Study No. 173 July 2018 - CERI

CANADIAN ENERGY RESEARCH INSTITUTE

CANADIAN CRUDE OIL AND NATURAL GAS

PRODUCTION, SUPPLY COSTS, ECONOMIC IMPACTS

AND EMISSIONS OUTLOOK (2018-2038)

Study No. 173 July 2018

Canadian Energy Research Institute | Relevant • Independent • Objective

Canadian Crude Oil and Natural Gas Production, Supply Costs, i Economic Impacts and Emissions Outlook (2018-2038)

July 2018

CANADIAN CRUDE OIL AND NATURAL GAS PRODUCTION, SUPPLY COSTS, ECONOMIC IMPACTS AND EMISSIONS OUTLOOK (2018-2038)

ii Canadian Energy Research Institute

July 2018

Canadian Crude Oil and Natural Gas Production, Supply Costs, Economic Impacts and Emissions Outlook (2018-2038) Authors: Andrei Romaniuk Hamid Rahmanifard ISBN 1-927037-58-4 Copyright © Canadian Energy Research Institute, 2018 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute July 2018 Printed in Canada Front cover photo courtesy of Google images Acknowledgements: The authors of this report would like to extend their thanks and sincere gratitude to 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.

ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE – CANADA’S VOICE ON ENERGY Founded in 1975, the Canadian Energy Research Institute (CERI) is an independent, registered charitable organization specializing in the analysis of energy economics and related environmental policy issues in the energy production, transportation and consumption sectors. Our mission is to provide relevant, independent, and objective economic research of energy and environmental issues to benefit business, government, academia and the public. For more information about CERI, visit www.ceri.ca CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Email: [email protected] Phone: 403-282-1231

http://www.ceri.ca/

mailto:[email protected]

Canadian Crude Oil and Natural Gas Production, Supply Costs, iii Economic Impacts and Emissions Outlook (2018-2038)

July 2018

Table of Contents

LIST OF FIGURES ............................................................................................................. v

LIST OF TABLES ............................................................................................................... vii

EXECUTIVE SUMMARY .................................................................................................... ix

CHAPTER 1 INTRODUCTION ........................................................................................ 1

Crude Oil ............................................................................................................................ 1 Natural Gas ........................................................................................................................ 5 Report Structure ................................................................................................................ 9

CHAPTER 2 CANADIAN OIL AND GAS SUPPLY COSTS AND PRODUCTION – PROVINCIAL OUTLOOK .............................................................................................. 11

Canadian Crude Oil ............................................................................................................ 11 Alberta .......................................................................................................................... 11 British Columbia ........................................................................................................... 16 Saskatchewan .............................................................................................................. 19 Manitoba ...................................................................................................................... 22 Newfoundland and Labrador ....................................................................................... 24 Natural Gas ........................................................................................................................ 29 Alberta .......................................................................................................................... 29 British Columbia ........................................................................................................... 33 Saskatchewan .............................................................................................................. 36 Canada ......................................................................................................................... 39

CHAPTER 3 CANADIAN OIL AND GAS ECONOMIC IMPACTS AND EMISSIONS ............... 41

Economic Impacts .............................................................................................................. 41 Assumptions for Economic Impact Modeling .............................................................. 42 Economic Impacts of Conventional Crude Oil Development ...................................... 47 Economic Impacts of Natural Gas Development ......................................................... 50 Emissions ............................................................................................................................ 53

CHAPTER 4 CONCLUSIONS .......................................................................................... 57

BIBLIOGRAPHY ............................................................................................................... 63

APPENDIX A NATURAL GAS AND CRUDE OIL PRODUCTION FORECASTS AND SUPPLY COST METHODOLOGIES ................................................................................ 67

Natural Gas Production Forecast and Supply Cost Methodology ..................................... 67 Production Inputs ........................................................................................................ 68 Cost Inputs ................................................................................................................... 68 Other Economic Assumptions ...................................................................................... 68 Crude Oil Production: Western Canada Forecast and Supply Cost Methodology ........... 69 Production Impacts ...................................................................................................... 69 Cost Inputs ................................................................................................................... 70 Other Economic Assumptions ...................................................................................... 70

iv Canadian Energy Research Institute

July 2018

Crude Oil Production: Offshore Newfoundland and Labrador Forecast and Supply Cost Methodology .................................................................................................. 71

Production Profile Inputs ............................................................................................. 71 Production Profile Assumptions .................................................................................. 71

APPENDIX B INPUT-OUTPUT MODEL ............................................................................ 73

CERI CMRIO 4.0 .................................................................................................................. 73 Industries in the CMRIO 4.0 ............................................................................................... 77

APPENDIX C PRODUCTION FORECASTS ......................................................................... 81

Oil and Condensate Production Forecasts ......................................................................... 81 Gas Production Forecasts .................................................................................................. 83

APPENDIX D STUDY SUPPLY AREAS .............................................................................. 85

Canadian Crude Oil and Natural Gas Production, Supply Costs, v Economic Impacts and Emissions Outlook (2018-2038)

July 2018

List of Figures

E.1 Total Canadian Conventional Crude Oil Production .................................................... ix E.2 Total Canadian Natural Gas Production ...................................................................... xi E.3 Crude Oil Production Emissions ................................................................................... xiii E.4 Natural Gas Production Emissions ............................................................................... xiii 1.1 Conventional Oil and Condensate Production, Canada .............................................. 2 1.2 Canadian Crude-by-Rail................................................................................................ 3 1.3 Canadian Oil Reserves .................................................................................................. 4 1.4 US Natural Gas Production, 2004-2018 ....................................................................... 5 1.5 Canada’s Gas Exports and Production ......................................................................... 6 1.6 Canada-US Natural Gas Trade Volumes....................................................................... 7 1.7 Pipeline Capacity Additions for Marcellus Natural Gas Outflows ............................... 8 2.1 Alberta New Oil Well Forecast ..................................................................................... 12 2.2 Alberta Crude Oil Production Forecast ........................................................................ 13 2.3 WTI Crude Oil Price Forecast ....................................................................................... 14 2.4 Alberta Vertical Oil Well Supply Costs ......................................................................... 15 2.5 Alberta Horizontal Oil Well Supply Costs ..................................................................... 15 2.6 British Columbia New Oil Well Forecast ...................................................................... 16 2.7 British Columbia Crude Oil Production Forecast ......................................................... 17 2.8 British Columbia Vertical Oil Well Supply Costs .......................................................... 18 2.9 British Columbia Horizontal Oil Well Supply Costs ...................................................... 18 2.10 Saskatchewan New Oil Well Forecast .......................................................................... 19 2.11 Saskatchewan Crude Oil Production Forecast ............................................................. 20 2.12 Saskatchewan Vertical Oil Well Supply Costs .............................................................. 21 2.13 Saskatchewan Horizontal Oil Well Supply Costs .......................................................... 21 2.14 Manitoba New Oil Well Forecast ................................................................................. 22 2.15 Manitoba Crude Oil Production Forecast .................................................................... 23 2.16 Manitoba Vertical Oil Well Supply Costs ..................................................................... 23 2.17 Manitoba Horizontal Oil Well Supply Costs ................................................................. 24 2.18 Number of Wells with Drilling and Equipment Costs, 2012-2016 ............................... 25 2.19 Development Wells Distribution among Fields in Newfoundland and Labrador ........ 26 2.20 Offshore Newfoundland and Labrador Crude Oil Production Forecast ...................... 27 2.21 Canada New Oil Well Forecast ..................................................................................... 28 2.22 Canadian Crude Oil Production Forecast ..................................................................... 29 2.23 Alberta New Gas Well Additions .................................................................................. 30 2.24 Alberta Wellhead Natural Gas Production Forecast .................................................... 31 2.25 Alberta Vertical Natural Gas Well Supply Costs ........................................................... 32 2.26 Alberta Horizontal Natural Gas Well Supply Costs ...................................................... 32 2.27 British Columbia New Gas Well Forecast..................................................................... 33 2.28 British Columbia Field Gate Natural Gas Production Forecast .................................... 34 2.29 British Columbia Vertical Gas Well Supply Costs ......................................................... 35

vi Canadian Energy Research Institute

July 2018

2.30 British Columbia Gas Well Supply Costs ...................................................................... 35 2.31 Saskatchewan New Gas Well Forecast ........................................................................ 36 2.32 Saskatchewan Natural Gas Production Forecast ......................................................... 37 2.33 Saskatchewan Vertical Natural Gas Well Supply Costs ............................................... 38 2.34 Saskatchewan Horizontal Natural Gas Well Supply Costs ........................................... 38 2.35 Canada New Oil Well Forecast ..................................................................................... 39 2.36 Canada Natural Gas Production Forecast .................................................................... 40 3.1 Alberta Operations and Capital Investment ................................................................ 42 3.2 British Columbia Operations and Capital Investment ................................................. 44 3.3 Saskatchewan Operations and Capital Investment ..................................................... 45 3.4 Manitoba Operations and Capital Investment ............................................................ 46 3.5 Newfoundland and Labrador Operations and Capital Investment ............................. 47 3.6 Annual GDP Impacts of Crude Oil Development, 2018-2028 ...................................... 48 3.7 Employment Impacts of Crude Oil Development, 2018-2028 ..................................... 49 3.8 Annual Tax Receipts from Crude Oil Development, 2018-2028 .................................. 50 3.9 Annual GDP Impacts of Natural Gas Development, 2018-2028 .................................. 51 3.10 Employment Impacts of Natural Gas Development, 2018-2028 ................................. 51 3.11 Annual Tax Receipts from Natural Gas Development, 2018-2028 .............................. 52 3.12 Percentage of Oil Type by Province ............................................................................. 54 3.13 Emissions from Crude Oil Production, 2018-2028 ....................................................... 55 3.14 Emissions from Natural Gas Production, 2018-2028 ................................................... 56 4.1 Total Canadian Conventional Crude Oil Production .................................................... 57 4.2 Total Canadian Natural Gas Production ...................................................................... 58 4.3 Total Tax Revenues by Commodity, 2018-2028 .......................................................... 59 4.4 Total Employment by Province, 2018-2028................................................................. 60 4.5 Total Percentage of Emissions by Province, 2018-2038 .............................................. 61 D.1 Map of British Columbia Study Areas .......................................................................... 88 D.2 Map of Alberta Study Areas ......................................................................................... 89 D.3 Map of Saskatchewan Study Areas .............................................................................. 90 D.4 Map of Manitoba Study Areas ..................................................................................... 91 D.5 Map of Newfoundland and Labrador Study Areas ...................................................... 92

Canadian Crude Oil and Natural Gas Production, Supply Costs, vii Economic Impacts and Emissions Outlook (2018-2038)

July 2018

List of Tables

3.1 Total GDP and Employment Impacts of Crude Oil Development, 2018-2028 ............ 48 3.2 Total Tax Receipts from Crude Oil Development, 2018-2028 ..................................... 49 3.3 Total GDP and Employment Impacts of Natural Gas Development, 2018-2028......... 50 3.4 Total Tax Receipts from Natural Gas Development, 2018-2028 ................................. 52 B.1 Sectors/Commodities in CERI Canada Multi-Regional I/O Model ............................... 77 C.1 Oil and Condensate Production Forecast .................................................................... 81 C.2 Natural Gas Production Forecast ................................................................................. 83 D.1 Supply Study Areas ...................................................................................................... 85

viii Canadian Energy Research Institute

July 2018

Canadian Crude Oil and Natural Gas Production, Supply Costs, ix Economic Impacts and Emissions Outlook (2018-2038)

July 2018

Executive Summary This study examines Canada’s conventional crude oil and natural gas industries, including production forecasts and supply costs, over the next 20 years. The study covers onshore and offshore conventional oil, including shale and tight oil activity, conventional natural gas, coalbed methane, tight and shale gas, and the associated natural gas liquids (pentanes plus and condensate only). It does not include oil sands.

