On-site diesel generation

61 The Yukon Energy Corporation meets the vast majority of supply requirements through hydro generation. Peak demand is met with diesel generators (under replacement with LNG generators). Limited on-grid wind generation is also a component of the YEC system.

March 2015 Economic Impacts of Natural Gas Development 19 Within the Yukon Territory

Table 1.4 outlines available information about current and projected energy requirements associated with mineral development projects, producing mines, mines in temporary closure, and advanced exploration projects. For the most part, projected energy requirements have been identified through a preliminary economic assessment or feasibility study.62

Table 1.4: Active and Prospective Mine Loads Annual Annual Energy Energy Deposit GW.h (low) GW.h (high) Project Life Status Minto 23.4 46.7 8+ yrs. Producing Wolverine 37 37 7+ yrs. Temp Closure Eastern Keno Hill Silver District 15 21.7 5+ yrs. Temp Closure PEA/Permitting/Past Brewery Creek 20.5 33.88 9 yrs. Producer Eagle Gold 95 95 7.3 yrs. Financing Wellgreen Platinum 300 574 25 yrs. PEA/Baseline Studies Carmacks Copper 56.5 56.5 7+ yrs. Feasibility Howard's Pass (Selwyn Project) 705 860 11+ yrs. Exploration/Feasibility Casino 940.8 940.8 22+ yrs. Permitting MacTung 58 58 11+ Feasibility/Assessment Coffee Gold 90 90 11 PEA Northern Dancer 200 300 29-30 yrs. Exploration/PEA Whitehorse Copper 8.7 8.7 6 yrs. Past Producer Ketza River 2 2 6 yrs. Past Producer Rackla Gold (Tiger Advanced Gold Deposit) N/A N/A 10+ yrs. Exploration/PEA Tagish Lake Gold N/A N/A N/A Past Producer White Gold 30 60 10+ yrs. Advanced Exploration Total GW.h/yr. 2581.9 3184.28 Sources: 20-year Resource Plan, YEC; company websites & personal communication

With Yukon Energy Corporation’s system at capacity, and numerous mineral development projects advancing, the fundamentals for energy supply favour scalable, reliable and affordable solutions.

The Yukon Minerals Advisory Board has declared energy as central to current and near-term mineral exploration and development: “(T)he limited availability of reliable and price competitive

62 This survey is not exhaustive, but is focused on projects in production, temporary shut-down, past producers with active exploration and development programs, and with advanced and active exploration programs. For the purposes of the time horizon of this study, the selection of projects was intended to given an indication of the short- and mid-term demand outlook.

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energy – including access to an electrical grid – affects all sectors of the economy and continues to negatively impact the territory’s current and future mineral development industry. Energy costs comprise a significant part of a mine’s operating costs and the use of diesel power places Yukon mines at a competitive disadvantage compared to mines in other jurisdictions.”63

Under the umbrella of “Next Generation Hydro”, the Yukon Development Corporation (YDC) is charged with evaluating one or more hydroelectric projects that might contribute to “an adequate and affordable supply of reliable and sustainable electrical power in Yukon.”64 As part of the site screening undertaken by YDC, $183/MWh ($ 2014) is the cut-off for identifying prospectively economic hydro sites in Yukon.65 A short-list of 16 sites is economically viable at this cut-off. (The benchmark cut-off is based on YEC’s 2011, 20-year Resource Plan levelized cost of energy for LNG of $183/MWh.) Another option to address energy demand in Yukon is a capital-intensive grid interconnection, such as with the Northwest Transmission Line project in northwest British Columbia.66

As noted above, companies moving into economic evaluation of projects are exploring LNG as the near- and mid-term baseline to assess project feasibility. Wellgreen Platinum, operators of the Wellgreen Mine, have signaled their intentions to power operations with LNG by signing a memorandum of understanding with General Electric Canada and Ferus NGF for the supply of LNG and equipment.67

63 p. 5, Annual Report, 2012, Yukon Minerals Advisory Board http://www.emr.gov.yk.ca/mining/pdf/ymab_annual_report_2012.pdf 64 Section 1(2), “Corporation to plan Project”, Hydroelectric Power Planning Directive, Yukon Development Corporation Act http://www.ydc.yk.ca/uploads/documents/hydroelectric_power_planning.pdf 65 p. 29 Site Screening Inventory, Part 1, Yukon Development Corporation 66 Personal communication, Energy, Mines & Resources 67 “Wellgreen Platinum Enters Agreement for Canadian LNG in the Yukon”, press release, Wellgreen Platinum, August 14, 2014 http://www.wellgreenplatinum.com/news_2014_aug_14_wellgreen_platinum_enters_agreement_for_canadian_l ng_in_the_yukon.php

March 2015 Economic Impacts of Natural Gas Development 21 Within the Yukon Territory Chapter 2 Yukon Basins: Availability and Risk

In Yukon, oil and gas resources and related land management are principally governed by the Oil and Gas Act and other laws of general application. However, resources and related access may also be subject to treaty, legislative, or administrative provisions affecting oil and gas availability.

In advance of oil and gas and energy infrastructure development in Yukon, the issues of basin availability and land access must be addressed. The smaller the available resource base, the higher the financial risk will be for infrastructure development. The exception to this is where existing infrastructure allows access to the wider market, and presently this is the case only for Liard Basin.

Yukon’s eight hydrocarbon basins represent a small proportion of the territory’s total land area – only 14.8 percent. Of that, much cannot currently be accessed for a variety of reasons. The discussion below outlines the current status of oil and gas resources, falling into four main categories: available, unavailable, encumbered, and First Nations-owned.

Governments and corporations looking to develop oil and gas in Yukon must consider resource ownership, availability, and land access restrictions as central to their risk mitigation strategies.

Available A number of basin areas in Yukon are presently available for oil and gas exploration and production. This includes areas under the authority of Yukon that are neither constrained by regulation nor by Ministerial direction under Section 17 of the Oil and Gas Act. By this measure, 36 percent of Yukon basins are currently available.

Resources considered available are administered under laws of general application. Currently, 7.2 percent of Yukon basins are under active disposition, while 29.4 percent remain open and available for disposition.

Unavailable Some areas are off-limits to oil and gas exploration and production. At present, over 12.7 percent of oil and gas basins are restricted for the long term as a result of establishing, for example, national parks or certain types of territorial parks.

Constraints resulting in resources being considered unavailable are as follows:

 A regulatory withdrawal is in effect for an indefinite period under Section 17 of the Oil and Gas Act, in combination with a legal designation of the area to a class of parks or protected areas that does not allow for disposition of oil and gas resources; or

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 Oil and gas resources are governed pursuant to the Yukon Act and National Parks Act or other federal law restricting oil and gas disposition.

These basin areas are not considered likely to become available during the study horizon. Currently, over 12.7 percent of Yukon basin areas are unavailable.

Encumbered Forty percent of the hydrocarbon-prospective basin areas in Yukon are temporarily unavailable but may be made available in the future. Where the resource is encumbered, a third party applicant is unable to secure oil and gas rights.

These resources and associated land access are currently constrained by one or more of the following four measures:

 A regulatory restriction under Section 17 of the Oil and Gas Act, where the restriction is subject to a sunset provision or otherwise limited by treaty or law, establishing that oil and gas disposition and management will revert to provisions established by laws of general application;  An explicit term of a treaty establishing provisional restriction given effect by law;  Government-mandated management direction limiting land use activities normally associated with oil and gas exploration, production, or related infrastructure given effect by Ministerial direction under Section 17 of the Oil and Gas Act; or  Withholding or refusal of disposition by the Minister for any other reason, under Section 17 of the Oil and Gas Act for 12 consecutive months or more.

It is important to reiterate that encumbered oil and gas basin areas and associated land access are provisionally unavailable but may be open for future oil and gas activity. For the purposes of this study, an area is categorized as encumbered if there is a possibility of it being released before the end of the study period.

First Nations-Owned Yukon has 14 First Nations residing in the territory; 11 have settlements in place with the governments of Canada and Yukon. For those First Nations with Category A Settlement Land, a Yukon First Nation has ownership and authority over the land surface and subsurface resources.

In Yukon, 11 percent of oil and gas basin areas are owned by Yukon First Nations. For a third party to acquire rights and carry out activities for the purpose of exploring and developing oil and gas resources, interests must be acquired from the First Nation and its consent secured for exploration and development activities, although regulation may occur in accordance with the Oil and Gas Act.

March 2015 Economic Impacts of Natural Gas Development 23 Within the Yukon Territory

Figure 2.1: Current Availability in all Yukon Basins, Percentage of Total Basin Area

Encumbered 40%

Available 29%

Unavailable 13%

First Nation 11%

Available Active 7%

0% 5% 10% 15% 20% 25% 30% 35% 40% 45%

Sources: Energy, Mines & Resources, Government of Yukon

Oil and Natural Gas Potential Yukon has eight onshore oil and gas exploration regions with a combined total of assessed conventional hydrocarbon resources of 14.76 Tcf of natural gas and 662.6 MMbbls of oil (Table 2.1). In addition, Yukon has an interest in offshore hydrocarbon exploration and development in the Beaufort Sea, which shows the potential for conventional oil and gas resources.

The Tintina Fault can be observed in Figure 2.2, running from the Alaska border, northwest of Dawson City, down southeast to Watson Lake and the border with British Columbia – a distance of approximately 420 km. The northeast of the strike-slip fault is comprised of thick, old sedimentary rocks, while the southwest part of the Tintina is composed of a mix of younger rocks. Of the eight sedimentary basins attracting attention for the hydrocarbons, seven are located northeast of the fault line while only one is southwest of the fault line – the Whitehorse Trough. Only two sedimentary basins are located in southern Yukon, Whitehorse Trough and Liard. The remainder are located in northern Yukon and have similar geological characteristics to the Western Canadian Sedimentary Basin.

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Figure 2.2: Yukon’s Oil and Natural Gas Resource Potential by Exploration Region

Source: http://www.emr.gov.yk.ca/oilandgas/oilgas_resource_assessments.html

Table 2.1 illustrates the oil and natural gas potential of the sedimentary basins. In terms of natural gas potential, the three largest basins are Eagle Plain (3,400 Bcf), Liard (4,460 Bcf), and Peel Plateau & Plain (2,920 Bcf). In terms of oil potential, the three largest basins are Eagle Plain (329 MMbbls), Beaufort-Mackenzie (217 MMbbls), and Kandik (99 MMbbls). Only the Eagle Plain and Liard, however, hold significant discovered gas and oil resources. Eagle Plain has 83.7 Bcf of natural gas and 3.5 MMbbls of oil, while Liard has 417 Bcf of natural gas. The resource assessments for Eagle Plain and Liard were undertaken by the Geological Survey of Canada and the National Energy Board (NEB), respectively.