For crude oil, after a sharp decline in output from 2014 to 2016 (by 8.4%),1 conventional oil production started to rise in 2017 in response to increasing oil prices. Conventional oil production including pentanes plus in Canada in 2017 was 1.52 million barrels per day (MMbpd), led by Alberta at 0.69 MMbpd, 0.49 MMbpd from Saskatchewan and 0.22 MMbpd from Newfoundland

and Labrador (offshore).2 Figure E.1 shows total conventional crude oil produced in Canada between 2013-2017, and forecast out to 2038. It does not include production out of the territories, Ontario, New Brunswick, or Nova Scotia as these volumes are negligible.

Figure E.1: Total Canadian Conventional Crude Oil Production

Source: CERI, BCOGC, AER, Government of SK, Government of Manitoba, CNLOPB, PSAC, CAPP

1 NEB, Estimated production, NEB Data-hub 2 Totals may not add due to rounding. NEB, Estimated Production of Canadian Crude Oil and Equivalent, https://www.neb-one.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/stmtdprdctn-eng.html

https://www.neb-one.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/stmtdprdctn-eng.html

x Canadian Energy Research Institute

July 2018

This report examines conventional crude oil production from each province individually. Total

production will increase from 2017 to 2025 where it will remain stable through the remainder of the study period. Growth in western Canada will be offset by the declines seen in offshore Newfoundland and Labrador. Over the study period, production levels are not expected to reach the highs seen in 2014 before the decline in oil price.

The growth in crude oil production will be led by Alberta (25% increase from 2018 levels), followed by Saskatchewan (11% growth) as it is expected the province will be focusing on drilling their tight oil formations. In 2038, total conventional crude oil production will be just above 1.3 MMbpd. Pentane plus and condensate production for the two scenarios of no LNG plants versus LNG plants are 0.37 and 0.43 MMbpd, respectively. Thus, total conventional oil production with pentanes plus and condensate in Canada will increase to 1.67 MMbpd (9.8% growth from 2017) or 1.76 (15.7% growth from 2017) for the scenario with LNG.

Canadian natural gas producers are facing challenges with the “shale revolution” that has occurred in the United States. The shale revolution and LNG exports have transformed the US from a net importer to a net exporter of natural gas in 2017. With Canada being the main natural gas exporter to the US, it is no surprise that there are negative consequences for Canadian gas producers. In 2017, Canada was the fifth largest producer of natural gas globally3 with production of 18.1 bcf/d.4 In Canada, Alberta represented approximately three-quarters of the country’s production. Total natural gas production in Canada from 2013-2017 and the forecast through 2038 is shown in Figure E.2.

As shown in Figure E.2, total Canadian production is expected to decrease out to 2038 because of the declining trend of Canadian natural gas exports to the US and increased imports from the

US. Alberta will see declining production from 2018 through 2038, while British Columbia is expected to have a slight increase for the same period. British Columbia will also see two increases in production if Liquefied Natural Gas (LNG) projects are approved. In this study, the Canadian Energy Research Institute (CERI) assumes liquefaction capacity is coming online in 2023 and 2025. Total natural gas production for LNG projects is forecasted to be slightly over 5 Bcf/d. This amount could be perceived as optimistic, but still feasible if projects on the west coast take FID in 2018-2020. Once production has risen to accommodate the increase in demand that the LNG projects will cause, production will remain stable with marginal decreases through the remainder of the study period. In 2038, the production of natural gas will be 15.4 Bcf/d for the scenario with no new LNG plants, whereas it is approximately 20 Bcf/d with new LNG plants.

3 BP website, BP Statistical Review of World Energy June 2017, https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review -2017/bp-statistical-review-of-world-energy-2017-full-report.pdf, pp. 30. (Accessed on May 18, 2018) 4 CAPP Statistical Handbook, October 2017, Table 3.9.

https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review%20-2017/bp-statistical-review-of-world-energy-2017-full-report.pdf

https://www.bp.com/content/dam/bp/en/corporate/pdf/energy-economics/statistical-review%20-2017/bp-statistical-review-of-world-energy-2017-full-report.pdf

Canadian Crude Oil and Natural Gas Production, Supply Costs, xi Economic Impacts and Emissions Outlook (2018-2038)

July 2018

Figure E.2: Total Canadian Natural Gas Production

Source: CERI, Government of SK, BCOGC, AER, PSAC, CAPP

This study also examines the economic impacts of the Canadian conventional oil and natural gas industry on the Canadian economy, at the provincial level, utilizing CERI’s proprietary Canada

Multi-Regional Input-Output (CMRIO) model. The impacts analysis is done for the period 2018-2028.

The Canadian oil and gas industry is a significant contributor to the provincial and national economies in Canada. In the foreseeable future, natural gas and crude oil will be important elements in many economic sectors in Canadian and North American economies. Total GDP impacts from investment and revenues throughout the forecast period of 2018-2028 for crude oil is CAD$833.9 billion and CAD$299.7 billion for natural gas. Similarly, with government tax revenues, those collected and received from crude oil are higher in magnitude than for natural gas. Federal taxes from crude oil projects are approximately three times higher than those collected from natural gas projects (CAD$68.7 billion vs. CAD$27.9 billion). Provincial tax revenues follow the same pattern – crude oil related provincial taxes are higher than those for

natural gas (CAD$50.3 billion vs. CAD$17.5 billion).

Total employment impacts from all Canadian oil and gas development will materialize in every province and territory (1,836 thousand person-years for oil and 820 thousand person-years for natural gas). The largest labour impact will be felt in Alberta with 46 and 60 percent for crude oil and natural gas projects, respectively, of total labour impacts. However, companies that are

xii Canadian Energy Research Institute

July 2018

suppliers of goods and services, such as machinery, manufacturing, trade, legal, environmental,

financial services, often located outside of Alberta, will also benefit.

Because of the impacts of carbon emission intensities on market outlook of industrial operations, the third part of this study estimated the annual average emissions from oil and gas production during the forecast period. CERI’s emission forecasts include upstream production of conventional oil and conventional and unconventional gas in Canada. More specifically, upstream emissions encompass emissions from the following activities: drilling, production and extraction, processing in the field, and venting, flaring, and fugitive emissions.

For conventional crude oil, we used data from CERI Study 167: “An Economic and Environmental Assessment of Eastern Canada Crude Oil Imports.” In particular, emission intensity for light crude volumes for this study is calculated as a weighted average of two emission intensity figures –

mixed sweet blend and mixed sour blend. The estimated intensity is then 41.12 kg CO2 eq/bbl, which is used to calculate total upstream emissions for light, medium and condensate production. For heavy oil production, an intensity of 72.4 CO2 kg eq/bbl is used for calculating upstream emissions.

For our analysis, CERI is using the emissions intensity of the natural gas industry derived from data published by Environment and Climate Change Canada (ECCC 2018). According to the publication, as of April 2018, total natural gas emissions were 48.6 megatonnes of carbon dioxide equivalent. Using 17.91 Bcf/d as raw natural gas production for 2016 (CanSim 2017), the resulting intensity is 7.44 tonnes CO2 eq/mmscf.

It is important to note that according to historical intensity values, which have been decreasing

for natural gas and crude oil, CERI considered two scenarios for emissions:

• The reference case: 2016 emission intensities were considered to be the same over the study period (no further improvement in emission intensities was assumed in the forecast).

• The lower intensity case: CERI assumed that the 2016 intensities drop by 1.1% for oil production and 4.6% for natural gas production based on recent historical trends. Note that the decreasing trend of intensities continues until it reaches 70 percent of the 2016 intensity rates at which it is assumed to remain constant.

In the reference case, total emissions associated with oil production will amount to 635.7 million tonnes over the 2018-2038 period (Figure E.3). On average, annual emissions from oil production will be 30.3 million tonnes/year. The provinces of Alberta and Saskatchewan will generate the

highest emissions at 45 and 40 percent, respectively. With the improved emission intensities, total annual emissions drop from 28.13 million tonnes/year in 2018 to 23.9 million tonnes/year in 2038 (on average 26.4 million tonnes/year).

Canadian Crude Oil and Natural Gas Production, Supply Costs, xiii Economic Impacts and Emissions Outlook (2018-2038)

July 2018

Figure E.3: Crude Oil Production Emissions

Figure E.4 shows total emissions associated with natural gas production for the reference case, which is 970.4 million tonnes over the 2018-2038 period (Figure 3.14). On average, annual emissions from natural gas production will be 46.2 million tonnes/year during the study period. The provinces of Alberta and British Columbia will generate the highest emissions at 70 and 28 percent, respectively (Figure E.4). With the improved emission intensities, total annual emissions drop from 47.9 million tonnes/year in 2018 to 29.4 million tonnes/year in 2038 (on average 33.0 million tonnes/year).

Figure E.4: Natural Gas Production Emissions

xiv Canadian Energy Research Institute

July 2018

Canadian Crude Oil and Natural Gas Production, Supply Costs, 1 Economic Impacts and Emissions Outlook (2018-2038)

July 2018

Chapter 1: Introduction

Crude Oil Since the publication of the last Canadian Energy Research Institute (CERI) report on conventional oil and gas in September 2016, the oil market situation has changed significantly.

The WTI oil price has recently rebounded to close to $70 from the $40 range in September 2016 and from even more stressing levels of under $30 in February that year (Bloomberg 2018). The commodity has been in growth mode since June 2017 underpinned by the joint OPEC-Russia production cuts, declines in Mexico and Venezuela production and geopolitical risks of new US sanctions on Iran.

Since late 2016, OPEC, Russia and some other countries have voluntarily been cutting production to reduce world oil stocks and oversupply. Though the market was skeptical about these measures, as OPEC countries are known for not fully following the commitments and non-transparent reporting, the joint alliance demonstrated record compliance. From January 2017 to April 2018, all OPEC countries complied with the cuts. In fact, since last October, OPEC has passed 100% of compliance and is at 166% of its target of 1.18 million barrels per day (MMbpd) as of April 2018 (Wingfield et al. 2018). Non-OPEC countries (Russia, Mexico, Oman, Kazakhstan and others) reached overall targets in August-October of 2017. In fact, they cut up to 140% of their commitments collectively but dropped to 73% compliance levels as of April 2018. Recently, OPEC and Russia have signalled that the production cuts may not be prolonged further. This halted a Brent oil price rally several dollars short of $80. The fate of the deal was decided in June 2018 (DiChristopher 2018).

So far, critics of the deal admitted that actions by OPEC and non-cartel countries resulted in a return to the 5-year average1 oil inventory. The talks about oversupply and long-term low prices have changed to discussions regarding eminent undersupply after 2020 and price spikes due to

low investment levels in the industry since 2014. Global oil and gas upstream investment fell 25% in 2015 and another 26% in 2016 (OGJ 2017). The IEA suggested that the agency “does not see a peak in oil demand any time soon and unless investment globally rebounds sharply, a new period of price volatility looms on the horizon." Indeed, over the next two decades, the IEA forecasts world oil demand to grow from 93.7 MMbpd to 118.8 MMbpd under their Current Policies scenario and 104.9 MMbpd under the New Policies scenario (IEA 2017).

According to the IEA, this total growth of 11% in demand under the New Policies scenario will be

filled by:

• Non-OPEC countries: North America (1% cumulative annual growth rate from 2016-2040) and Latin America (1.7%), and

1 N.B. these averages are considered by some countries to be inflated due to high stocks in recent years.

2 Canadian Energy Research Institute

July 2018

• OPEC countries: Middle East (0.8%) and non-Middle East (0.4%).

Canada’s production (with oil sands) is assumed to grow annually by 1.4% (from 4.5 to 6.2 MMbpd), reacting to global demand for oil while US production will grow at 0.7% (IEA 2017).

In recent years, the dominating themes in the Canadian oil industry were:

• need for expanded market access to international and US markets,

• changes in regulatory processes (environment impact assessment process and redesign of the National Energy Board),

• widening price differential between Western Canadian Select and WTI,

• production and price risks from the upcoming regulation change in the shipping industry regarding sulphur levels, and

• competitiveness issues as compared to the US.

The fall in output of conventional oil from 2014 to 2016 by 8.4% was also a challenge. In 2017, production began to grow and gained 5% compared to 2016. With this growth, the 2017 production was 96% of 2014 levels. The largest growth came from condensate in both Alberta and British Columbia (20% compared to 2016), followed by growth of oil production in Saskatchewan and Newfoundland and Labrador. Alberta, Manitoba, Northwest Territories, and British Columbia still experienced a reduction in conventional oil production compared to 2016. Figure 1.1 shows the actual oil production in Canada from 2014-2017. For comparison, in the same pricing environment, the US has boosted its production by 6.7% from 2014, growing to 9.4 million barrels per day in 2017.

Figure 1.1: Conventional Oil and Condensate Production, Canada (mbpd)

Source: CERI, NEB

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

1,800,000

2014 2015 2016 2017

AB AB Heavy SK SK Heavy NF/NL

BC MB NWT/NT ON AB Condensate

BC Condensate SK Condensate NS Condensate


July 2018

The fall in Canadian production paralleled a 37% reduction in drilling during 2014-2017. The

number of oil wells drilled dropped from 7.7 thousand to 4.9 thousand. Alberta’s drilling decreased by 43%, while Saskatchewan’s by 27%.

Looking ahead, as major oil export pipelines are running full (Kinder Morgan’s Trans Mountain Pipeline, Enbridge’s Mainline, TransCanada’s Keystone), further growth of oil production, primarily oil sands, is contingent on the expansion of market access. Three projects – Trans Mountain Expansion, Line 3 and Keystone XL – will ease the situation. However, none will be completed by the end of 2019. This limits the industry’s ability to take advantage of substituting for falling Mexico and Venezuela exports to the US.

Irrespective of surging US oil developments, Canadian oil is still in demand in the US as many mid-continent and Gulf Coast refiners are suited to the processing of heavy Canadian crude. While US

oil production has grown by 43% from 2012-2017, the share of OPEC countries has decreased by 20% in the US market, and Canada’s has increased by 37% (EIA 2018c). Because the US has allowed for oil exports effective 2015, it can now monetize its light shale oil at the premium price in export markets, while refining cheaper heavier oil domestically. This model allows for sustaining and even increasing Canada’s oil exports to the US in parallel to US shale oil developments.

Crude-by-rail is expected to alleviate part of the problem, but it is not certain if rail can take the volume necessary to support incremental production. Since August 2017, rail volumes (see Figure 1.2) have been on the rise, reaching 170 thousand barrels per day (Mbpd) in March 2018 from 92 mbpd in August 2017. From 2012, Canada has never exported more than 179 Mbpd by rail (Jaremko 2018).

Figure 1.2: Canadian Crude-by-Rail

Source: National Energy Board


July 2018

The remaining established reserves (Figure 1.3) have been stable over the last 15 years, hovering

around 4,000 million barrels, showing that producers have been able to substitute almost 100% of produced oil with successful exploration. If this success continues and market access increases, Canada will be positioned to expand its production and export of light, medium and heavy oil in the future.

Figure 1.3: Canadian Oil Reserves

Source: CERI based on CAPP Statistical Handbook 2017

There are two other regions worth mentioning – eastern offshore developments and the Arctic.

First, Newfoundland and Labrador has seen the first oil from a new producing asset in 2017 – the Hebron project. The platform sits on top of a 707 million barrel reserve base (C-NLOPB 2018c) and is expected to reach approximately 40 mbpd in 2018 and 134 mbpd in 2022 (C-NLOPB 2018a), providing a needed addition to the provincial royalty base, which has dropped from $1.98 billion in 2014 to $0.49 billion in 2016 due to lower Brent prices (CAPP 2018). Development drilling also grew from 8 wells in 2014 to 11 wells in 2017; geophysics volumes grew as well (C-NLOPB 2018b). For the latter, over $1 billion has been spent during 2014-2016, compared to $92 million spent in 2012-2013 (CAPP 2018). Looking ahead, the government has set the ambitious goal of 100 new exploration wells in the next 12 years (Financial Post 2018) To put into perspective, 19 exploration

wells have been drilled over the last 5 years.

As of the time of writing, BP started offshore exploration drilling in the adjacent Nova Scotia, in the license area close to the natural gas Sable Island project (BP 2018). This drilling campaign follows Shell’s efforts in 2017 to find oil in Nova Scotia’s shelf, which resulted in sealing two wells due to the failure to find commercial reserves (Withers 2016).


July 2018

Second, in December 2016, the federal government announced joining the US in a drilling ban in

the Arctic. Canada banned such operations for five years, while the US did it indefinitely. However, the Northwest Territories viewed the development differently (Canadian Press 2017). Oil production in the Northwest Territories fell to under 10 mbpd in 2014 and reached almost zero in 2017 while remaining reserves in the Mackenzie Delta and Beaufort Sea are estimated at 340 million barrels. This represents 22% of Alberta’s and almost 50% of Saskatchewan’s remaining recoverable reserves. Premier McLeod suggested that while Canada has benefited for years from resource development, it now wants to tell the territories they can't develop their own fossil fuels while the South keeps pumping out oil and gas (Canadian Press 2017).

Natural Gas In terms of natural gas, the last decade has seen a transformation from considering the US as our major customer to our major competitor. The US became a net gas exporter in 2017 because of

major production increases in several natural gas basins in the country; including the prolific Marcellus Play (see Figure 1.4). While both shale oil and shale gas have soared in the US, the impact on the natural gas market has been significant.

Figure 1.4: US Natural Gas Production, 2004-2018

Until 2016, the US did not have an opportunity to export its natural gas in the form of LNG. Thus, surging production from shale gas, especially from the Marcellus and Utica plays in Pennsylvania,

West Virginia and Ohio, and Eagle Ford and Haynesville in Texas was competing with and displacing Canadian gas and US LNG imports. The shale natural gas supply in the US soared from around 5 bcf/d ten years ago to over 50 bcf/d in 2018, totalling almost three times that of Canadian production.


July 2018

With Canada historically being the main natural gas exporter to the US, it is no surprise that in

the long-term there are negative consequences for Canadian gas producers. In recent years (2013-2017), there have not been any dramatic changes in trade. Overall, Canada’s production kept growing, supported by domestic demand. As shown in Figure 1.5, net exports stabilized around 5.1-5.6 bcf/d, while exports grew from 7.6 to 8.1 bcf/d.2 Recall that today’s export volumes have already dropped by 20% from the peak in 2007 – 10.4 bcf/d.

Figure 1.5: Canada's Gas Exports and Production (bcf/d)

Source: CERI based on US EIA, Statistics Canada

Going forward, the US EIA forecasts that net imports from Canada will almost disappear by 2040 as US imports will fall close to 5 bcf/d and their exports will grow to almost the same level from today’s 2 bcf/d (Figure 1.6).

2 Net exports = Exports – Imports.

15.88 16.62 16.81

17.91 18.30

7.63 7.22 7.19 7.99 8.12

2.50 2.11 1.92 2.11 2.51

5.14 5.11 5.27 5.88 5.60

-

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

20.00

2013 2014 2015 2016 2017

Gas Production Gas exports to US Gas imports (from US) Net exports


July 2018

Figure 1.6: Canada-US Natural Gas Trade Volumes (bcf/d)

Source: CERI, based on EIA Outlook 2017

This means that if this scenario materializes, current net exports of 5.6 bcf/d will vanish removing the need for this volume in Canadian production unless domestic demand growth compensates for the reduction in exports. This could come in the form of increased demand for oil sands energy requirements, electricity generation, petrochemical feedstock demand or other domestic demand sectors.

The growth of imports from the United States into Ontario and Quebec is expected to continue. Existing import pipeline capacity of 5.4 bcf/d (5.2 bcf/d to Ontario and 0.2 bcf/d to Quebec) (EIA 2018b) is already enough to push the volumes of US gas that the EIA forecasts out to 2040. Ontario and Quebec have historically been large customers of western Canadian gas. However, because of the Marcellus Play in the US close to Ontario and Quebec, the eastward throughput of the TransCanada Mainline fell from 5.97 bcf/d in 2006 to 2.17 bcf/d in 2017 (NEB 2017b).

To increase western Canadian producers cost-competitiveness in central Canada, TransCanada introduced in 2017 a discounted toll of $0.77/GJ substituting its existing rate of $1.86/GJ. It was reported that 23 companies signed for 1.5 million gigajoules per day (1.4 bcf/d) under this rate (MCINTOSH 2017). This measure gives Canadian gas a chance to be cost-competitive.

Domestically, Marcellus/Utica natural gas producers have been aggressively moving natural gas out of the producing area which has resulted in a 49.3 bcf/d pipeline outflow capacity from three states – Pennsylvania, West Virginia, and Ohio. An additional 4.1 bcf/d was added in 2017, and a further 27.3 bcf/d of new capacity has been announced (EIA 2018b). Many of the latter projects will not be built, but the magnitude of activity and interest indicates a robust market.

-

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.020

16

20

17

20

20

20

21

20

22

20

23

20

24

20

25

20

26

20

27

20

28

20

29

20

30

20

31

20

32

20

33

20

34

20

35

20

36

20

37

20

38

20

39

20

40

Net imports to US Pipeline Imports from Canada Pipeline Exports to Canada


July 2018

In Figure 1.7, the map of the Marcellus/Utica shale gas outflows in blue show the following

expansions:

• to Canada – plus 300 mmscf/d from Pennsylvania to Ontario, Empire North Expansion Project), and

• to the US Gulf of Mexico – companies are reversing pipelines, e.g., the Northern Supply Access Project, and making pipelines bidirectional, e.g., the Kinder Morgan Louisiana pipeline (KMLP). The latter has applied for authorization to add bidirectional 580 mcf/d capacity to send Marcellus gas to the Sabine Pass LNG export terminal starting in 2019 when the fifth liquefaction train comes online (Argus media 2016).

Figure 1.7: Pipeline Capacity Additions for Marcellus Natural Gas Outflows

Source: CERI based on EIA US natural gas pipeline projects (EIA 2018b).

Additional pipeline capacity out of Marcellus/Utica overlaps with Canadian exports to the states of New York and Michigan. Canada exports 0.44 bcf/d of Canadian gas to these states. Both states already have substantial pipeline inflow capacity and can receive an additional 7.2 bcf/d.

Even if the US EIA outlook does not fully materialize, it is likely to occur to some significant extent. Therefore, Canadian natural gas markets will likely grow through domestic demand growth and LNG exports only. The former is forecasted to grow by only 1.83 bcf/d from 2018 to 2040 (NEB 2017c), which is insufficient to compensate for dwindling net export volumes.

Regarding LNG opportunities, a total of 35 LNG export/import licences were issued by the NEB by the end of 2017: 28 in British Columbia, 3 in Quebec, 3 in Nova Scotia, and 1 in New Brunswick. However, only one project has received final investment decision (FID) according to the BC Oil and Gas Commission. This is the Woodfibre project in British Columbia with 0.3 bcf/d capacity. Several projects were cancelled in 2016-2017, including Pacific Northwest LNG. Simultaneously,


July 2018

the United States is expected to build more than 9 bcf/d LNG liquefaction capacity by the end of

2019 (EIA 2017).