March 2015 Economic Impacts of Natural Gas Development 25 Within the Yukon Territory

Table 2.1: Yukon’s Oil and Natural Gas Resource Potential Basin Mean Gas Play Mean Oil Play Discovered Discovered Potential Potential Gas Oil (Bcf) (MMbbls) (Bcf) (MMbbls) Kandik 649 99 Beaufort- 1,008 217 Mackenzie Bonnet Plume 800 0 Eagle Plain 3,400 329 83.7 3.5 Liard 4,460 0.1 417 Old Crow 1,149 0 Peel Plateau & Plain 2,916 0 Whitehorse Trough 380 17.5 TOTAL 14,762 662.6 500.7 11

Source: Yukon Energy, Mines and Resources 1

In 2014 onshore exploration and/or development activity are proposed or underway in two areas — the Eagle Plain basin and the Liard region’s Kotaneelee gas, the only natural gas field with historic production. However, for the purposes of this study the analysis will focus on the economic impacts of the Eagle Plain and Peel Plateau & Plain Basins. The other basins are further described in Appendix A.

This report considers Eagle Plain as the most feasible area for development for the following reasons: there is a high degree of availability, in excess of 70 percent (see Figure 2.3); among the northern basins, it is closest to the Whitehorse-Aishihik-Faro (WAF) grid and has the advantage of the Dempster Highway corridor passing through. Furthermore, according to the Government of Yukon’s latest estimates of gas reserves, Eagle Plain shows potential, with 3.4 Tcf mean gas- in-place (see Table 2.1). Eagle Plain is the most viable option for Yukon gas development.

1 Government of Yukon, Energy, Mines and Resources, Oil and Gas Resource Assessments. Tiffany Frasier, online communication, 2014.

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Figure 2.3: Yukon Basin Availability, 2014

100%

90% 90.6% 80%

70% 73.0% 60%

50%

40%

30% 36.0%

20%

10% 0.0% 0.4% 2.3% 4.2% 0.0% 0%

% Available % Encumbered % Unavailable % First Nations

Sources: Energy, Mines & Resources, Government of Yukon

Eagle Plain Basin The Eagle Plain sedimentary basin is currently attracting the most attention in Yukon. The large basin is located in northern Yukon, surrounded on all four sides by mountain ranges. The intermontane basin is underexplored, but holds proven hydrocarbon potential, particularly in the Middle Devonian to Upper Cretaceous strata.2 While there are no pipelines, the area is accessible by the Dempster Highway, and the Dempster lateral pipeline corridor transects the basin. The largest nearby communities are Old Crow, and Dawson City, both located about 250 km from the basin.

Figure 2.4 shows Eagle Plain’s geographical features. Kandik basin is to the west and Peel Plateau & Plain is to the east. Most bedrock geology is Quaternary (beige-shaded) and Late Cretaceous-

2 Ibid.

March 2015 Economic Impacts of Natural Gas Development 27 Within the Yukon Territory

Tertiary (brown-shaded). The illustration also shows oil and gas wells, as well as dry and abandoned wells.

Fifteen petroleum plays in the Eagle Plain are attracting attention. Nine are natural gas-related, while six are oil-related. The plays are further broken down by the trap: structural or stratigraphic. They are Cretaceous, Permian, Carboniferous, Lower Carboniferous, and Lower Paleozoic-aged rocks. The most promising are the Permian stratigraphic, Carboniferous stratigraphic, and Lower Paleozoic stratigraphic.

While Eagle Plain holds no coalbed methane potential, tight reservoirs show promise overlying the Paleozoic carbonate and Imperial Formation clastics.3 In addition, shale potential exists in the Cretaceous-aged Road River Group, Canol Formation, Ford Lake/Hart River/Blackie and Mount Goodenough/Eagle Plain Group.4 The potential is greatest in the northwestern part of the Eagle Plain, where the shales are thickest and mature.

Figure 2.4: Map of Eagle Plain Basin Exploration Region

Source: http://www.emr.gov.yk.ca/oilandgas/pdf/io_eagle_plain_map.pdf

NCY (Northern Cross (Yukon) Ltd.), with partner CNOOC (Chinese Offshore Oil Corporation Ltd.), is in its 7th year of exploring its 1.3 million acre permit area in the Eagle Plain. NCY advanced its exploration effort in the past year by following up their 2012-13 four-hole drilling program (Figure

3 Yukon Geological Survey Miscellaneous Report 7, “Scoping study of unconventional oil and gas potential”, Department of Energy, Mines and Resources, 2012, pp. 50. 4 Ibid. pp. 51-4.

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2.5) with 3D seismic and airborne LiDAR, methane and temperature surveys.5 Approximately 325 km2 were covered by the 3D seismic survey, overlapping most 2012-13 well locations.

Figure 2.5: Northern Cross Yukon Proposed 2015 Drill Program

Source: Energy, Mines & Resources, Yukon Government

5 Eagle Plain 3D Seismic & Exploration Project Review presentation, Northern Cross Yukon http://www.northerncrossyukon.ca/upload/news_item/9/01/3d-seismic-exploration-project-review.pdf & Open House Presentations June 16-18, 2014: Whitehorse, Mayo, Old Crow & Dawson, NYC, 2014 http://www.northerncrossyukon.ca/upload/news_item/11/02/community-open-house-presentations-june- 2014.pdf

March 2015 Economic Impacts of Natural Gas Development 29 Within the Yukon Territory

NCY has proposed a 20-hole drilling program in the area of the seismic survey, to start in early 2015.6 The focus of the program will be the discovery and appraisal of conventional crude oil and natural gas resources. With discoveries and positive drill stem tests, wells are proposed to undergo flow testing in order to evaluate the long-term viability of the resource. This proposal is currently undergoing public review in the Yukon Environmental and Socio-economic Assessment Board (YESAB) process, with Board recommendations anticipated in the beginning of 2015.

NCY has spent over $105M in exploring their permit area since 2011, a significant proportion of it on employment services in Yukon.7 Expenditures associated with the 2012-13 drilling program exceeded $80M with 25 percent spent in Yukon. Yukon expenditures supported 88 Yukon-based suppliers of goods and services and a work force averaging 20 percent of Yukon residents, including many First Nations citizens. Camp construction and maintenance expenditures totaled over $5M. The 2013-14 3D seismic and other programs cost over $20M, with $4.4M (>22 percent) spent directly in Yukon supporting 51 businesses and Yukon residents. The seismic program alone entailed 7,890 person-days of employment of which 2,249 went to Yukon residents (average 29 percent). Thirty-six Yukon First Nations citizens were either employed or in industrial training programs which included tree-falling/chainsaw, WHMIS, H2S, first aid (including AED), and drilling.8

Peel Plateau & Plain Basin The Peel Plateau & Plain basin is located in northern Yukon in the Northern Interior Platform (approximately 10,300 km2 of the basin lies in Yukon). It is north of the Mackenzie Mountains and east of the Richardson Mountains. The Eagle Plain is located on the other side of the Richardson Mountains to the east. The Peel Plateau & Plain extends east into the Northwest Territories and is bordered on the east by the Anderson Plain.

Figure 2.6 shows the geographical features of the Peel Plateau & Plain.

6 Open House Presentations June 16-18, 2014: Whitehorse, Mayo, Old Crow & Dawson, NYC, 2014 http://www.northerncrossyukon.ca/upload/news_item/11/02/community-open-house-presentations-june- 2014.pdf 7 Northern Cross Yukon Limited Presentation to Yukon Select Committee on Hydraulic Fracturing, January 31, 2014, NCY, 2014; http://www.northerncrossyukon.ca/upload/news_item/10/03/yukon-select-committee-on-hydraulic- fracturing-presentation.pdf & Northern Cross 3D Seismic Program, NCY, 2014, http://www.northerncrossyukon.ca/operations/3d-seismic-program.html 8 Don Stachiw (NCY), personal communication

March 2015 30 Canadian Energy Research Institute

Figure 2.6: Map of the Peel Plateau & Plain Exploration Region

Source: http://emrlibrary.gov.yk.ca/oilandgas/ResourceAssessments/peel_plateau_final_2005.pdf

Peel Plateau & Plain is accessible by Fort MacPherson and Fort Good Hope, Northwest Territories, and by the Mackenzie River. The Peel Plateau & Plain is characterized by low elevation and muskeg.

There are seven petroleum plays in the Peel Plateau & Plain that are periodically assessed for resource potential. The region is divided into three structural domains:

 Peel Plateau west of Trevor fault  Peel Plateau west of limit of deformation  Peel Plateau east of limit of deformation

The limit of deformation, or the Cordilleran Foreland Belt, separates the Plateau from the Plain in the Peel region. All seven petroleum plays are gas plays and their total mean gas potential is 2.9 Tcf in approximately 88 pools.9

9 Yukon Energy, Mines and Resources, “Oil and Gas Resource Assessments”, http://www.emr.gov.yk.ca/oilandgas/oilgas_resource_assessments.html#Peel_Plateau_and_Plain_Oil_and_Gas_R esources_Assessment Accessed June 19, 2014.

March 2015 Economic Impacts of Natural Gas Development 31 Within the Yukon Territory

The Peel Plateau & Plain was first explored in the mid-1950s and the area’s first well was completed in 1965.10 There have been 18 wells in the area since. The target depth is between 1,000 m and 4,000 m.11 The Mesozoic depth to target is surface to 1,000 m, while the Carboniferous is surface to 2,500 m, the Devonian shale is surface to 3,500 m, and the Paleozoic carbonate is from a depth of 1,500 m to 4,000 m.12

10 Aboriginal Affairs and Northern Development Canada, “Chapter 2 – Mackenzie Valley, Southern Territories and Interior Plains”, http://www.aadnc-aandc.gc.ca/eng/1320417163153/1320417233918#chp2.3 Accessed June 19, 2014. 11 Ibid. 12 K.G. Osadetz et al., “Petroleum Resource Assessment, Peel Plateau & Plain, Yukon Territory”, Yukon Geological Survey & Energy, Mines and Resources, 2005, pp. 7, http://emrlibrary.gov.yk.ca/oilandgas/ResourceAssessments/peel_plateau_final_2005.pdf Accessed June 19, 2014.