Two projects in eastern Canada (Bear Head LNG and Goldboro LNG with a total capacity of 1.8-2.5 bcf/d) have received many approvals including environmental impact assessment and are close to taking FID. In the west, two larger projects with a total initial capacity of 3 bcf/d (LNG Canada and Kitimat LNG) have also advanced in the regulatory approvals process. LNG Canada is expected to take FID in 2018. In total, 15 LNG projects on both coasts are at different stages of activity and regulatory processes. CERI estimates that nine of them are active (a more detailed picture of Canadian LNG projects and competitiveness is available in CERI Study 172, “Competitive Analysis of Canadian LNG,” July 2018).

It is worth mentioning that Alberta represents an approximate 70% share of total Canadian

production. Since 2014, this share has been growing by 2% annually. British Columbia’s share has increased from 27% to 28%, growing by 4% annually. Saskatchewan’s share has been dropping by 3% annually, holding an approximate 2.5% share in production in 2017. Nova Scotia’s share has diminished from 2% to under 1%, decreasing by 27% annually due to production declines of the Deep Panuke project.

New Brunswick and Nova Scotia are keeping their bans on shale fracking, and Quebec has just announced (June 2018) that it will also ban fracking province-wide (Kestler-D’Amours 2018). These regulations do not allow for the local natural gas production developments which could compete with US and western Canada gas (more detailed information about the gas potential in these provinces can be found in CERI’s reports published in 2017 (CERI 2017) and 2015 (CERI 2015)).

As such, this study is a timely analysis of the supply costs and production outlook in Canada for oil and natural gas producers.

Report Structure This study provides an outlook of production for crude oil (excluding oil sands) and natural gas, production supply costs for new development, the economic impacts as well as emissions due to oil and gas production. It is an update and expansion of CERI Study 159, “Canadian Crude Oil and Natural Gas Production and Supply Costs Outlook (2016-2036),” September 2016. The expansion includes the economic impacts and emissions due to oil and gas production.

This study is divided into four chapters, with Chapter 1 providing a background, as well as defining the scope of the project. Chapter 2 discusses the Western Canadian Sedimentary Basin (WCSB)

and the province of Newfoundland and Labrador’s production forecasts and supply costs. It is subsequently divided into two parts: oil and natural gas. Both sections are further sub-divided by province.

Chapter 3 is divided into three parts:


July 2018

• The first reviews the methodology and assumptions used in modelling economic impacts, and the capital and operations investment forecasts, for two commodities (crude oil and natural gas).

• The second deals with the impacts of the Canadian oil and gas industry on Canada during the 11-year period (2018-2028). Economic impacts include economy-wide impacts such as value-added gross domestic product (GDP), job creation, and government revenues.

• Part three details GHG emissions due to oil and gas production during the study period.

Chapter 4 summarizes the results.

Appendices A and B present more detailed information on the models. Appendices C and D include detailed tables of oil and natural gas production forecasts by region and provincial maps where active drilling is taking place.


July 2018

Chapter 2: Canadian Oil and Gas Supply Costs and Production – Provincial Outlook

This chapter examines the crude oil and natural gas production forecast and associated supply costs within the Western Canadian Sedimentary Basin by province (British Columbia, Alberta, Saskatchewan, and Manitoba) as well as for the province of Newfoundland and Labrador, for the period 2018-2038. This analysis is for both onshore and offshore conventional oil, including shale and tight oil activity, conventional natural gas, coalbed methane, tight and shale gas, and the

associated natural gas liquids (pentanes plus and condensate only). Oil production out of Alberta’s oil sands is not included and can be found separately in CERI’s 2018 Annual Oil Sands Update.

In producing this forecast of drilling and production, CERI relied on and accounted for a variety of data which included historical well-licensing data, historical drilling activity in activity areas, supply costs, the ratio of horizontal and vertical wells, and industry’s interests in a resource play. CERI has accounted for the forecast of domestic demand for conventional crude oil and natural gas and exports. For the latter, the US EIA Outlook 2017 forecast was used for natural gas (US imports and exports to Canada). For exports to the US of non-oil sands oil, it was assumed that Canada’s non-oil sands oil would maintain its market share of total US imports over the study period as it was in 2016. Thus, the forecast reflects the changes in expected trade volumes of natural gas and oil between the US and Canada due to US growth of shale oil and gas volumes.

At the same time, CERI did not constrain the production outlook for any potential bottlenecks in export pipelines or current recoverable reserves estimates.

Canadian Crude Oil

Alberta Alberta’s conventional oil production has been in decline since 2014 (-9.2% CAGR), while pentanes plus and condensate output has been on the rise (20.4% over the same period). Overall production for oil (not including condensate) fell from 0.59 MMbpd in 2014 to 0.44 MMbpd in 2017.

Going forward, with the increase in oil price, CERI estimates 1,513 horizontal and vertical oil wells

will be put into production in 2018, not including cold bitumen production (CBP) or in-situ thermal (Steam Assisted Gravity Drainage, [SAGD]) producing wells. For the longer term, CERI estimates oil wells put in service to steadily increase from the current levels (1,500 per year) to approximately 2,500 wells per year in 2038, which is reflected in Figure 2.1.


July 2018

Figure 2.1: Alberta New Oil Well Forecast

Source: CERI

As shown in Figure 2.1, the increase in drilling rates is expected to occur from 2018 to 2019, which can be attributed to an expected rise in the price of oil. The number of wells then increases to

the end of the forecast period.

The new well forecast is developed based on historical well-licensing data, supply costs and knowledge of historical drilling activity in activity areas.

Given drilling expectations and forecasted decline and IP rates in the drilling areas, CERI developed a 20-year production forecast for oil production, not including oil sands production, in Alberta as shown in Figure 2.2.


July 2018

Figure 2.2: Alberta Crude Oil Production Forecast

Source: CERI, AER, PSAC, CAPP

The production rate forecast shown in Figure 2.2 has similar behaviour as the drilling rates depicted in Figure 2.1, which showed the continuous production rates for oil and condensate

(including pentane plus) during the forecast period. For crude oil production, the profile remains stable with a slight increase through the forecast period. Overall, oil production grows from 492 mbpd in 2018 to 618 mbpd by the end of 2038 (25.4 % increase). For condensate, a sharper incremental trend is expected in the first four years (2018-2021), which then becomes stable with a slight increase through the rest of the study period. Condensate production grows to 311 mbpd

in 2038 from 217 mbpd in 2018 (43% increase) and comes not only from gas wells but also oil wells. This can be attributed to the different well decline rates and the number of tied in wells.

To produce our oil production supply costs, CERI uses information contained in the 2017 Well Cost Study from the Petroleum Services Association of Canada (PSAC) as well as from the Canadian Association of Petroleum Producers (CAPP) Statistical Handbook (2017). Reference wells are assigned to each activity area and formation under study, and the well cost is calibrated

to the average historical drill depth (for the last 7 years) using true vertical depth for a vertical well and total drill depth for a horizontal well. A provision for infrastructure (field equipment) costs plus geological and geophysical costs, land costs, and enhanced oil recovery are added to the well cost.


July 2018

The EIA’s Reference Case forecast for WTI crude oil is used for all oil well forecasts done in this

report and is shown in Figure 2.3. CERI uses the WTI forecast for its assumption of the oil price growth in the supply cost model.

Figure 2.3: WTI Crude Oil Price Forecast

Source: EIA (EIA 2018a)

The EIA’s Annual Energy Outlook 2018 predicts that (in 2017 USD), the WTI price will rise to US$104/bbl by 2038 – significantly higher than the 2017 price of US$52/bbl.

The supply costs for specific areas are shown in Figures 2.4 and 2.5 with the average WTI price, Hardisty Heavy price and Edmonton Light par price overlaid for reference. The geographic locations of all Area IDs listed in the following figures, as well as throughout the rest of this report, can be found in Appendix D.


July 2018

Figure 2.4: Alberta Vertical Oil Well Supply Costs


Figure 2.5: Alberta Horizontal Oil Well Supply Costs



July 2018

In looking at the supply cost results for oil wells in Alberta, the lowest numbers belong to the

central to southeastern regions of the province, which contain many of the pipeline influence areas (PIAs), including PIA 13, 14, 11, 06, 15, 16, 14, 09, 05, 12 and 17 in both the horizontal and vertical supply cost curves. The Montney, Duvernay, and Cardium formations are, unsurprisingly, represented at the lower end of the supply cost curve. Going forward, it is expected that most of the drilling, approximately 80%, will occur in these areas. Note that Figure 2.4 and 2.5 only show the supply cost results for those regions with the cost lower than CAD$120/bbl.

British Columbia

Historically, British Columbia has not contributed substantial amounts to Canada’s total production of crude oil. Over the last five years (2013 to 2017), British Columbia has produced less than two percent of Canada’s total crude (NEB 2018). Oil production has been stable at around 20 Mbpd over 2014-2017 (NEB 2018).

For British Columbia, similar to Alberta, CERI used historical well licensing data, supply costs and knowledge of historical drilling activity in activity areas to forecast drilling for new oil wells. CERI’s forecast for conventional oil wells in British Columbia is shown in Figure 2.6.

Figure 2.6: British Columbia New Oil Well Forecast

Source: CERI, BCOGC


July 2018

CERI does not predict a significant drilling program targeting crude oil in British Columbia. The

assumption is that the province will consistently add 27 new conventional oil wells on average per year over the study period.

Given drilling expectations and forecasted decline and IP rates in the drilling areas, CERI developed a 20-year production forecast for oil in British Columbia as shown in Figure 2.7.

Figure 2.7: British Columbia Crude Oil Production Forecast

Source: CERI, BCOGC, PSAC, CAPP

CERI predicts continuous declining levels of crude production out of British Columbia owing to the generally unfavourable well supply costs and a preference for targeting NGLs-rich natural gas rather than crude oil. For the production of condensate (including pentane plus), CERI assumed scenarios in the gas production section: one with no new LNG plants and one with new LNG plants coming online in 2023 and 2025 (further details are provided in the natural gas section, BC).

As shown in Figure 2.7, the condensate production remains approximately constant until 2027 with a slow incremental trend caused by the increase in the drilling rate of gas wells through the

end of the study period. For the scenario with new LNG plants, on the other hand, the condensate production continuously increases as the drilling for natural gas for LNG plants is assumed to include NGL-rich areas. Since no significant change occurs, a stable condensate production rate is expected by the end of the forecast period (Figure 2.7).


July 2018

The well costs for specific activity areas are shown in Figures 2.8 and 2.9, with the average WTI

price, Hardisty Heavy price and Edmonton Heavy par price overlaid for reference.

Figure 2.8: British Columbia Vertical Oil Well Supply Costs


Figure 2.9: British Columbia Horizontal Oil Well Supply Costs



July 2018

The supply costs of horizontal wells are far less expensive than those of vertical wells. The three

areas shown in Figure 2.9 to have favourable average supply costs for horizontal drilling are all part of British Columbia’s Montney formation. Future oil well drilling is expected to continue to be in this formation, concentrated in the three regions identified above (in 2017, 94% of drilling in British Columbia was in the Montney area). Appendix A includes other areas that are not depicted in Figures 2.8 and 2.9, i.e., PIA 31, 33, and 34 to 45, due to their high supply costs.

Saskatchewan

Unlike Alberta, Saskatchewan’s production has not seen such a deep decline. Overall oil production decreased by 1.7% CAGR, or from 0.51 to 0.48 Mbpd from 2014 to 2017. The province has already surpassed Alberta in the number of wells drilled, and CERI predicts that the trend will be sustained in the future.

CERI uses historical well licensing data, supply costs and knowledge of drilling activity in pipeline influence areas to forecast drilling for new oil wells in the province of Saskatchewan. CERI’s forecast for conventional oil wells in Saskatchewan is shown in Figure 2.10.

Figure 2.10: Saskatchewan New Oil Well Forecast

Source: CERI, Government of SK, PSAC, CAPP


July 2018

Drilling will increase consistently through the study period, with 2038 having approximately 80

percent more drilling than 2018. Most of the activity will fall within the tight oil formations within the WCSB, in Saskatchewan’s portion of the Bakken.