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March 2015 Economic Impacts of Natural Gas Development 33 Within the Yukon Territory Chapter 3 Description of Issues

Prices for buying or selling natural gas in Yukon would not be affected by external markets. But that would change if the natural gas industry in the territory grows to the point where shipping natural gas to North American or world markets becomes feasible. In that case, the following issues – presently being dealt with in other jurisdictions – would inevitably arise in Yukon and need to be considered by the territory’s government, industry, and other stakeholders.

Supply Abundance The implementation of hydraulic fracturing (or fracking) technology has created a dramatic increase in low-cost shale gas production in the US. While skeptics question the sustainability of shale gas production and economics, the consensus is that the natural gas industry has been permanently changed. Arctic gas developments – that would have been brought to market via the Mackenzie Valley and Alaska Highway pipeline projects and also would have had significant implications for Yukon – have been deferred indefinitely. Prospects for liquefied natural gas (LNG) imports into North America have been reversed to LNG exports from North America. Long-haul pipelines have been displaced by near-market production (e.g., Marcellus basin production adjacent to East Coast markets). While prices below $3/MMcf are viewed as unsustainable in the long run, prices over $4 are seen as equally unsustainable. A significant supply overhang involving shut-in and unfinished wells could result in low prices for an extended period of time. Supply availability and investment decisions are responsive to price changes.

Demand Dynamics The decline in per capita natural gas demand in North America has been a long-term trend as the efficiency of replacement capital improves in residential and commercial markets (e.g., high efficiency furnaces) and as high prices in industrial markets have dampened demand growth. Only natural gas-fired power plants have contributed to increased demand. However, the prospect of extended low-to-moderate prices has changed demand dynamics. While the residential and commercial sectors may remain unresponsive to low prices, prospects in industrial and power markets are buoyant. In a number of states and provinces, natural gas is displacing other types of generation or is the marginal new generation option. Investments to reopen fertilizer and petrochemical plants further signal a potential revival in industrial demand in North America.

The general view is that demand for natural gas will grow on the back of cheap prices. Does this thinking discount the power of the market? Could rising demand support higher prices? Could higher prices then limit demand and increase supply? Or is a natural gas supply bubble really a long “sausage” with low prices extended to the horizon?

March 2015 34 Canadian Energy Research Institute

Market Structure Low prices are pushing producers, and particularly Canadian Exploration & Production companies, toward restructuring and consolidation. With persistent low prices and reduced market access as US production displaces Canadian gas in Eastern markets, producers are experiencing reduced returns. Canadian producers are finding it challenging to compete with low-cost US production that is close to markets. Falling pipeline volumes threaten to further raise regulated transportation costs, providing an additional barrier to accessing markets. Rising demand in Western Canada to support oil sands growth represents one alternative market opportunity. LNG exports offer another, longer-term opportunity.

The structure of natural gas markets is changing in North America and globally. Rapid demand increases in Asia are triggering a surge in LNG projects and offer the prospect of a more integrated global natural gas market. Currently, international sales in Asia and Europe are based on long- term contracts and prices linked to oil. There is pressure, however, to decouple natural gas prices from oil prices and move toward shorter term contracts to take advantage of the gas-on-gas competition which dominates North America. It is uncertain how this emerging dynamic could affect LNG export prices from British Columbia over the long term. Within North America, the rise of low-cost, market-area supply, notably in the proximity of the Marcellus and Utica basins to eastern markets, has altered the geographic structure of supply. Western Canadian gas has been displaced from the eastern markets and is also facing challenges from US imports in Ontario. Prices at the Dawn hub in Ontario are frequently less than the AECO hub plus transportation costs.

Resource Access Access to any resource base is principally determined by three factors. The first is infrastructure, which is a particularly important issue within the northern context. Yukon is better served by road access when compared to some of its northern neighbours. However, any infrastructure needed for future development in remote regions is expensive to develop, and jurisdictions such as Yukon face additional demographic and legislative limitations.

Policy is the second determining factor. The pursuit of policy objectives can result in either limitations or expansion to resource development. How governments, both territorial and federal, respond in their decision making to the varying agendas of different stakeholders has significant implications for resource access.

Finally, regulatory, assessment, planning, and treaty uncertainties can affect resource access. These uncertainties have been ongoing in Yukon for decades, with oil and gas disbursements being affected by factors such as special management areas, habitat protection areas, natural environment parks, and outstanding First Nations land claims. These issues can influence project economics – extending timelines and increasing costs.

March 2015 Economic Impacts of Natural Gas Development 35 Within the Yukon Territory

Environmental and Societal Pressures Broad environmental concerns, natural-gas-specific concerns, and safety concerns all affect natural gas demand. These include climate change and the release of greenhouse gas emissions into the atmosphere. Natural gas has a relatively low carbon footprint compared to oil or coal. Rising air quality problems could also benefit natural gas development. Restrictions on particulates, as well as low-sulfur standards in marine use, could drive a movement towards more natural gas engines for heavy-duty vehicles, for example.

Environmental and social unease specific to natural gas focus on hydraulic fracturing (fracking) and pipelines. Hydraulic fracturing issues are mostly related to the disposal of waste fluids and the risk of groundwater contamination. Above-ground problems include noise, dust, and road deterioration. With the construction of more pipelines comes pipeline failure worries. Some or all of these various matters may affect the development of the natural gas industry in Yukon.

Alberta and British Columbia Alberta and British Columbia natural gas developments compete for access to increased Canadian demand and maintenance of export flows to the United States. British Columbia could reap new and large benefits if LNG terminals are developed. The main reasons for this are the proximity of British Columbia’s Horn River and Montney natural gas plays to the Pacific coast and the announced pipelines connecting the plays to LNG project sites. However, improved pipeline connections between the two provinces could result in an equally competitive playing field for future gas developments. Emerging shale developments in Alberta (Duvernay and others) are proving to be equal to the British Columbia plays in terms of initial production rates and resource size, but the Alberta plays have the added advantage of existing infrastructure (roads, pipelines, and conventional developments) and significant takeaway capacity and connectivity to the Canadian, California, and Illinois market centres. These features offer several market options to the producer by virtue of access to three separate hubs through existing pipelines.

Yukon Territory Figure 3.1 depicts the change in Henry Hub prices for each of CERI’s four natural gas narratives that predict future price trends1 – this represents the possible market conditions that Yukon would be facing if attempting to export gas by pipeline out of the territory and into the North American system.

1 For more information on these narratives, see CERI Study No. 138. http://www.ceri.ca/index.php?option=com_content&view=article&id=55&Itemid=59 Accessed June 26, 2014

March 2015 36 Canadian Energy Research Institute

Figure 3.1: Forecasted Henry Hub Prices (2010$/MMBtu)

Sources: CERI, ICF

Under two of the narratives (Full Speed Ahead and LNG Tsunami), gas prices in Alberta and the border between British Columbia and Yukon (assumed) increase towards the $6 level by 2020. However, both of these narratives are based on increased LNG exports from the continental United States (10 Bcf/d) and the west coast of Canada (5 Bcf/d). This suggests that LNG exports from Yukon would not find ready markets because of an oversupplied Asia-Pacific basin. In addition, while market prices support development drilling south of the 60th parallel, resource development in parts of Yukon would be difficult because of the absence of pipeline connectivity, high cost of drilling in remote areas, and the lack of a service industry. In the Power Wave view of the world, North America is focused on climate change issues, which include the replacement of coal-fired power generation by natural gas and renewable power generating systems. Under this narrative, the window of opportunity may be open for LNG development in the Skagway/Haines area utilizing Yukon-sourced pipeline gas. Under the Nowhere Fast narrative, world economies struggle, and low oil and gas prices close the door on LNG exports from North America, including Yukon.

Diesel vs. Natural Gas Electricity Production A recent study released by Yukon Energy, Mines, and Resources titled Energy for Yukon: The Natural Gas Option, makes two very important points: First, by replacing diesel generation in the Territory with natural gas generation, Yukon could see greenhouse gas emissions from generation drop by as much as 34 percent.2 This is in line with the stated territorial government

2 Energy for Yukon: The Natural Gas Option. “Backgrounder, Summary of Case Study and Next Steps”. Updated November, 2010. Yukon Energy, Mines and Resources. P. 5. [online document] http://emrlibrary.gov.yk.ca/oilandgas/energy_for_yukon_backgrounder.pdf Accessed April 18, 2014

March 2015 Economic Impacts of Natural Gas Development 37 Within the Yukon Territory goal to “reduce GHG emissions by 20 percent by 2015 and become carbon-neutral by 2020”.3 The second is that when comparing the levelized unit electricity cost between diesel and natural gas generation options to mine sites, in all cases natural gas proves to be demonstrably more economical than diesel.4 For example, Figure 3.2 shows the levelized unit electricity costs to supply a typical Yukon 5 MW mine 25 km from the 138 kV grid.

Figure 3.2: Levelized Cost of Electrical Power Delivered to a 5 MW Mine

0.35

0.30

0.25

0.20

0.15

0.10

Delivered Delivered $/kWh powercost, 0.05

0.00 Diesel on-site YEC power supply LNG from Stewart from grid Crossing

Sources: Yukon Energy, Mines, and Resources, 2010; CERI

It appears evident, then, that natural gas is superior to diesel both in terms of emissions and costs. However, the North American economy has a mature diesel energy infrastructure. To build other kinds of energy infrastructure – such as hydroelectricity, small and mid-sized LNG liquefaction plants, and natural gas-fired generation – involves investment and time to establish. The problem is that the largest industrial users in Yukon are mines, and some of these projects require energy for only a few years until they are mined out. At that point, energy suppliers are forced to find other users – presumably new mines – yet commodity prices at that particular time may not be favourable for new mine investment. Therefore, there is a high degree of investment risk for natural gas energy infrastructure projects. Diesel costs may be higher than natural gas costs, but utilizing existing diesel infrastructure offers lower risk, at least over a short-term horizon.

3 Yukon Government Climate Change Action Plan. [online document]. http://www.env.gov.yk.ca/publications- maps/documents/YG_Climate_Change_Action_Plan.pdf Accessed April 18, 2014. 4 Energy for Yukon, “Backgrounder” Pp 12-13.

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March 2015 Economic Impacts of Natural Gas Development 39 Within the Yukon Territory Chapter 4 Methodology and Scenarios

Two pipeline scenarios are explored in this study. The first is a small-diameter pipeline built to carry natural gas from Eagle Plain to Stewart Crossing; at Stewart Crossing, electrical generation and LNG liquefaction would take place, and from Stewart Crossing a lateral pipeline would be constructed to take the remaining gas to the Casino mine. The second scenario would add gas from Peel Plateau & Plain and build a larger diameter pipeline from Eagle Plain to Stewart Crossing to the Canada/US border north of Haines, AK. Sufficient gas would be transported under this scenario to feed a small, one-train LNG liquefaction facility in Haines. As with the first scenario, some gas would be diverted at Stewart Crossing. In order to model these scenarios, the following assumptions were made:

 The entire area of the Eagle Plain basin, which measures just over 5,000,000 acres, is considered in this study. The entire area of the Peel Plateau & Plain basin, approximately 3,500,000 acres, is also considered in this study.  Eagle Plain basin’s mean gas-in-place estimate of 3.4 Tcf is located within the area available for development. Peel Plateau & Plain’s mean gas-in-place estimate of 2.9 Tcf is located within the area available for development.  60 percent of the mean gas-in-place is recoverable using conventional extraction methods. Recovery by means of hydraulic fracturing is not considered in this report.  73 percent of Eagle Plain is available for development in 2014; 36 percent of Peel Plateau & Plain is available. The areas neither shrink nor grow over the course of the study period.  Each basin is developed with vertical wells only, each drilled to 2,800 metres. There is a 100 percent drilling success rate.  The produced gas is dry, not requiring additional processing.  A typical production curve from northeast British Columbia is used as a proxy for the estimated production profile for both basins.  Each well has an IP rate of 2.8 MMcf/d. This rate was arrived at through comparing the limited available Yukon drilling data with more comprehensive Northeast British Columbia drilling data.1  Production simulations are run for each pipeline scenario, with the results entered into an I/O model; this model is used to determine the possible economic impacts of developing the Eagle Plain and Peel Plateau & Plain.

1 The drilling data from Yukon suggests higher IP rates in some cases. A higher IP rate would likely increase the economic benefits of natural gas production.

March 2015 40 Canadian Energy Research Institute

Assumptions for the Input/Output (I/O) Model Operating and capital costs were calculated and injected into CERI’s UCM Regional I/O 3.0 model in order to estimate GDP, employment, and taxation over the period 2017-2041. For operating expenditures, it is assumed that the majority of spending occurs in Yukon where the sites and facilities would be located. For capital expenditures, it is assumed that the majority of spending would occur in the mature, oil-and-gas-focused Alberta economy, with the much smaller Yukon economy receiving less.

Capital Costs Drilling: These costs are calculated by taking the well costs multiplied by the number of wells per year. Then a 25 percent premium is added for remote area construction. Finally, C$1.2 million per well in gathering costs is assumed.

Pipeline: For Scenario 1, these costs are the total capital expenditure for the mainline and the Casino lateral, as expressed in Table 4.2. For Scenario 2, pipeline costs equal the total capital expenditure for the export pipeline (Table 4.7) plus the Peel Plateau & Plain pipeline (Table 4.8), and the Casino Lateral, as noted in Table 4.2.

Tankage: Tankage capital expenditure is assumed to be C$12.3 million for both scenarios.

LNG: LNG facility capital expenditure is expected to cost C$100 million (Table 4.1) for both scenarios.

Operating Costs Drilling: A C$203,000 per well operating cost is assumed, based on data from British Columbia drilling under similar conditions. That cost is inflated by 1.25 (or an incremental 25 percent) to reflect remote operations cost inflation. This comes to a total of C$253,750 per well.

Pipeline: 1.5 percent of pipeline capital costs are assumed as yearly pipeline operating costs.

Tankage: 2.5 percent of tankage capital costs are assumed as yearly tankage operating costs.

LNG: 2.5 percent of LNG capital costs are assumed as yearly LNG operating costs.

Capital Injections Drilling: The Petroleum Services Association of Canada (PSAC) Winter 2013 Well Cost Study2 was consulted. The BC well BC2B found to serve as a reasonable proxy to expected well characteristics in Yukon. Various activities undertaken in Yukon related to drilling capital costs were considered. These add up to C$668,000 on a C$3.6 million well, or 18 percent. Thus, 18 percent of drilling-related injections are allocated to Yukon and 82 percent to Alberta.

2 2013 Well Cost Study: Upcoming Winter Costs, Published October 30, 2013.

March 2015 Economic Impacts of Natural Gas Development 41 Within the Yukon Territory

Pipeline: For pipelines, it is assumed that 60 percent of capital is allocated to construction and 25 percent of this is labour in Yukon. Multiplying these two percentages leads to an assumed 15 percent of all pipeline activity undertaken within Yukon and 85 percent in Alberta.

Tankage: The 15:85 ratio established for pipeline injections is also used for tankage.

LNG: The 15:85 ratio established for pipeline injections and tankage is also used for LNG.

In terms of operating injections, Yukon receives a higher percentage than it does for capital injections. The assumption here is that there will be significant local employment and ongoing spending in the Yukon economy. Much of the capital spending, on the other hand, will take place outside of Yukon, where pipe, pumps, valves, and other engineered components will be sourced; construction crews will come to the territory on an as-needed basis, complete their work, and then return to Alberta where there is more regular activity. All capital spending outside of Yukon is assumed to occur in Alberta.

Operating Injections Seventy-five percent of operational costs are assumed to be incurred in Yukon and the remaining 25 percent in Alberta. This 75:25 ratio holds for drilling, pipelines, tankage, and LNG. Local labour for tasks such as maintenance and repair are assumed to be sourced in Yukon while more specialized operational expertise is sourced from Alberta.

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Scenario 1 – Domestic Pipeline: Eagle Plain to Stewart Crossing

Figure 4.1: Scenario 1 Route Map

Sources: Energy, Mines & Resources, Yukon Government

March 2015 Economic Impacts of Natural Gas Development 43 Within the Yukon Territory

Within the Eagle Plain basin are several active oil and gas leases in lands that have not been withdrawn from oil and gas disposition, and the basin holds an estimated 3.4 Tcf of potential gas reserves. As is the case with all of Yukon’s basins, Eagle Plain’s estimated gas-in-place is not a final number, but there has been more work done in this basin than in most of the others. According to a 2012 report commissioned for the Government of Yukon: “Active petroleum systems in the Eagle Plain basin are evident in the presence of surface seeps, oil and bitumen staining, and oil and gas recoveries from wells”.3 The authors note that numerous wells were drilled in the 1970s and 1980s and conclude that the Eagle Plain “be given the highest priority in future geoscientific work”.4 The conventional gas deposit estimations may not be known for certain until further exploration is undertaken.

The Eagle Plain basin meets the 138 kV grid at Stewart Crossing, a northerly settlement that was connected to the WAF grid and the 69 kV Mayo-Dawson (MD) grid in 2011. The distance between Eagle Plain and Stewart Crossing is approximately 500 km. It has been assumed, to meet the territory’s domestic needs only, a 12” diameter natural gas pipe should be built. At Stewart Crossing, a new 50 MW gas-fired power generating system could be constructed, with output being fed into the 138 kV WAF grid. A 12.5 MMcf capacity liquefaction facility would also be built at Stewart Crossing. The generating system could provide extra power to the grid as general needs increase, and it could also serve future mines situated on or near the grid. The liquefaction facility would become a hub for LNG to be trucked throughout Yukon and possibly into northern British Columbia as well. Estimated costs in 2014 dollars for these facilities are shown in Table 4.1.5

Table 4.1: New-Build LNG Liquefaction and Gas-fired Power Generation Facilities Costs

LNG Plant Electrical Power

12.5 MMcf 12.5 MMcf 50 MW 50 MW 2.8 $million/MMcf 1.3 $million/MW 35 $million 65 $million

Sources: Energy for Yukon: The Natural Gas Option, 2010; CERI

To show what this new generation would mean for Yukon, see Figure 4.2. Potential gas-fired generation and LNG liquefaction facilities at Stewart Crossing, fed with natural gas from Eagle Plain, would represent as much potential power capacity as all of the Territory’s hydropower

3 Petrel Robertson Consulting, Ltd. (2012). “Scoping study of unconventional oil and gas potential, Yukon.” Yukon Geological Survey Miscellaneous Report 7. Pp. 41. http://ygsftp.gov.yk.ca/publications/miscellaneous/Reports/YGS_MR-7.pdf Accessed June 24, 2014. 4 Ibid pp. 88-89. 5 These calculations are in $CDN 2014 based on data from the 2010 Eagle Plain Case Study, adjusted for inflation.

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resources combined. Eagle Plain gas could well serve the Yukon’s needs as the Territory grows since it is cheaper to develop than new large-scale hydro, is less GHG-intensive than diesel, and more reliable than intermittent wind. However, if the capacity of the plants are in excess of demand the cost of the surplus capacity would reduce their economic viability. This study does not include an assessment of the impact of excess capacity on the viability of an LNG plant or natural gas to electricity generator.

Figure 4.2: Yukon Present and Potential Power Capacity (MW)

120

100 Fish Lake 80 37 LNG 50 Aishihik Potential 60

15 Mayo Electrical 40 Power Potential Whitehorse 54 50 20 40

0.8 0 Hydropower Diesel Wind Eagle Plain Gas Potential

Sources: Government of Yukon; CERI

A lateral pipeline taking the remaining 25 MMcf/d of the produced Eagle Plain natural gas could also be built to reach the Casino gold and copper mine project, south and west of Stewart Crossing. This gas would fuel the large, 100 MW natural gas-powered generators that would be required for mining operations at this project.

The pipeline option is a feasible way to deliver gas to a large mine like Casino. In terms of levelized unit costs, pipelines can deliver gas far more cheaply than diesel delivered by truck (less than half the cost) and even less than LNG by truck, as was stated in the 2010 Energy for Yukon report (see Figure 4.3).

March 2015 Economic Impacts of Natural Gas Development 45 Within the Yukon Territory

Figure 4.3: Levelized Cost of Electrical Power Delivered to the Casino Mine

$0.35

$0.30 Diesel on-site $0.25 LNG from Eagle Plains

$0.20 LNG from Stewart Crossing hub

Two pipeline options YEC gas generation at Stewart $0.15 Crossing Natural gas from Stewart Crossing $0.10 hub AHPP YEC gas generation at Whitehorse $0.05

$0.00 Delivered power cost,1 $/kWh ($2014)

Note: Assumes no surplus capacity costs. Sources: Energy for Yukon: The Natural Gas Option, 2010; CERI

However, the versatility of LNG by truck makes it a logical choice for smaller, more remote mine sites away from established pipeline or electricity infrastructure. Potential sites that could be serviced by trucked LNG include the Wolverine project (180 km from grid; 8 MW peak electrical demand) and Eagle Gold (45 km from grid; 13 MW peak demand). Other mines located along the Eastern border with the Northwest Territories (Mactung, Selwyn) and more likely to be developed further into the future, would also be ideal candidates for LNG by truck.