Given drilling expectations and forecasted decline and IP rates in the drilling areas, CERI developed a 20-year production forecast for oil in Saskatchewan as shown in Figure 2.11.

Figure 2.11: Saskatchewan Crude Oil Production Forecast


Saskatchewan’s crude oil production forecast behaves like its drilling forecast trend. CERI predicts that oil production will remain stable until 2020 followed by a continuous incremental trend throughout the rest of the study period. In 2038, the production rate is expected to reach approximately 600 mbpd from the 2018 level of 539 mbpd (10% increase).

The average calculated well costs for specific pipeline areas are shown in Figures 2.12 and 2.13, with the average WTI price, Hardisty Heavy price and Edmonton Light par price overlaid for reference.


July 2018

Figure 2.12: Saskatchewan Vertical Oil Well Supply Costs


Figure 2.13: Saskatchewan Horizontal Oil Well Supply Costs



July 2018

While vertical wells in PIA 51 and 52 can deliver oil at supply costs below benchmark prices, the

supply costs for horizontal wells in Saskatchewan, like in Alberta and British Columbia, are generally lower than those for vertical wells, and well below the benchmark prices making them economically attractive. Horizontal drilling is expected to make up higher percentages of total drilling in the coming years.

Manitoba

Manitoba has seen its production of crude oil more than double over the last decade, reaching a peak of three percent of total Canadian crude oil production in 2013. However, it has also seen (similar to Alberta) an annual decline of 8.6% from 2014 to 2017, or from 48.3 Mbpd to 36.7 Mbpd (NEB 2018).

Like other provinces, CERI uses historical well licensing data, supply costs and knowledge of

historical drilling activity in activity areas to forecast drilling for new oil wells in Manitoba. CERI’s forecast for conventional oil wells in Manitoba is shown in Figure 2.14.

Figure 2.14: Manitoba New Oil Well Forecast

Source: CERI

CERI predicts a slight growth in Manitoba’s new oil wells during the study period (having more

than seven additional wells in 2038 with respect to 2018).

Given a slight growth in drilling and expectations and the forecasted decline and IP rates in the drilling areas, CERI developed a 20-year production forecast for oil in Manitoba as shown in Figure 2.15.


July 2018

Figure 2.15: Manitoba Crude Oil Production Forecast

Source: CERI, Government of MB, PSAC, CAPP

As drilling increases in the province over the next few years, production will also increase from 46 mbpd to almost 57 mbpd by the end of the study period (24 percent increase).

The calculated supply costs for specific areas are shown in Figures 2.16 and 2.17, with the average WTI price, Hardisty Heavy price and Edmonton Light par price overlaid for reference.

Figure 2.16: Manitoba Vertical Oil Well Supply Costs



July 2018

Figure 2.17: Manitoba Horizontal Oil Well Supply Costs


As with the other provinces in this study, the supply costs for horizontal wells are lower than those for vertical wells, except in PIA 72, where the supply cost for vertical wells is cheaper than horizontal wells. With forecasted production rates, the horizontal wells are barely economic

compared to the benchmark price (note that CERI’s supply costs include a 10% rate of return. Also note that Figures 2.16 and 2.17 only show the supply cost results for those regions with the cost lower than CAD$120/bbl).

Newfoundland and Labrador

Over the past five years (2013 to 2017), Newfoundland and Labrador has accounted for approximately sixteen percent of Canada’s total conventional crude oil per year. In 2017, Newfoundland and Labrador’s offshore projects produced 220 Mbpd (NEB 2018).

The offshore assets that have been included in the production forecast are only producing projects – Hibernia, Terra Nova, White Rose, and North Amethyst, and Hebron and approved project development extensions (White Rose South Extension). Unlike the western Canadian

provinces, CERI has assessed offshore Newfoundland and Labrador on a per-asset basis rather than per-well.

CERI used the following information available from the provincial regulator (CNLOPB) to model future forecasts for the study period: historical planned and actual production information, drilling and production forecasts from approved project development plans, initial and updated


July 2018

recoverable reserves per asset, projects’ life-spans, and assets extension plans. Figure 2.18 shows

the actual data for the number of wells and drilling and equipment cost from 2012 to 2016 for different fields in Newfoundland and Labrador including Hibernia, Terra Nova, White Rose, and Hebron, whereas the distribution of the wells among the offshore fields with the average well cost per well is depicted in Figure 2.19.

Figure 2.18: Number of Wells with Drilling and Equipment Costs, 2012-2016

Source: CERI, CAPP, and CNLOPB


July 2018

Figure 2.19: Development Wells Distribution among Fields in Newfoundland and Labrador

Source: CERI, CAPP, and CNLOPB

Over the period 2012-2016, the number of development wells peaks at 9 wells in 2013, declining to 4 wells and increasing to 10 wells in 2015 and 2016, respectively. The highest number of development wells put in service during the study period belong to the Hibernia field with an average of 5 wells per year. Total drilling and operating costs in Newfoundland and Labrador between 2012 and 2016 are $4.1 and $14.3 billion, peaking at $1.4 billion and $3.5 billion in 2014, while the average cost per well is about $106.4 million as shown in Figure 2.19.

CERI’s forecast for offshore Newfoundland and Labrador crude oil production is shown in Figure 2.20.


July 2018

Figure 2.20: Offshore Newfoundland and Labrador Crude Oil Production Forecast

Source: CERI, CNLOPB, Various individual operators

Total crude oil production will increase until 2020 as the Hebron asset is added and ramps up its output. After 2022, Hebron’s annual production is set to decline steadily throughout the study

period. The White Rose South Extension will boost provincial production in 2022-2026, returning to declining mode after that. Total annual production is expected to fall from 253 mbpd in 2018 to 48 mbpd in 2038 if no new projects are put into production.

In the coming years, Terra Nova is set to continue its production decline of approximately 0.5 million barrels per year from 11.1 million barrels per year in 2017 (30.5 Mbpd).

Hibernia is predicted to hover for several years around the level of production reached in 2017 – 53 million barrels per year (145 Mbpd). The increase from 49.7 million barrels in 2016 was reached largely due to a number of high producing wells, such as B-016-056Z, B-016-021-X, and B-016-042-Z, which produced more than 6.2 million barrels per year each. As the project keeps drilling producing wells (seven in 2017, and five in 2018 at the time of writing), this will help

maintain the archived level of production until the decline mode resumes in 2020.

White Rose and North Amethyst are predicted to gradually decline from 42.7 Mbpd in 2017 until 2022, and then ramp up to 75 Mbpd in 2024 due to an extension project. Hebron, which produced first oil in 2017, is going to increase production up to 134 Mbpd in 2022, after which the gradual decline will follow. While offshore Newfoundland and Labrador sees significant volumes of natural gas recovered alongside the oil, this gas is not produced to be sold. Any


July 2018

solution gas that is produced is currently used as fuel for oil production, re-injected to maintain

well pressure, enhanced oil recovery, or stored for potential future commercial use. One consideration is its use as a feedstock for East Coast LNG plants.

Canada

Overall in Canada, the number of wells put into production will increase through the study period, with approximately 60 percent more producing wells in 2038 (5,552) than in 2018 (3,493). The increase predominantly comes from Alberta and Saskatchewan (Figure 2.21).

Figure 2.21: Canada New Oil Well Forecast

Source: CERI, BCOGC, AER, Government of SK, Government of MB, CNLOPB, PSAC, CAPP

Similarly, Figure 2.22 illustrates total production forecasts for all provinces in Canada. In the production forecast for Canada, CERI includes the data from 2013 to 2017 (actual data) in addition to the forecast period (2018 to 2038). This assists with interpreting production fluctuations during the period of low oil prices.

It is evident that the pricing environment over 2014-2017 had its impact on the industry and led to a sharp reduction in production rates. However, from 2017 to 2025, production rebounds, reaching on average, 1.4 million bpd (without condensate), which is followed by a stable trend with a slight decrease due to the reduction in Newfoundland and Labrador to the end of the study period. By the end of 2038, total production of conventional oil is forecast to be 1.3 million bpd


July 2018

without condensate, and 1.7 million bpd with condensate production. Condensate production in

British Columbia will double if new LNG plants are built.

Figure 2.22: Canada Crude Oil Production Forecast


Natural Gas

Alberta

Alberta is a major natural gas producer in Canada. It accounted for almost 70% of total natural gas production in 2017. From 2014 to 2017, the production increased by 6.2 percent and totalled 12.5 Bcf/d.

CERI developed the new gas well forecast based on historical well-licensing data, supply costs and knowledge of historical drilling activity in activity areas. Alberta natural gas producing well

additions are shown in Figure 2.23.


July 2018

Figure 2.23: Alberta New Gas Well Additions

Source: CERI

Natural gas drilling in Alberta is expected to decrease from 1,719 tied-in wells in 2018 to approximately 700 wells in 2038. The decrease in drilling reflects lower demand for natural gas

from Alberta due to a decrease in US imports of natural gas from Canada and a simultaneous increase of US exports to Canada. While LNG projects may source natural gas from British Columbia and Alberta, particularly during the initial period, CERI makes the methodological assumption that 100% of natural gas feedstock for LNG will come from British Columbia.

Given that slight growth in drilling and expectations and forecasted decline and IP rates in the drilling areas, CERI developed a 20-year production forecast for natural gas in Alberta as shown in Figure 2.24.


July 2018

Figure 2.24: Alberta Wellhead Natural Gas Production Forecast

Source: CERI, AER

As drilling activity is set to decline during the study period, the supply of natural gas from Alberta will follow and dip from 13.9 Bcf/d in 2018 to approximately 9.3 Bcf/d in 2038. Solution gas, or associated gas, is not considered in the study forecast for Alberta, nor the other provinces. It is worth noting that approximately 10 percent of the natural gas produced in the WCSB is solution gas.

The approach to CERI’s supply costs calculation for natural gas is like oil (refer to the Crude Oil section, Alberta).

The supply costs for vertical and horizontal natural gas wells in Alberta are shown in Figures 2.25 and 2.26 against the average AECO-C prices for 2017 and forecast to 2038 (inflating the 2017 prices with an annual increase of two percent).


July 2018

Figure 2.25: Alberta Vertical Natural Gas Well Supply Costs

Source: CERI, PSAC, CAPP, NEB

Figure 2.26: Alberta Horizontal Natural Gas Well Supply Costs

Source: CERI, PSAC, CAPP, NEB


July 2018

Horizontal wells are shown to have lower supply costs and have a larger number of activity areas

whose supply costs fall below the 2017 and 2038 AECO-C prices.

When considering recent drilling intensities, the corridor to the east of the Rocky Mountains has collectively the highest concentration of activity. These formations include Alberta’s Montney, Cardium, Duvernay, Glauconitic and Beaverhill Lake as well as a collective of smaller pools. The weighted average supply cost of these Alberta areas is $1.89/mscf. Note that Figures 2.25 and 2.26 only show the supply cost results for those regions with a cost lower than CAD$5/mscf.

British Columbia

British Columbia has been a more significant player in the production of natural gas compared to crude oil. During the past decade, British Columbia has produced approximately 22 percent of total Canadian gas production.1 From 2014 to 2017, production grew by 10%, reaching 4.9 Bcf/d.

CERI uses historical well licensing data, supply costs and knowledge of historical drilling activity in activity areas to develop the new well forecast. British Columbia natural gas well additions to the producing pool are shown in Figure 2.27.

Figure 2.27: British Columbia New Gas Well Forecast

Source: CERI

1 Canadian Association of Petroleum Producers, ‘Statistical Handbook for Canada’s Upstream Petroleum Industry”, October 2017, Table 3.9.