If a pipeline were not built to Casino, the mine could operate reasonably efficiently using trucked LNG originating from within Yukon. In fact, if a pipeline were not built, the cost difference to truck in natural gas would not amount to more than a few cents per kWh – as Figure 4.3 shows. Beyond cost effectiveness, there are other advantages to transporting gas by pipeline. Pipelines are generally considered the safest way to transport gas and other hydrocarbons. One pipeline would also eliminate many moving parts: no trucks to break down, less wear and tear on roads,6 and reduced labour requirements.

6 In the 2010 Eagle Plain Case Study, the authors estimate that 200 MW of generation capacity would necessitate a fleet of between 95 to 100 trucks on the road every day. To supply fully a mine the size of Casino would require more than 50 trucks per day, causing significant traffic and associated road maintenance issues. Smaller mines of approximately 5 MW would need 1 or 2 LNG truck shipments per day.

March 2015 46 Canadian Energy Research Institute

Unit cost for the Casino lateral would be higher than that of the mainline because the lateral would not follow established transportation corridors. The estimated costs of such a project, with mainline and lateral pipelines, calculated in the 2010 Energy for Yukon study, have been updated for this report and are shown in Table 4.2.7

Table 4.2: Pipeline Costs for Domestic Pipelines Eagle Plain to Stewart Crossing Mainline Casino Lateral

Delivered Gas (MMcf/d) 50.0 25.0 Distance (km) 504 125 Diameter (inches) 12.0 10.0 Unit Cost ($/dia-inch-km) 90,000 100,000 Capital Cost ($000s) 544,320 125,000 Cost of Service Factor (%) 13.77 13.77 Annual Cost of Service ($000/y) 74,953 17,212 Toll at 100% Load Factor ($/Mcf) 3.95 1.89 Eagle Plain to Stewart Crossing ($/Mcf) 3.95 Eagle Plain to Casino ($/Mcf) 5.84 Sources: Energy for Yukon: The Natural Gas Option, 2010; CERI

Table 4.3 breaks down the lifespan of the Eagle Plain basin, assuming the 12” pipeline is built, there are no new discoveries of conventional natural gas, and shale gas is not developed.

Table 4.3: Eagle Plain Basin Characteristics Eagle Plain Basin - 2.04 Tcf Basin Area 5,140,815 Acres Basin Area 8,032 Sections Available Basin Area 5,863 Sections Mean Gas-in-place 3.4 Trillion cubic feet Recoverable Gas 2.04 Trillion cubic feet Accessible Gas8 1.49 Trillion cubic feet Daily Production 51.5 Million cubic feet Yearly Production 18.8 Bcf Lifespan of Basin if 2.04 TCF 79.2 Years Source: Government of Yukon, CERI

7 These costs are based on analysis done for the November 2010 study “Energy for Yukon: The Natural Gas Option” released by the Yukon Department of Energy, Mines, and Resources. Unit costs have been adjusted to reflect 2014 industry estimates. 8 “Accessible gas” is calculated by multiplying the amount of recoverable gas in a particular basin by the %age of the basin that is accessible in 2014.

March 2015 Economic Impacts of Natural Gas Development 47 Within the Yukon Territory

Assuming 60 percent of the 3.4 Tcf estimated mean gas-in-place is recoverable and that the resource lies within the 73 percent of the basin that is accessible in 2014, the Eagle Plain could be productive for almost 80 years. The Casino Mine production life span is estimated to be about 25 years, so it follows that Eagle Plain could comfortably provide gas for Casino until it winds up, while simultaneously supplying gas for power generation and LNG production. A key uncertainty is the demand for natural gas once the mine closes assuming that Yukon infrastructure is not connected to the rest of North America.

It is important to note that the above calculations are based on an unchanging Eagle Plain basin. In reality, when new basins are developed, it spurs further exploration. More activity to find and exploit conventional gas resources could be expected as well as efforts to investigate the region’s shale gas potential. A developing Eagle Plain basin would be exploited by exploration and production companies to extract all economically feasible volumes of natural gas; the basin’s lifespan could be reasonably expected to increase significantly.

With Eagle Plain producing 51.5 MMcf/d, Figure 4.4 shows the number of new wells to be drilled per year to sustain that flow to 2037 and beyond. Each well has been assumed to be a vertical well, so there would be no horizontal fracturing involved. Also assumed is a processing loss factor of 3 percent, and a minimum sales gas output of 50 MMcf/d. These assumptions are based on wells drilled in similar structure in similar conditions in northeast British Columbia. To build up to 50 MMcf/d by the third year, presumed to be 2017 in this example, an initial 7 wells would be built in 2015 and 2016, with 10 being built in 2017; each well would be capped until pipeline construction is complete and flow can begin in the third year of well construction.

Figure 4.4: Eagle Plain Well Requirements for 50 MMcf/d Natural Gas Production 20 100 18 90 16 80 14 70 12 10 60 10 50 7 7 8 6 40 5 5 5 5 5 5 6 4 4 4 4 4 4 4 4 30 3 3 3

Well Count Well 4 20

2 10 Production Volume (MMcf/day) Volume Production 0 0

New Wells Production Volume

Source: CERI

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This presumes that each of the wells will have an initial production (IP) rate of 2.2 MMcf/d and decline according to the hyperbolic curve shown in Figure 4.5.

The historical average for IP rates in blocks, 094 M,N,O & P in northeast British Columbia is 1.1 MMcf/d. This average is based on actual rates from drilled wells. Historical flow rates in the Eagle Plain basin are approximately 5.0 MMcf, however, these data are based on a very small sample size of eleven test wells, (compiled by Fekete,9) and the flows vary from .5 MMcf/d to 10 MMcf/d. For the purposes of this study, a rate of 2.8 MMcf/d is assumed, a conservative estimate that acknowledges flow rates may be greater in a basin 800 km north of British Columbia but are unlikely to be 450% greater. The decline curve below represents the average decline among the BC wells with the assumption the decline curves for all Yukon wells would be the same.

Figure 4.5: Assumed Production Decline Curve

3.00

2.50

2.00

1.50

1.00 Production Rate (mmcf/d) Rate Production 0.50

0.00

1

15 29 43 57 71 85 99

127 337 113 141 155 169 183 197 211 225 239 253 267 281 295 309 323 351 Month

Sources: CERI, PSAC

9 Fekete and Associates. 2005. “North Yukon Conceptual Oil and Gas Development Scenario and Local Benefits Assessment.” Pp 29, 39.

March 2015 Economic Impacts of Natural Gas Development 49 Within the Yukon Territory

Because there has been little exploration or production activity in the Eagle Plain region for over 30 years, there is no available field cost data to help estimate costs for future development. Therefore, well cost data for a vertical well drilled, cased, and completed in the Fort Nelson Region of northeast British Columbia has been used as a proxy.10 This area was chosen for its geological and climatic features, similar to those in Yukon. The well characteristics and costs are shown in Table 4.4.

Table 4.4: Well Cost Assumptions Fort Nelson Vertical. NE BC 94-J-11 Type of Well Gas Vertical/Horizontal/Directional Vertical Total Vertical Depth 2800 metres

Total Days Rig-in to Tear-out 27 days Rig Type/Size Triple Rig Loads 30 Camp Required? Yes Number of Persons in Camp 40

Total D & A Estimate $2,919,634 Total Drill & Case Estimate $3,123,370 Total Casing and Completion Estimate $668,836 Total Drill, Case, and Complete Estimate $3,589,570 3,589,570 * 1.25 (Northern Operations $4,486,962 Premium) Source: CERI; PSAC

10 Petroleum Services Association of Canada (PSAC). 2013 Well Cost Study: Upcoming Winter Costs. “BC2B. Ft. Nelson Vertical NE BC 94-J-11. Well Cost Estimate.” 22-27. Published November 6, 2012.

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Economic Impacts for Scenario 1

Table 4.5: Economic Impacts of Yukon Natural Gas Development, Scenario 1 – 2017-2041 $CAD Million Thousand Investments and Person Years Operations Output GDP Compensation Employment of Employees Alberta 14,676 8,417 4,071 45 British Columbia 549 298 186 3 Manitoba 99 48 28 0 New Brunswick 30 13 7 0 Newfoundland & Labrador 12 7 3 0 Northwest Territories 8 4 3 0 Nova Scotia 23 12 7 0 Nunavut 2 1 1 0 Ontario 1,116 574 349 4 Prince Edward Island 2 1 1 0 Quebec 369 183 104 2 Saskatchewan 148 73 32 1 Yukon Territory 1,498 875 349 6 Gabd* 0 0 0 0 Total Canada 18,531 10,506 5,140 62 *Gabd = Canadian government abroad (embassies, consulates, etc.) Source: CERI

Figure 4.6: Jobs (x 1,000) Created and Preserved in Canada as a Result of Yukon Natural Gas Development, Scenario 1 – 2017-2041

6

5

4

Induced 3 Indirect 2 Direct

1

0

Source: CERI

March 2015 Economic Impacts of Natural Gas Development 51 Within the Yukon Territory

Table 4.6: Federal, Provincial, and Municipal Tax Receipts as a Result of Yukon Natural Gas Development, Scenario 1 – 2017-2041 ($CAD millions) Investments and Indirect Personal Income Corporate Sum Operations Tax Tax Tax Alberta 384 884 450 1,718 British Columbia 20 29 8 57 Manitoba 4 5 1 10 New Brunswick 1 1 0 2 Newfoundland & Labrador 0 1 0 1 Northwest Territories 0 0 0 1 Nova Scotia 1 1 0 2 Nunavut 0 0 0 0 Ontario 47 65 16 128 Prince Edward Island 0 0 0 0 Quebec 15 23 6 44 Saskatchewan 5 6 3 13 Yukon Territory 27 62 12 101 Total Canada 504 1,078 496 2,078 Source: CERI

The Government of Yukon collects royalties on natural gas production based on an “ad valorem” or “according to the value” basis. Payable royalty is calculated by assessing the market value of the gas and the costs associated with production. In the case of the wells in Scenario 1, the Initial Production royalty rate is 2.5% to a threshold of 2 GJ (1876.8 MMcf). Once production rises above the threshold, the royalty rate increases to 20.3%. Under Scenario 1, all gas will be produced and consumed within the territory, so it will not be subject to market prices. We assume a Yukon domestic natural gas price of $8.27/MMcf for the duration of Scenario 1, which leads to the following results:

Table 4.7: Total Natural Gas Volume, Value and Royalty as a Result of Yukon Natural Gas Development, Scenario 1, 2017-2041 Sales Gas Volume 467.4 Bcf Sales Gas Value $3.87 billion Royalty $452.9 million

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Scenario 2 – Domestic and Export Pipeline: Peel Plateau & Plain + Eagle Plain to US Border Figure 4.7: Scenario 2 Route Map

Sources: Energy, Mines & Resources, Yukon Government

March 2015 Economic Impacts of Natural Gas Development 53 Within the Yukon Territory

Building a large diameter transportation pipeline to serve the needs of Yukon and to send gas to Alaska for export would be a significantly bigger project than the domestic pipeline outlined in Figure 4.1. For the second scenario, a 24” pipeline would be required and constructed. As with the first scenario, domestic needs at Stewart Crossing and Casino mine would be met first before remaining gas is sent on to Haines, Alaska (see Figure 4.7). In order to sustain the larger volumes for over 20 years, however, Eagle Plain gas would not be enough. Therefore, we have added 50 MMcf/d of natural gas from Peel Plateau & Plain to the increased Eagle Plain production. Volumes and costs have been calculated to supply natural gas to a small, one-train LNG gasification facility that would be approximately the same size as the Douglas Channel LNG. This analysis does not include any pipeline built beyond the Canadian border, nor does it include the construction of an LNG liquefaction facility at Haines.