July 2018

CERI assumed two scenarios for drilling volumes of natural gas wells and production in British

Columbia: 1) a scenario with no new LNG plants, and 2) a scenario with LNG plants. In the no LNG scenario, the number of new wells put into production is expected to remain stable in the first five years (2018 to 2022). This period is followed by a continuous incremental trend to the end of the study period. In 2038, CERI expects to see approximately 80 percent more new wells put into production than in 2018.

The number of new wells for the case with LNG plants continuously increases from 2018 to meet the demand (5 Bcf/d) with the expectation of LNG facilities being built in the province. The profile is followed by two peaks in 2023 and 2025 because of the commencement of operation of those plants. In 2027, the new additions due to LNG are expected to drop off, and the province will see a small but consistent decline of drilling through the remainder of the study period.

CERI’s production forecast for natural gas in British Columbia is shown in Figure 2.28.

Figure 2.28: British Columbia Field Gate Natural Gas Production Forecast


CERI forecasts a total increase in demand for natural gas of approximately 5 Bcf/d due to LNG projects coming online in 2023 (by 1.85 Bcf/d) and 2025 (by 3.2 Bcf/d). This amount could be perceived as optimistic, but still feasible if projects on the West Coast take FID in 2018-2020. After 2025, total production will stabilize through the remainder of the study period at approximately 9.8 Bcf/d and reach 10.1 Bcf/d in 2038.


July 2018

Supply costs for natural gas wells in British Columbia are calculated in the same manner that they

are for Alberta’s wells. The supply costs for natural gas wells, vertical and horizontal, are shown in Figures 2.29 and 2.30, respectively.

Figure 2.29: British Columbia Vertical Gas Well Supply Costs


Figure 2.30: British Columbia Horizontal Gas Well Supply Costs



July 2018

The Montney formation, with sound economics and a prolific resource base, leads British

Columbia gas developments. The average supply cost of horizontal wells in British Columbia’s Montney formation (PIA-34) is $1.87/Mcf, a close match to $1.89/Mcf in Alberta, proving its attractiveness to drillers. Since 2013, approximately 65 percent of the wells drilled in British Columbia were in its Montney formation; the ratio has grown to 94% in 2017. The remainder of the drilling has been split evenly between the rest of British Columbia’s formations, with the next highest numbers coming out of its Jean Marie formation at 5 percent. The Montney has the overwhelmingly highest concentration of activity, and it is expected that this will remain the case throughout the study period due to its favourable well economics.

Saskatchewan

Unlike Alberta and British Columbia, Saskatchewan’s natural gas production over 2014-2017 dropped by almost 9 percent and represented 0.5 Bcf/d, or 2.8 percent, of Canada’s total

production.

CERI uses historical well licensing data, supply costs and knowledge of historical drilling activity in activity areas to develop the new well forecast. Saskatchewan natural gas well additions are shown in Figure 2.31.

Figure 2.31: Saskatchewan New Gas Well Forecast

Source: CERI


July 2018

Drilling of gas wells put into production in Saskatchewan is expected to rise from current levels

of below 5 wells per year to 13 wells per year in 2023 and remain constant through the end of the study period.

CERI’s 20-year production forecast for natural gas in Saskatchewan is shown in Figure 2.32.

Figure 2.32: Saskatchewan Natural Gas Production Forecast


As with Alberta, due to the decline rates, natural gas production in Saskatchewan is expected to decline throughout the study period due to lower demand for natural gas and higher interest of drillers in Canada for other plays. The consistent addition of 13 new wells per year after 2023 is also enough to sustain a consistent decline rate as shown in Figure 2.32.

Supply costs for natural gas wells in Saskatchewan are calculated in the same manner as Alberta and British Columbia. The supply costs for vertical and horizontal wells are shown in Figures 2.33 and 2.34.


July 2018

Figure 2.33: Saskatchewan Vertical Natural Gas Well Supply Costs

Source: CERI

Figure 2.34: Saskatchewan Horizontal Natural Gas Well Supply Costs

Source: CERI


July 2018

Notwithstanding other provinces in the WCSB, the supply costs of horizontal wells in

Saskatchewan are higher than the vertical well supply costs in some areas (PIAs 56, 58, and 59) due to relatively higher decline curves and lower IP rates. Note that Figures 2.33 and 2.34 only show the supply cost results for those regions with a cost lower than CAD$5/mscf.

Canada

Considering the drilling rates for all provinces, which were estimated using historical well licensing data, supply costs and knowledge of drilling activity in pipeline influence areas, the forecast drilling for new gas wells in Canada is shown in Figure 2.35.

Overall in Canada, in the scenario without new LNG plants, the number of new wells put into production will decline throughout the study period, with approximately 60 percent fewer new wells in 2038 compared to 2018. The rates for the scenario with new LNG plants follow the same

trend as the first scenario. The number of wells for LNG account for 21% of total wells in this scenario over 20 years. Alberta and British Columbia account for almost all drilling over the next 20 years, with British Columbia’s numbers growing and Alberta’s falling; in 2038, British Columbia’s share in total new wells will account for 27%.

Figure 2.35: Canada New Oil Well Forecast



July 2018

Similarly, Figure 2.36 illustrates total production for Canada. In the production forecast, CERI

includes the data from 2013 to 2017 (actual data) in addition to the forecast period (2018 to 2038) to provide a better understanding of the trends in Canadian gas production. An incremental trend in gas production occurred during this period and was caused by two factors. First, the increase of export to the US from 2014 to 2017 (from 7.4 to 8.2 bcf/d) as well as net exports (from 5.3 to 5.8 bcf/d) (NEB 2017a). Second, an increase in domestic gas consumption by 10% over the same period (NEB 2017c). However, it is expected that the gas production rate follows a decreasing trend over the forecast period because of the declining trend of Canadian natural gas exports to the US and their increased exports to Canada (EIA 2018a).

Figure 2.36: Canada Natural Gas Production Forecast

Source: CERI, Government of SK, BCOGC, AER, PSAC, CAPP

Canadian natural gas production with new LNG plants provides an opportunity to sustain and develop production capacity in western Canada. Such a scenario will lead to a consistent increase in production until 2025 to meet demand. Post-2025, production will stabilize through the remainder of the study period and will be approximately 20 Bcf/d in 2038. The gas for LNG will

constitute approximately one-fifth of total Canadian production. Without LNG, the production of natural gas is expected to be 15.4 Bcf/d.


July 2018

Chapter 3: Canadian Oil and Gas Economic Impacts and Emissions

Economic Impacts Input/Output (I/O) analysis in general addresses the way economic circumstances in one part of an economy can ripple through the rest. It deals with inter-industry relationships, notably the use of output from one industrial process as an input into another. CERI’s model is used to determine an approximate impact on the macroeconomic with the introduction of investments (or ‘shocks’). In the case of resource or infrastructure developments, the expenditures include those for the investment and operation phases of a project. Any activity that leads to increased production

capacity in an economy has two components: a) the construction or development of the capacity, and b) the operation of the capacity to generate outputs. The first component is referred to as the investment phase, while the second is the operation phase. Both activities affect the economy through purchases of goods, services, and labour. The construction phase represents short-term activity and hence leads to short-term temporary impacts; whereas, operations and management of a facility are typically continuous. The first step is to estimate and forecast the value of the investment (i.e., construction or development expenditure) and operations. CERI has done this for the various activities. The second step is to estimate and forecast the value of total operations from those processes.

The forecasted values of investment and operations are then used to estimate demand for the various goods and services and labour used in both phases. These demands are met through two sources: domestic goods production and goods imports. Domestic contents of the goods and

services are calculated using Statistics Canada data. Impacts are calculated for Canada, broken down by province. They are presented as Gross Domestic Product (GDP) and employment. For employment, jobs are direct, or indirect. Direct jobs are those tied directly to the activity. Indirect jobs would be those where economic sectors play a support role in the activity such as financial or legal services. Induced jobs are a third category that CERI has determined that, as an indicator of economic impact, these effects are too diverse to meaningfully be attributed to any one activity. As such, going forward we will focus on direct and indirect jobs only.

There are two main assumptions underpinning the construction of an I/O model. The first assumption is that the economy is in equilibrium. Equilibrium means that the existing relationship between economic activities is constant and there are no surplus or deficits of production or need between sectors. This is a realistic assumption in the long run, as economies move to use

up surplus or create additional production to meet a need. A second important assumption in the I/O analysis is the linear relationship between inputs and outputs in the economy. Each sector uses a variety of inputs linearly to produce various final products under the assumption of fixed proportions. A very interesting aspect of this assumption is the constant return to scale. Though the linearity of the production relationship function gives a constant average and marginal products, these are justified if the analysis focuses on the medium term. Long-run changes in the


July 2018

economy (beyond 20 years) may affect the fixed relationship between sectors. CERI employs a

10-year horizon to limit the challenges of changing economic relationships between sectors.

Assumptions for Economic Impact Modeling

This section reviews the capital investments and producer’s gross revenues (operations), which are used as inputs, or injections, into CERI’s I/O model. The model, in turn, calculates the various economic impacts associated with the level of activity stemming from the outlook models over the 2018-2028 period.

The capital investment and operations forecasts are discussed by province: Alberta, British Columbia, Saskatchewan, Manitoba, and Newfoundland and Labrador. The capital investments are further illustrated by commodity (i.e., crude oil and natural gas), whereas the operations are aggregated. All monetary values are in real 2017 Canadian dollars unless stated otherwise.

Capital investments do not include oil sands-related expenditures and exploratory wells; they include only production wells and not all wells drilled in a province in each year. Economic impacts do not include natural gas liquids and condensate from wells supplying LNG projects. Figure 3.1 illustrates operations and capital investments in Alberta. Total capital investments are divided by type of commodity, whether crude oil or natural gas.

Figure 3.1: Alberta Operations and Capital Investment

Source: CERI, PSAC, CAPP


July 2018

Natural gas and crude oil capital investments in Alberta peak at $9.5 billion in 2018 and $7.2

billion in 2028, respectively. The 2018 investment levels in the conventional oil and gas are the same as 2017 levels (CAPP 2018). Annual capital costs for drilling and the connection of new natural gas and crude oil wells – including infrastructure costs plus geological and geophysical costs, land, and enhanced oil recovery – make up the capital expenditures for natural gas and crude oil. Investments include costs of drilling wells, gathering pipelines and the associated capital to construct new and sustain existing projects. The capital requirements are determined from the drilling profile converted to investment dollars using the Petroleum Services Association of Canada (PSAC) Well Cost Study and the Canadian Association of Petroleum Producers (CAPP) Statistical Handbook.

Operations (representing producer revenues) are, on the other hand, driven by the amount of oil and gas produced and the pricing for each producing asset. The shaded area in Figure 3.1

illustrates the operations from all crude oil and natural gas production (existing wells plus future new well additions). These are based on the oil and natural gas price forecast from the EIA, Annual Energy Outlook 2018, and AECO-C 2017, which have been adjusted for quality, transportation, exchange rate and are in real 2017 Canadian dollars.

Total operations in Alberta between 2018 and 2028 is $410.9 billion, growing from $25.4 billion in 2018 and peaking at $44.2 billion in 2028. Between 2018 and 2028, operations in natural gas and crude oil are $123.8 billion and $287.1 billion, respectively. Such an increase in revenues in real dollars against the fall in production of natural gas in Alberta is explained by two factors: a) growth of oil and condensate production, and b) the increase of WTI price in real dollars from US$49.5 in 2018 to $86.32 in 2028.

Figure 3.2 illustrates operations and capital investments in British Columbia. In the case of British Columbia, crude oil and natural gas are included. Over the study period (2018-2028), natural gas and crude oil capital investments in British Columbia total $28.5 billion and $754 million, respectively. Most of the capital investments in British Columbia are in the natural gas sector. Natural gas capital investments peak at $2.7 billion in 2018 and remain stable, while for crude oil, they peak at only $89 million in 2019. Total operations in British Columbia between 2018 and 2028 is $66.3 billion, peaking at $7.3 billion in 2028. Between 2018 and 2028, total operations related to natural gas is $123.8 billion, followed by $22.2 billion in crude oil. Overall growth in operations is explained by the growth of natural gas output in the province.


July 2018

Figure 3.2: British Columbia Operations and Capital Investment


Figure 3.3 illustrates operations and capital investments in Saskatchewan. Over the study period

(2018-2028), crude oil and natural gas capital investments in Saskatchewan total $40.3 billion and $22 million, respectively. Most of the capital investments in Saskatchewan are in the crude oil sector, particularly in the Bakken Formation. Crude oil capital investments peak at $3.8 billion in 2021. Capital investments for natural gas peak at only $2.2 million in 2018. Total operations in Saskatchewan between 2018 and 2028 is $203.7 billion, peaking at $21.7 billion in 2028 from $12.2 billion in 2018. Between 2018 and 2028, total operations related to crude oil is $202.7 billion, followed by only $996 million in natural gas.


July 2018

Figure 3.3: Saskatchewan Operations and Capital Investment


Figure 3.4 illustrates operations and capital investments in Manitoba. In the case of Manitoba,

only crude oil is included, with the province not producing any natural gas. Over the study period (2018-2028), crude oil capital investments in Manitoba total $3.5 billion. Crude oil capital investments peak at $359 million in 2018, declining to $296 million in 2028. Total operations in Manitoba between 2018 and 2028 is $17.9 billion, peaking at $1.9 billion in 2028 from $0.9 billion in 2018.


July 2018

Figure 3.4: Manitoba Operations and Capital Investment


Figure 3.5 illustrates operations and capital investments in Newfoundland and Labrador. In the

case of Newfoundland and Labrador, only crude oil is included, with the province not producing any natural gas. Associated natural gas is assumed to be reinjected to maintain reservoir pressure. Over the study period (2018-2028), crude oil capital investments in Newfoundland and Labrador total $7.0 billion (does not include capital costs in the coming years associated with the West White Rose Extension project). Crude oil capital investments peak at $1.1 billion in 2019, declining to $54 million in 2027. Total operations in Newfoundland and Labrador between 2018 and 2028 is $99.5 billion, peaking at $10.7 billion in 2025.


July 2018

Figure 3.5: Newfoundland and Labrador Operations and Capital Investment


Economic Impacts of Conventional Crude Oil Development

This section presents the economic impacts of conventional crude oil development including both existing and future drilling activity within the provinces of British Columbia, Alberta, Saskatchewan, Manitoba, and offshore Newfoundland and Labrador over the period 2018 to 2028. The analysis covers conventional crude, tight oil, and offshore.

Table 3.1 presents the total impacts associated with both investment and operation of crude oil (excluding oil sands) projects in British Columbia, Alberta, Saskatchewan, Manitoba, and Newfoundland and Labrador for the period 2018 to 2028. Total Canadian GDP impact is estimated to be CAD$833.9 billion (2017 Canadian dollars), with 46 percent of impacts contributed by Alberta, 27 percent by Saskatchewan, 12 percent by Newfoundland and Labrador, and the rest by other provinces and territories. Annual GDP will average approximately CAD$75.8 billion; CAD$52.3 billion in 2018, increasing to almost CAD$84.7 billion in 2028 (Figure 3.6).


July 2018

Table 3.1: Total GDP and Employment Impacts of Crude Oil Development, 2018-2028

Province GDP

($CAD million) Employment

(thousand person-years)

Alberta 386,579 843,141

British Columbia 39,412 141,779

Manitoba 23,476 52,827

Newfoundland/Labrador 103,268 140,592

Saskatchewan 225,170 365,933

Canada 833,961 1,836,268

Figure 3.6: Annual GDP Impacts of Crude Oil Development, 2018-2028


July 2018

Total employment (direct and indirect) will amount to 1,836 thousand-person years, translating

to growth from 119 thousand jobs in 2018 to 186 thousand jobs in 2028 (Figure 3.7).

Figure 3.7: Employment Impacts of Crude Oil Development, 2018-2028

Total federal government tax revenues will be CAD$68.7 billion over the 2018-2028 period. Over that period, total provincial government tax revenues will be CAD$50.3 billion (Table 3.2). On average, annual federal tax revenues will be CAD$6.2 billion, and annual provincial tax revenues will be CAD$4.5 billion. The provinces of Alberta and Saskatchewan will generate the highest shares of both federal and provincial tax revenues. Income taxes on wages constitute a larger proportion of total tax revenues than corporate taxes, both at the federal and provincial levels (Figure 3.8).

Table 3.2: Total Tax Receipts from Crude Oil Development, 2018-2028

Province Federal Tax

($CAD million) Provincial Tax ($CAD million)

Alberta 36,687 21,647


Manitoba 1,819 1,660

Newfoundland/Labrador 5,729 5,697

Saskatchewan 15,526 14,068

Canada 68,754 50,309


July 2018

Figure 3.8: Annual Tax Receipts from Crude Oil Development, 2018-2028

Economic Impacts of Natural Gas Development

This section presents the economic impacts of natural gas development, including both existing and future drilling activity within the provinces of British Columbia, Alberta, and Saskatchewan

over the period of 2018 to 2028. The analysis covers conventional, tight, shale gas, and coalbed methane, but not offshore natural gas production.

Table 3.3 presents the total impacts associated with both investment and operation of natural gas projects in British Columbia, Alberta, and Saskatchewan. Total Canadian GDP impact is estimated to be CAD$299.7 billion (2017 Canadian dollars), with 63 percent of impacts felt in Alberta, 28 percent in British Columbia, and the rest across other provinces and territories. Annual GDP growth will average approximately CAD$27.2 billion, starting at CAD$26.9 billion in 2018, increasing to CAD$29.4 billion in 2028 (Figure 3.9).

Table 3.3: Total GDP and Employment Impacts of Natural Gas Development, 2018-2028

Province GDP

($CAD million) Employment

(thousand person-years)

Alberta 188,975 431

British Columbia 83,156 252

Saskatchewan 2,716 8

Canada 299,750 820


July 2018

Figure 3.9: Annual GDP Impacts of Natural Gas Development, 2018-2028

Total employment will amount to 820 thousand-person years, translating to growth from 77 thousand jobs in 2018 to 79 thousand jobs in 2028 (Figure 3.10).

Figure 3.10: Employment Impacts of Natural Gas Development, 2018-2028


July 2018

Taxes on income are considered direct taxes, while taxes on expenditures (GST, PST, HST, etc.)

and all taxes deductible by corporations for income tax purposes (such as property taxes) are considered indirect taxes. The tax impact on a corporation includes taxes generated by economic activity within a province payable to federal, provincial, and municipal governments.

Total tax revenues generated from natural gas development in Canada to the Federal government will amount to CAD$27.9 billion; to the provincial governments approximately CAD$17.582 billion over the 2018-2028 period (Table 3.4). On average, annual federal tax revenues will be CAD$2.5 billion and provincially CAD$1.6 billion per year. The provinces of British Columbia and Alberta will generate the highest shares of both federal and provincial tax revenues. Income taxes on wages constitute a larger proportion of total tax revenues than corporate taxes, both at the federal and provincial levels (Figure 3.11). Tax revenues do not include royalty revenues.

Table 3.4: Total Tax Receipts from Natural Gas Development, 2018-2028

Province Federal Tax

($CAD million) Provincial Tax ($CAD million)

Alberta 17,984 10,636


Saskatchewan 190 177

Canada 27,978 17,582

Figure 3.11: Annual Tax Receipts from Natural Gas Development, 2018-2028


July 2018

Emissions This section presents emission forecasts from the upstream production of conventional oil and conventional and unconventional gas in Canada. Upstream emissions in this study are defined as emissions related to the upstream extraction of these hydrocarbons. Hence, emissions related to oil sands, midstream/downstream processing, and pipeline transportation are excluded. More specifically, upstream emissions encompass emissions from the following activities: drilling, production and extraction, processing in the field, and venting, flaring, and fugitive emissions.

For natural gas, methane releases (or fugitive emissions) are closely associated with well completion, equipment selection and operations. The quality of the cement and the cementing process are key to leak management before, during and after production. Valve and seal leaks are the principal sources of these emissions during the production phase of the well (during operational offsets, gas can be vented to maintain desired operational conditions, like pressure).

While there have been numerous studies on methane leaks and flaring and energy requirements to support developmental and operational phases of the gas supply chain, there is no scientific consensus.

For our analysis, CERI is using the emissions intensity of the natural gas industry derived from data published by Environment and Climate Change Canada (ECCC 2018). According to the publication, as of April 2018, total emissions from the natural gas industry were 48.6 megatonnes of carbon dioxide equivalent. Using 17.91 Bcf/d as raw natural gas production for 2016 (CanSim 2017), the resulting intensity is 7.44 tonnes CO2 eq/mmscf.

For conventional crude oil, we used data from CERI Study 167: “An Economic and Environmental Assessment of Eastern Canada Crude Oil Imports.” In particular, emissions intensity for light

crude volumes for this study is calculated as a weighted average of two emission intensity figures – mixed sweet blend and mixed sour blend. The estimated intensity is 41.12 kg CO2 eq/bbl, which is used to calculate total upstream emissions for light, medium and condensate production. For heavy oil production, an intensity of 72.4 CO2 kg eq/bbl is used for calculating upstream emissions.

CERI assumes the same ratios between heavy and light oil for all provinces according to 2017 actual production data (NEB 2018). The ratios are depicted in Figure 3.12.

It is important to note that according to historical intensity values, which have been decreasing for natural gas and crude oil, CERI considered two scenarios for emissions:

• The reference case: 2016 emission intensities were considered to be the same over the study period (no further improvement in emission intensities was assumed in the forecast).


July 2018

• The lower intensity case: According to Environment and Climate Change Canada (ECCC 2017) and the raw oil and gas production rates (CanSim 2017) for the 2012-2016 period, the annual intensity reduction for oil and gas is 1.13% and 4.6%,1 respectively. Therefore, CERI assumed that the 2016 intensities dropped with the same annual rate over the study period. Note that the decreasing trend of intensities continues until it reaches 70 percent of the 2016 intensity rates at which it is assumed to remain constant.

Figure 3.12: Percentage of Oil Type by Province

In the reference case, total emissions associated with oil production will amount to 635.7 million tonnes over the 2018-2038 period (Figure 3.13). On average, annual emissions from oil production will be 30.3 million tonnes/year during the study period. Alberta and Saskatchewan will generate the highest emissions at 45 and 40 percent, respectively (Figure 3.13). With the improved emission intensities, total annual emissions drop from 28.13 million tonnes/year in 2018 to 23.9 million tonnes/year in 2038 (on average 26.4 million tonnes/year).

1 CAGRs


July 2018

Figure 3.13: Emissions from Crude Oil Production, 2018-2028

Figure 3.14 shows total emissions associated with natural gas production for the reference case,

which is 970.4 million tonnes over the 2018-2038 period. On average, annual emissions from natural gas production will be 46.2 million tonnes/year during the study period. Alberta and British Columbia will generate the highest emissions at 70 and 28 percent, respectively. With the improved emission intensities, total annual emissions drop from 47.9 million tonnes/year in 2018 to 29.4 million tonnes/year in 2038 (on average 33.0 million tonnes/year).


July 2018

Figure 3.14: Emissions from Natural Gas Production, 2018-2028


July 2018

Chapter 4: Conclusions

The crude oil production forecast over the 2018-2038 period is characterized by rising production in response to increasing prices (Figure 4.1). It does not include production out of the territories, Ontario, New Brunswick, or Nova Scotia as these volumes are negligible.

Production levels are not expected to reach the highs seen in 2014 before the decline in oil price. Total production will experience an increase until 2025 and then remain stable through the study period, with a slight growth in western Canada being offset by the declines in offshore Newfoundland and Labrador.