The main, large diameter pipeline route would run along the Dempster Highway to the Stewart Crossing corridor, where 25 MMcf/d would be diverted to feed the electrical power station and LNG liquefaction plant, and 25 MMcf/d would move via a lateral pipeline to the Casino mine. The main transmission line would continue south through Whitehorse and parallel the highway to the US border, north of Skagway and Haines, Alaska.11 The total distance of the transportation pipeline would be beyond 900 km.

Table 4.8 shows a cost summary for the large diameter mainline transporting gas from Eagle Plain to the US border. Because this pipeline would run along an established transportation corridor (the Dempster Highway route), unit costs are lower than for a pipeline along a new route.

Table 4.8: Pipeline Costs for Export Pipeline

Eagle Plain to US Border Delivered Gas (MMcf/d) 237.4 Distance (km) 916 Diameter (inches) 24 Unit Cost ($/dia-inch-km) 90,000 Capital Cost ($000s) 1,978,560 Cost of Service Factor (%) 13.77 Annual Cost of Service ($000s/y) 272.4 Toll at 100% Load Factor ($/Mcf) 2.99 Eagle Plain to US Border ($/Mcf) 2.99

Source: Energy for Yukon: The Natural Gas Option, CERI.

Peel Plateau & Plain shows promise if it is developed after or at the same time as Eagle Plain. Peel Plateau & Plain is geographically close to Eagle Plain and the Dempster Highway corridor, and because it offers almost 3 Tcf in mean gas-in-place, with 36 percent of the basin open, it

11 Though Skagway, another port town in Alaska, is closer to the Canadian border than Haines, the port at Haines is more suitable for large container traffic; Skagway is located at the end of the long and narrow Taiya Inlet, whereas Haines is more easily accessed via the Lynn Canal.

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holds more potential to produce over the coming decades than other basins. Peel Plateau & Plain has certain advantages: geographical proximity to Eagle Plain, sufficient quantities of natural gas, and a reasonable amount of accessible land.

Transporting the natural gas to Eagle Plain would require a pipeline of approximately 90 km in length, opening a new corridor across hilly terrain. Similar to the Casino lateral, the unit cost for the Peel Plateau & Plain to Eagle Plain pipeline would be higher than for the mainline because of the high costs involved to develop the new corridor. The estimated costs are shown in Table 4.9.

Table 4.9: Pipeline Costs for Peel Plateau & Plain to Eagle Plain Pipeline

Peel Plateau & Plain to Eagle Plain Delivered Gas (MMcf/d) 50 Distance (km) 93 Diameter (inches) 12 Unit Cost ($/dia-inch-km) 100,000 Capital Cost ($000s) 111,600 Cost of Service Factor (%) 13.77 Annual Cost of Service ($000s/y) 15.37 Toll at 100% Load Factor ($/Mcf) .82 Source: Energy for Yukon: The Natural Gas Option, CERI.

Table 4.10 estimates the lifespan of the Peel Plateau & Plain basin, with a 51.5 MMcf/d production rate and a 12” pipeline. As with the Eagle Plain, it is assumed that there will be no new discoveries of either conventional or unconventional natural gas resources in Peel Plateau & Plain.

Table 4.10: Peel Plateau & Plain Basin Characteristics

Peel Plateau & Plain 1.75 Tcf Basin Area 3,552,369 Acres Basin Area 5,551 Sections Available Basin Area 1,998 Sections Mean Gas-in-place 2.92 Trillion cubic feet Recoverable Gas 1.75 Trillion cubic feet Accessible Gas .629 Trillion cubic feet Daily Production 51.5 Million cubic feet Yearly Production 18.8 Bcf Lifespan of Basin if 1.75 TCF 33.5 Years Source: Government of Yukon, CERI.

March 2015 Economic Impacts of Natural Gas Development 55 Within the Yukon Territory

Adding the 50 MMcf/d natural gas volume from the Peel Plateau & Plain to the Eagle basin would permit natural gas to flow south to the border and on to the proposed LNG plant in Haines for a longer period of time. Without the Peel Plateau & Plain gas, Eagle Plain on its own could provide gas to Stewart Crossing and Haines for approximately 17 years; with the Peel Plateau & Plain gas, Stewart Crossing and Haines could be supplied for 24 years. Again, this presupposes no more production in these or other basins. In reality, production generally spurs more exploration and production, which would in all likelihood extend the supply for a number of years further. Table 4.11 provides estimates of production and lifespan if natural gas infrastructure were developed in both basins.

Table 4.11: Peel Plateau + Eagle Plain Basin Characteristics

Peel Plateau & Plain + Eagle Plain 3.79 Tcf Basin Area 8,693,185 Acres Basin Area 13,583 Sections Available Basin Area 7,862 Sections Mean Gas-in-place 6.32 Tcf Recoverable Gas 3.79 Tcf Accessible Gas 2.12 Tcf Daily Production 237.4 MMcf Yearly Production 88.9 Bcf Lifespan of Basin if 3.79 Tcf 23.8 Years Source: Government of Yukon, CERI.

Assuming the two fields together could support production of 237.4 MMcf/d, Figure 4.8 indicates the number of new wells that would be required to sustain that flow over the years ahead. Again, each well is assumed to be a vertical well with a processing loss factor of 3; all wells will produce a minimum specified sales gas output of 237.4 MMcf/d. To build up to a sustained flow of 237.5 MMcf/d by 2017, an initial 32 wells would be built in both 2015 and 2016, with construction peaking at 48 wells in 2017.

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Figure 4.8: Peel Plateau + Eagle Plain Well Requirements for 237.4 MMcf/d Natural Gas Production 60 300 48 50 250

40 200 32 32 30 27 150 23 24 21 22 22 21 20 20 19 20 20 20 20 16 16 16 16 16 100

Well Count Well 10 50 Production Volume (MMcf/day) Volume Production 0 0

New Wells Production Volume

Source: CERI

March 2015 Economic Impacts of Natural Gas Development 57 Within the Yukon Territory

Economic Impacts for Scenario 2

Table 4.12: Economic Impacts of Yukon Natural Gas Development, Scenario 2 – 2017-2041 $CAD Million Thousand Investments and Person Years Operations Output GDP Compensation Employment of Employees Alberta 45,667 26,337 12,595 140 British Columbia 1,687 917 571 9 Manitoba 306 149 86 2 New Brunswick 91 41 23 0 Newfoundland & Labrador 38 21 10 0 Northwest Territories 24 12 8 0 Nova Scotia 71 35 22 0 Nunavut 5 3 2 0 Ontario 3,449 1,774 1,080 14 Prince Edward Island 6 3 2 0 Quebec 1,137 563 320 5 Saskatchewan 454 223 99 2 Yukon Territory 4,598 2,712 1,069 19 Gabd* 0 0 0 0 Total Canada 57,533 32,791 15,887 191 *Gabd = Canadian government abroad (embassies, consulates, etc.) Source: CERI

Figure 4.9: Jobs (x 1,000) Created and Preserved in Canada as a Result of Yukon Natural Gas Development, Scenario 2 – 2017-2041

16

14

12

10 Induced 8 Indirect 6 Direct 4

2

0

Source: CERI

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Table 4.13: Tax Receipts from Yukon Natural Gas Development Scenario 2 – 2017-2041 ($CAD millions) Investments and Indirect Personal Income Corporate Sum Operations Tax Tax Tax Alberta 1,208 2,766 1,408 5,382 British Columbia 63 88 25 176 Manitoba 11 16 3 30 New Brunswick 2 4 1 8 Newfoundland & Labrador 1 2 1 4 Northwest Territories 1 1 0 2 Nova Scotia 2 4 1 7 Nunavut 0 0 0 0 Ontario 146 201 49 396 Prince Edward Island 0 0 0 1 Quebec 47 71 17 136 Saskatchewan 15 18 8 41 Yukon Territory 84 193 36 314

Total Canada 1,581 3,365 1,551 6,497 Source: CERI

As mentioned in Chapter 4, the Government of Yukon collects royalties on natural gas production based on an “ad valorem” basis. In the case of the wells in Scenario 2, the Initial Production royalty rate is 2.5% to a threshold of 2 GJ (1876.8 MMcf). Once production rises above the threshold, the royalty rate increases to 20.3%. Unlike Scenario 1, where all gas is produced and consumed within the territory, a portion of the production under Scenario 2 is available for export, subjecting Yukon to market prices. We assume a natural gas price of $6.20/MMcf for the duration of Scenario 2, resulting in the following:

Table 4.14: Total Natural Gas Volume, Value and Royalty as a Result of Yukon Natural Gas Development, Scenario 2, 2017-2041 Scenario 2 Sales Gas Volume 2.18 Tcf Sales Gas Value $13.53 billion Royalty $1.36 billion

March 2015 Economic Impacts of Natural Gas Development 59 Within the Yukon Territory Chapter 5 Key Findings and Concluding Remarks

There is at present no noteworthy oil and gas service industry in Yukon, which means that drilling and other cost over-runs could occur as the industry develops, and the companies that eventually work in the Territory will not realize economies of scale achieved in less remote North American regions. In terms of costs, this study assumes that the cost of wells drilled will equal the cost of field development – exploratory wells are not included in the calculus. The proxy well that has been used to determine those costs is located within a comparably remote area of British Columbia with similar geological characteristics to those found in both the Eagle Plain and Peel Plateau & Plain basins; it is therefore presumed to reflect future Yukon well costs with the addition of a 25 percent premium.

It is important to reiterate that the resource under study here is a conventional gas resource. The wells to be drilled will be vertical wells, not horizontal, and will not likely be extracting any of the resource from shale formations. The costs, then, will be considerably lower than those of shale gas producing areas. Each well will cost somewhere within the range of C$4 and C$5 million.

Key Findings The GDP, taxation, and employment projections stated below reflect the results of operating and capital expenditures injected into the CERI I/O model. These are lower-bound economic impact estimates, reflecting a Yukon oil and gas sector that is at an embryonic stage. As the sector grows, infrastructure is built, and economic linkages to other sectors and provinces materialize. GDP, taxation, and employment are all expected to increase – but calculating the degree of that increase is outside the scope of the model and of this study. The results stated in Table 5.1 are therefore conservative estimates (unless stated otherwise, all currency amounts are in 2013 Canadian dollars).

Table 5.1: GDP, Taxation and Employment Projections ($CDN 2013) Economic Impact Scenario 1 Scenario 2 2017-2041 Canada Yukon Canada Yukon Total Capital Investment ($mil) $1,580 $259 $4,661 $762 Total Operating Investment ($mil) $8,178 $525 $22,992 $1,914 GDP from Investment and $10,506 $875 $32,791 $2,712 Operations ($mil) GDP from Investment ($mil) $1,850 $183 $5,689 $566 GDP from Operations ($mil) $8,655 $692 $27,102 $2,146 Taxes Collected ($mil) $2,077 $101 $6,497 $314 Employment (person years) 62,000 6,000 191,000 19,000 Source: CERI

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Yukon is home to considerable oil and gas resources, and as Table 5.1 shows, the gas resource alone can provide significant economic benefits to the territory and the country. Over its recent history, the territory has witnessed brief periods of hydrocarbon exploration and development, but the petroleum industry has so far failed to take hold. Some of the challenges to exploration and production include land usage restrictions, infrastructure deficits, and a northern climate inhospitable to industrial activity. However, technological advances and environmental imperatives are causing government, business, and the general population to take a close look at the advantages oil and gas could bring.

Yukon’s continued reliance on diesel will create ongoing negative environmental and economic impacts. The Government of Yukon has been taking measures to replace diesel generators with natural gas or LNG units, to add wind, solar, and geothermal resources to the energy mix, and to upgrade the territory’s grid. Alternatives to diesel are also being considered by the private sector. Western Copper & Gold Corporation envisions a Casino mine operation run by natural gas-fired electricity, even if the gas has to be sourced as far south as the Greater Vancouver area and brought into Yukon in the form of trucked LNG. For the first time in the history of the North, a cleaner hydrocarbon is competing economically with diesel and emerging a clear winner.

Scenario 1 in this report considers a homegrown, conventional natural gas industry in Yukon. Gas is found in Yukon, extracted in Yukon, transported wholly within Yukon, and used only in Yukon. Under Scenario 1, natural gas would drive initial development of the mining sector in Yukon, bringing environmental and economic benefits. CERI’s economic analysis concludes that this scenario would grow Yukon GDP by $875 million over the study period, increase tax revenues by $101 million, and provide 6,000 person years of employment.

Scenario 2, which links the territory to North American and world natural gas markets by way of a pipeline to the Alaska border, offers more economic benefits to Yukon. It also provides the potential for reducing financial risk, particularly for infrastructure development, through the diversification of markets. Instead of an isolated market, for the most part serving mineral producers, operators would gain access to the wider world. Scenario 2 presents other risks, however. This scenario involves exposure to price volatility associated with potential supply overabundance and an ever-changing market structure in North America and abroad. Scenario 2 would see Yukon GDP grow to unprecedented levels: $2.7 billion. Tax revenues in the territory would exceed $314 million. Employment would jump as infrastructure is built with permanent operational jobs created and maintained for decades to come.

In either scenario, natural gas development would take place in a context of regulatory and policy requirements developed to meet First Nations concerns as well as environmental and social objectives. Central to success will be the ability to meet these objectives in an economically feasible way. Inevitably, the outlook for natural gas to benefit Yukon will depend on the readiness and capacity for development.

Basin availability, land access, and increased geological knowledge are precursors to development of the natural gas resource and associated infrastructure. Challenges remain to

March 2015 Economic Impacts of Natural Gas Development 61 Within the Yukon Territory natural gas development in Yukon but significant economic and environmental benefits can be realized if that development takes place.

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March 2015 Economic Impacts of Natural Gas Development 63 Within the Yukon Territory Appendix A A Note on the Liard, Old Crow, Beaufort- Mackenzie, Bonnet Plume and Kandik Oil and Gas Basins Liard Basin At the time of writing, most basins in the Yukon – Old Crow, Beaufort-Mackenzie, Bonnet Plume, and Kandik – are either not prospective for gas or are not available for development. The Liard basin, however, shows considerable promise for natural gas. And though Liard is presently almost completely unavailable for hydrocarbon development, there are no long-term regulatory or policy constraints on the basin. There has been drilling and production out of Liard’s Kotaneelee field in the past, so there is some infrastructure already set up in the basin. Therefore it is realistic to assume that some of the Liard basin could be unencumbered over the coming few years; there is no insoluble issue standing in the way of an open basin. With a mean gas-in-place of 4.6 Tcf, Liard is estimated to hold more conventional natural gas than any of the other Yukon basins, including Eagle Plain.

The Yukon portion of the Liard basin is located in the southeast, bordering British Columbia and the Northwest Territories. The basin is contiguous, stretching into northeastern British Columbia and southwestern Northwest Territories. The Yukon portion covers 6,500 km2. The Mackenzie and Franklin Mountains rise to the north of the Liard basin while the Rocky Mountains are located to the south.

Figure A.1 shows the entire Liard basin. To the east lies the Alberta basin, to the west the Rocky Mountains. To the northwest is Nahanni National Park, and to the northeast lies the Great Slave Plain. Directly north of the Liard basin are the Mackenzie Mountains and the Franklin Mountains. Most exploration and production activity is in the British Columbia portion of the basin.

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Figure A.1: Map of Liard Basin Exploration Region

March 2015 Economic Impacts of Natural Gas Development 65 Within the Yukon Territory

The age of rocks date from the Cambrian to the Cretaceous and the target zone ranges from a depth of 700 meters to 4,500 meters.1 Figure A.2 illustrates a schematic of the geology of the Liard basin and the neighbouring Horn River basin, from west to east across the Bovie fault.

Figure A.2: Schematic of the Geology of the Liard Basin and the Horn River Basin

Source: Fraser, T., et al 2

Assuming that Liard would come on line after the Eagle Plain and Peel Plateau & Plain are developed, the gas from Liard would almost certainly be added to the amount available for export. If gas from Liard would enable another small train to be built at Haines – a train the same size as the one constructed at Douglas Channel LNG – the basin characteristics would be as shown in Table A.1.

Table A.1: Liard Basin Characteristics

Liard Basin .063 Tcf Basin Area 1,518,444 Acres Basin Area 2,373 Sections Available Basin Area 55 Sections Mean Gas-in-place 4.6 Trillion cubic Recoverable Gas 2.7 fTrillioneet cubic Accessible Gas .06 fTrillioneet cubic Daily Production 187 fMillioneet cubic Yearly Production 68 fBcfeet Lifespan of Basin if .063 Tcf .93 Years Source: Government of Yukon, CERI

1 Aboriginal Affairs and Northern Development Canada, “Chapter 2 – Mackenzie Valley, Southern Territories and Interior Plains”, http://www.aadnc-aandc.gc.ca/eng/1320417163153/1320417233918#chp2.1 Accessed June 19, 2014. 2 Fraser, T., Ferri. F., Feiss, K., and Pyle, L., 2012. Besa River Formation in Liard Basin, Report on 2012 reconnaissance fieldwork, pp. 38

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Clearly, the present lack of accessibility to the basin is one factor that makes Liard unfeasible to develop in 2014; no pipeline would be built for a basin that would be exhausted in under a year.

A pipeline could be built for a more accessible Liard basin, however. This line would follow established transportation corridors, and the approximate costs would be as shown in Table A.2.

Table A.2: Pipeline Costs for Export Pipeline from Liard Liard to US Border (Haines) Delivered gas (MMcf/d) 187.4 Distance (km) 700 Diameter (inches) 24 Unit Cost ($dia-inch-km) 90,000 Capital Cost ($000s) 1,512,000 Cost of Service Factor (%) 13.77 Annual Cost of Service ($000s/y) 208.2 Toll at 100% Load Factor ($/Mcf) 2.85 Liard to US Border ($/Mcf) 2.85 Source: CERI

Liard is geographically very close to the Horn River and Montney shale gas plays in British Columbia, two producing unconventional gas basins. There are similarities in the geological structure as well.

Exploration and production companies are currently turning their attentions to the British Columbian portion of the Liard basin. The basin is rich in shale gas. The largest player in the Liard basin is Apache, also one of the major players in British Columbia’s Horn River basin. Tight shale and gas potential may extend into the Yukon portion of the Liard basin, particularly in the Triassic Toad-Grayling strata.3 Although little study has been completed to date, the geology is comparable to the liquids-rich Montney Shale, located in British Columbia and Alberta. The Cretaceous-aged shales are another prospective target for developers.4 Coal occurs in the Upper Cretaceous Wapiti Group as well as the Lower Carboniferous Mattson Formation. The coal seams in the latter may hold potential for coalbed methane.5

Old Crow Basin The Old Crow basin (Figure A.3) is located in northwestern Yukon in the Northern Yukon Fold Complex.6 The terrain is flat and spotted with muskeg and lakes and is north of the community

3 Yukon Geological Survey Miscellaneous Report 7, “Scoping study of unconventional oil and gas potential”, Department of Energy, Mines and Resources, 2012, pp. 42. 4 Ibid. pp. 48. 5 Ibid. pp. 42. 6 Yukon Energy, Mines and Resources, “Old Crow Basin Oil and Gas Resource Assessment”, http://www.emr.gov.yk.ca/oilandgas/oilgas_resource_assessments.html#Old_Crow_Basin_Oil_and_Gas_Resource _Assessment Accessed June 19, 2014.

March 2015 Economic Impacts of Natural Gas Development 67 Within the Yukon Territory of Old Crow, which is only accessible by air. The northern part of the basin is located in the Vuntut National Park while the western portion of the basin extends to the Alaska border. The Old Crow basin is located north of the Eagle Plain and the Peel Plateau & Plain regions and slightly north of the Yukon Fault and Dave Lord Uplift. The region area is approximately 75,000 km2 in size and is located entirely in Yukon.

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Figure A.3: Map of the Old Crow Exploration Region

March 2015 Economic Impacts of Natural Gas Development 69 Within the Yukon Territory

There are a total of three petroleum plays in the Old Crow basin that are periodically assessed for resource potential, all of which are gas plays. There are no oil prospects in the region.7

Beaufort-Mackenzie Plume Basin The Beaufort-Mackenzie basin is the most northern sedimentary basin in Yukon. The sliver- shaped basin is located next to the Beaufort Sea. Beaufort-Mackenzie includes onshore and offshore (though only the onshore resources have been considered for this report). Ivvavik National Park and Herschel Island Territorial Park lie in the basin. Like the Liard basin and the Peel Plateau & Plain, the basin is contiguous and extends east into the coastal region of the Northwest Territories. The region is approximately 75,000 km2 with no ports along its isolated shore. The Beaufort-Mackenzie basin shares a border with Alaska on its western edge.

Figure A.4 shows a map of the Yukon portion of the Beaufort-Mackenzie. The region is identified by a black line.

Figure A.4: Map of the Beaufort-Mackenzie Exploration Region

Source: P.K. Hannigan8

There are a total of six petroleum plays in the Beaufort-Mackenzie basin that are periodically assessed for resource potential, four of which are gas plays. Resource potential in the Northwest

7 Ibid. 8 Yukon Government, Energy, Mines and Resources, Beaufort-Mackenzie Basin Oil and Gas Resource Assessment, http://www.emr.gov.yk.ca/oilandgas/images/io_beaufort_mckenzie_map.pdf

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Territories’ portion of the Beaufort-Mackenzie is much higher; some estimates suggest 52 Tcf lie onshore/offshore.9

Bonnet Plume Basin The Bonnet Plume basin is located southwest of the Peel Plateau & Plain and southeast of the Eagle Plain. Approximately 40,000 km2 in size, there are three mountain ranges that converge on the basin – the Mackenzie, Werneckes and Richardson. Figure A.5 shows a map of Bonnet Plume, a structural depression in the eastern portion of the Cordilleran Orogen.10 The region is identified by a black line. As illustrated in the graphic, many of the rocks in the intermontane basin are Early Cretaceous to Early Tertiary.

Figure A.5: Map of Bonnet Plume Exploration Region

Source: http://www.emr.gov.yk.ca/oilandgas/pdf/map_bonnet_plume.pdf

There are three petroleum plays in the Bonnet Plume basin that have been periodically assessed for resource potential, all of which are gas plays. There are no wells in the basin – the nearest being the Toltec Peel River YT N-77 that was drilled in 1970 – and no seismic coverage in the area.11 The region, contains some of Yukon’s most extensive coal deposits, as well as deposits of iron, lead-zinc, copper and uranium.12 In addition, the thick coal deposits reveal the Bonnet

9 Fekete et al, North Yukon Conceptual Oil and Gas Development Scenario and Local Benefits Assessment, North Yukon Oil and Gas Working Group, pp. 11. 10 http://www.geology.gov.yk.ca/bonnet_plume_basin.html 11 Aboriginal Affairs and Northern Development Canada, “Chapter 3 – Northern Yukon”, http://www.aadnc- aandc.gc.ca/eng/1320855872731/1320855939488#chp3.4 Accessed June 19, 2012. 12 Canadian Heritage Rivers System, “Bonnet Plume River”, http://chrs.ca/Rivers/BonnetPlume/BonnetPlume- F_e.php Accessed June 19, 2014.

March 2015 Economic Impacts of Natural Gas Development 71 Within the Yukon Territory

Plume to be an attractive coalbed methane target, as the coal is expected to contain large amounts of natural gas.13

Kandik Basin The Kandik basin is located in northern Yukon, west of the Eagle Plain basin and south of the Old Crow basin. Figure A.6 shows a map of the Kandik basin, as well as wells and seismic lines in the area. Kandik straddles the Yukon-Alaska border, with the majority of the basin located in Alaska. Like the Liard basin and the Peel Plateau & Plain, the basin is contiguous. The Kandik is south of the Yukon Thrust, which extends from the southeast to the northwest, and the Tintina Fault Zone. The Nahoni Range borders the Kandik to the east and separates the Kandik from the Eagle Plain basin. The Kandik area is approximately 9,209 km2, of which approximately 60 percent is located in Alaska.14

13 Yukon Geological Survey Miscellaneous Report 7, “Scoping study of unconventional oil and gas potential”, Department of Energy, Mines and Resources, 2012, pp. 66. 14 Hannigan, P.K. “Petroleum Resource Assessment of the Old Crow Basin, Yukon Territory, Canada”, Yukon Economic Development, March 2001, pp. 7.

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Figure A.6: Map of the Kandik Basin Exploration Region

March 2015 Economic Impacts of Natural Gas Development 73 Within the Yukon Territory

There are five petroleum plays in the Kandik basin that are periodically assessed for resource potential, three of which are gas plays. The gas plays’ total mean gas potential is 648.9 Bcf.15

The Kandik basin possesses coalbed methane potential, with the Upper Cretaceous-aged Monster Formation’s 2,000 meter thick non-marine sediment.16 The coal, however, is of low quality. Tight reservoir potential is low in the basin; shales in the region are over-matured.17

Whitehorse Trough Basin The Whitehorse Trough, or Whitehorse basin, is located in southeastern Yukon, south of the Tintina Fault. The structural basin straddles the Yukon-British Columbia border, extending from Carmacks in the north to the foothills in British Columbia, near Dease Lake. The Yukon portion of the Whitehorse basin is approximately 37,192 km2 and is in the Canadian Cordillera.18 The Whitehorse Trough lies south of the Yukon Thrust, which extends from the southeast to the northwest and the Tintina Fault Zone. Figure A.7 shows a map of the Yukon portion of the Whitehorse basin. The area is outlined in black. To the east the geology is known as the Yukon Cataclastic Terrane while the region to the west is known as the Yukon Crystalline Terrane.

15 Yukon Government, Energy, Mines and Resources, “Kandik Basin Oil and Gas Resource Assessment”, http://www.emr.gov.yk.ca/oilandgas/oilgas_resource_assessments.html#Kandik_Basin_Oil_and_Gas_Resource_A ssessment Accessed June 19, 2014. 16 Yukon Geological Survey Miscellaneous Report 7, “Scoping study of unconventional oil and gas potential”, Department of Energy, Mines and Resources, 2012, pp. 66. 17 Ibid. 18 National Energy Board for Energy Resources Branch, “Petroleum Resource Assessment of the Whitehorse Trough”, Yukon Territory, Canada, February 2001, pp. 3.

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Figure A.7: Map of the Whitehorse Trough Exploration Region

Source: Yukon Energy, Mines and Resources

There are a total of eight petroleum plays in the Whitehorse basin that are being assessed for resource potential, four oil plays and four gas plays. Of the eight plays, six are stratigraphic in nature while two are structural.19 The gas plays’ total mean gas potential is 380 Bcf.20

19 Ibid. pp. 17. 20 Yukon Government, Energy, Mines and Resources, “Kandik Basin Oil and Gas Resource Assessment”, http://www.emr.gov.yk.ca/oilandgas/oilgas_resource_assessments.html#Kandik_Basin_Oil_and_Gas_Resource_A ssessment Accessed June 19, 2014.

March 2015 Economic Impacts of Natural Gas Development 75 Within the Yukon Territory Appendix B The History of Mining in Yukon

Over the past century, Yukon has produced gold, silver, lead, zinc, copper, asbestos, coal, nickel, platinum group elements and jade. Major mines and smaller producers of the 20th century are listed in Table B.1, with locations shown in Figure B.1.

Table B.1: Hard Rock Mining – Principal Historical Producers*

First Economic Operating Grid Deposit Commodities Company Staked Evaluation Periods Connect 1900-20, Whitehorse Whitehorse Ag, Au, Cu, Mo 1898 1924-29, Copper Copper 1967-82 1913-13, United early 1921-33, Keno Hill Ag, Pb, Zn Keno Hill 1951 1900s 1935-36, Mines, Ltd. 1946-89 Anvil Range 1923-38, Tantalus Coal Mining 1948-67, Butte Corp. 1905 1969-81 Anvil Range 1969-82, 1953 & Faro Ag, Au, Pb, Zn Mining 1986-93, 1969 1956 Corp. 1995-96 Initial Veris Gold Ketza Au 1954 Resource 1988-90 Corp. Estimate, 2011 Cassiar Clinton Asbestos Asbestos 1957 1967-78 Creek Corp. Sa Dena Hes Curragh Recommission / Mt. Ag, Pb, Zn Resources, 1962 feasibility 1991-92 Hundere Inc. 1997 Preliminary Feasibility Tagish Lake Mt. Skukum Au 1981 2004; 1986-88 Gold Corp. Resource estimate 2013 *Brewery Creek, a commercial gold producer that operated from May 1997 to December 2001, is included in the survey of prospective producers outlined in Table 1.1 as it is subject to ongoing exploration and development. Wellgreen, a deposit that once saw short-lived production for nickel and platinum group metals, operated very briefly and is outlined in Table 1.1 as a prospective development given renewed exploration and development. Source: Corporate Policy & Planning & Mineral Resources, Energy, Mines & Resources

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Figure B.1: Map of Yukon’s Past-Producing Mines

The single largest hard rock operation in Yukon was the Faro mine. At its peak, the Faro mine produced 15 percent of the world supply of lead and zinc,1 with Yukon accounting for close to 3 percent of Canada’s value of mineral production in 1992.2

1 p. 3 “A Detailed History of the Faro Mine Complex”, Faro Mine Remediation Project, Energy, Mines & Resources, http://www.faromine.ca/assets/files/history.pdf accessed on December 15, 2014 2 Source: Corporate Policy & Planning, Energy, Mines & Resources. Data: Mineral Production, Annual Statistics, NRCan, http://sead.nrcan.gc.ca/prod-prod/2013-eng.aspx Accessed November 18, 2014.

March 2015