On average, the provinces of Alberta and Saskatchewan will produce the highest amount of

conventional crude oil with 49 and 33 percent, respectively (Figure 4.1). The growth in crude oil production will be dominated by Alberta (25% increase from 2018), followed by Saskatchewan (10% increase from 2018) as it is expected that each province will be focusing on drilling their tight oil formation. In 2038, total conventional crude oil production will be approximately 1.3 MMbpd, whereas pentane plus and condensate production without LNG and with LNG plants would be 0.37 and 0.43 MMbpd, respectively.

Figure 4.1: Total Canadian Conventional Crude Oil Production



July 2018

Canadian natural gas production will see a declining trend from 2018 through 2038 (due to

decreased gas exports to the US and increased imports from the US). If LNG plants are constructed in British Columbia, the gas production rates will experience an increase in production in 2023 and 2025. Once production has risen to accommodate the increase in LNG demand, production remains stable with a marginal decrease through the remainder of the study period. In 2038, the production of natural gas will be 15.4 Bcf/d for the scenario with no new LNG plants, whereas it is slightly less than 20 Bcf/d for the scenario with new LNG plants.

Figure 4.2: Total Canadian Natural Gas Production

Source: CERI, NEB, BCOGC, AER, Government of SK, PSAC, CAPP

CERI has identified a number of areas where the supply costs of oil are below market prices for both commodities. For instance, in Alberta, 12 areas for vertical wells and 13 areas for horizontal wells can be profitable under $60 (or US$48) per barrel. In Saskatchewan, two areas for vertical wells and five for horizontal wells are profitable under those prices.

For natural gas, the average supply cost of horizontal wells in British Columbia’s Montney

formation is found to be $1.87/Mcf, a close match of the average $1.89/Mcf in Alberta in the Montney, Cardium, Duvernay, and other leading formations. At the same time, the majority of reference wells are not economic under current market prices. Therefore, reductions in production costs or a higher natural gas price would be necessary in order to see new investments.


July 2018

The natural gas forecast has three major uncertainties. One is the timing and the size of proposed

LNG plants in British Columbia. If none are built, this could remove approximately 5 Bcf/d of gas production. The second is the use of gas for electricity generation in Alberta. With the government’s policy of moving away from coal-fired generation, natural gas demand would likely increase. It is uncertain when that additional demand would occur and by how much. The third is US imports from Canada due to US shale gas developments. The shale gas revolution has changed the US from a net importer to a net exporter, which will reduce Canadian natural gas production due to the decrease in export volumes to the United States.

For crude oil, price is the major market uncertainty. Higher prices would stimulate more production. Another uncertainty is market access. Additional access through building the pipelines would provide alternate access to the global markets (instead of relying solely on the United States) and could also reduce the discount of western Canadian oil and bring a higher

price for Western Canadian Select (at least in the short- to medium-term). This latter uncertainty would not affect offshore Newfoundland and Labrador crude, which already has market access for its production and does not experience the land-locked discount faced in western Canada.

Despite all the above-mentioned uncertainties, the Canadian oil and gas industry is a significant contributor to provincial and national economies in Canada. Total GDP impact from investment and operations throughout the forecast period of 2018-2028 is CAD$833.9 billion for crude oil and CAD$299.7 billion for natural gas. Similarly, with government tax revenues, those collected and received from crude oil are higher in magnitude. Federal taxes from crude oil projects are approximately three times higher than those collected from natural gas projects (Figure 4.3). Provincial tax revenues follow the same pattern – crude oil related provincial taxes are higher than those for gas.

Figure 4.3: Total Tax Revenues by Commodity, 2018-2028


July 2018

Total employment impacts from all Canadian oil and gas development will materialize in every

province and territory. The largest labour impact will be felt in Alberta with 46 and 60 percent for crude oil and natural gas projects, respectively (Figure 4.4). However, companies that are suppliers of goods and services, such as machinery, manufacturing, trade, legal, environmental, financial services, often located outside of Alberta, will also benefit.

Figure 4.4: Total Employment by Province, 2018-2028

Finally, CERI’s estimations showed that the annual average emissions from oil and gas production

during the forecast period of 2018-2038 are 30.27 million tonnes CO2eq/year for crude oil and 46.2 million tonnes CO2eq/year for natural gas. To put these numbers into perspective, total average emissions for crude oil are close to 2016 levels of 30 million tonnes CO2eq/year. Natural gas production emissions are lower compared to 2016 levels of 48.6 million tonnes CO2eq/year. It is likely that emissions will be lower than those forecasted by CERI as technological improvements and energy efficiency activities have not been included.

The largest impact will be felt in Alberta with 45 and 71 percent for crude oil and natural gas production, respectively (Figure 4.5), followed by British Columbia (29%) on the gas side, and Saskatchewan (40%) on the oil side.


July 2018

Figure 4.5: Total Percentage of Emissions by Province, 2018-2038


July 2018


July 2018

Bibliography

Argus media. 2016. “News Story - Argus Media.” December 19, 2016. https://www.argusmedia.com/pages/NewsBody.aspx?id=1371418.

Bloomberg. 2018. “Macroeconomic Indicators - Financial Data - Market Data.” AssetMacro.Com. 2018. https://www.assetmacro.com/global/stock-market/bloomberg-wti-crude-oil/.

BP. 2018. “Nova Scotia | Offshore | Who We Are | Canada.” Bp.Com. 2018. https://www.bp.com/en_ca/canada/who-we-are/offshore/bp-in-nova-scotia.html.

Canadian Press. 2017. “N.W.T. Premier Issues ‘red Alert’ on ‘Colonial’ Attack on Territory’s Oil and Gas Future | CBC News.” CBC. November 1, 2017. https://www.cbc.ca/news/canada/north/nwt-premier-bob-mcleod-drilling-arctic-1.4381837.

CanSim. 2017. “Supply and Demand of Primary and Secondary Energy in Terajoules, Annual (Table: 25-10-0029-01).” 2017. https://www150.statcan.gc.ca/t1/tbl1/en/tv.action?pid=2510002901#tables.

CAPP. 2018. “CAPP Statistical Handbook - 2017 Data.” Canadian Association of Petroleum Producers. February 2018. https://www.capp.ca:443/publications-and-statistics/publications/316778.

CERI. 2015. “An Assessment of the Economic and Competitive Attributes of Oil and Natural Gas Developments in Quebec :: CERI.” December 16, 2015. https://ceri.ca/studies/an-assessment-of-the-economic-and-competitive-attributes-of-oil-and-natural-gas-developments-in-quebec.

———. 2017. “Economic Potential of Onshore Oil and Gas in New Brunswick and Nova Scotia.” July 4, 2017. https://ceri.ca/studies/economic-potential-of-onshore-oil-and-gas-in-new-brunswick-and-nova-scotia.

C-NLOPB. 2018a. “Development Plans || CNLOPB.” 2018. http://www.cnlopb.ca/information/development.php.

———. 2018b. “Statistical Information || CNLOPB.” 2018. http://www.cnlopb.ca/information/statistics.php.

———. 2018c. “Estimates of Recoverable Reserves/Resources - Hebron Field.” http://www.cnlopb.ca/pdfs/estrr_heb.pdf?lbisphpreq=1.

DiChristopher, Tom. 2018. “Saudi Arabia’s Oil Output Spikes Ahead of OPEC Meeting.” June 12, 2018. https://www.cnbc.com/2018/06/12/saudi-arabias-oil-output-spikes-ahead-of-opec-meeting.html.

ECCC, Environment and Climate Change. 2018. “Greenhouse Gas Emissions.” Research. Environment and Climate Change. June 6, 2018. https://www.canada.ca/en/environment-climate-change/services/environmental-indicators/greenhouse-gas-emissions.html.

ECCC. 2017. “National Inventory Report 1990–2015: Greenhouse Gas Sources and Sinks in Canada. Canada’s Submission to the United Nations Framework Convention on Climate Change. Part 3.” Annual Report. Canada’s Greenhouse Gas Inventory. Gatineau, QC:


July 2018

Environment and Climate Change Canada. http://unfccc.int/files/national_reports/annex_i_ghg_inventories/national_inventories_submissions/application/zip/can-2017-nir-13apr17.zip.

EIA. 2017. “United States Expected to Become a Net Exporter of Natural Gas This Year - Today in Energy - U.S. Energy Information Administration (EIA).” August 9, 2017. https://www.eia.gov/todayinenergy/detail.php?id=32412.

———. 2018a. “EIA - Annual Energy Outlook 2018.” 2018. https://www.eia.gov/outlooks/aeo/. ———. 2018b. “US EIA State-to-State Capacity.” U.S. Energy Information Administration (EIA) -

Data. 2018. https://www.eia.gov/naturalgas/data.php#pipelines. ———. 2018c. “U.S. Total Crude Oil and Products Imports.” May 31, 2018.

https://www.eia.gov/dnav/pet/pet_move_impcus_a2_nus_ep00_im0_mbbl_m.htm. Financial Post. 2018. “‘We Can Wait No Longer’: Newfoundland Unveils Plans to Double Oil

Production by 2030.” Financial Post (blog). February 19, 2018. http://business.financialpost.com/commodities/energy/n-l-unveils-plan-for-faster-cheaper-offshore-oil-and-gas-development.

Government of Alberta. 2017. “Enhanced Hydrocarbon Recovery Program.” 2017. http://www.energy.alberta.ca/AU/Royalties/Pages/EHRecovery.aspx.

———. 2018a. “Modernized Royalty Framework : Formulas - Open Government.” 2018. https://open.alberta.ca/publications/modernized-royalty-framework-formulas.

———. 2018b. “Royalty Information.” 2018. http://www.energy.alberta.ca/NG/RI/Pages/default.aspx.

Government of British Columbia. 2018. “Natural Gas Royalties - Province of British Columbia.” 2018. https://www2.gov.bc.ca/gov/content/taxes/natural-resource-taxes/oil-natural-gas/oil-gas-royalty/understand/natural-gas#royalty-rate.

Government of Manitoba. 2018. “Manitoba Petroleum Fiscal Regime | Petroleum | Growth, Enterprise and Trade | Province of Manitoba.” 2018. http://www.manitoba.ca/iem/petroleum/regime/index.html.

Government of Saskatchewan. 2018. “Crown Royalty and Freehold Production Tax Programs and Payments | Oil and Gas Incentives, Crown Royalties and Taxes.” Government of Saskatchewan. 2018. https://www.saskatchewan.ca/business/agriculture-natural-resources-and-industry/oil-and-gas/oil-and-gas-incentives-crown-royalties-and-taxes/crown-royalty-and-freehold-production-tax-forms-and-directives.

IEA. 2017. “World Energy Outlook 2017.” 2017. https://www.iea.org/weo2017/. Jaremko, Deborah. 2018. “Canadian Crude by Rail Surges to Highest since 2014 | Pipelines &

Transportation.” JWN Energy. May 28, 2018. http://www.jwnenergy.com/article/2018/5/canadian-crude-rail-surges-highest-2014/.

Kestler-D’Amours, Jillian. 2018. “Quebec to Ban Shale Gas Fracking, Tighten Rules for Oil and Gas Drilling | CBC News.” CBC. June 6, 2018. https://www.cbc.ca/news/canada/montreal/quebec-fracking-ban-1.4694327.

MCINTOSH, JEFF. 2017. “NEB Approves TransCanada’s Mainline Shipping Deal,” September 21, 2017. https://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/neb-approves-transcanadas-mainline-shipping-deal/article36356883/.

NEB. 2017a. “NEB – 2017 Natural Gas Exports and Imports Summary.” 2017. https://www.neb-one.gc.ca/nrg/sttstc/ntrlgs/rprt/ntrlgssmmr/ntrlgssmmr-eng.html.


July 2018

———. 2017b. “NEB – Pipeline Profiles: TransCanada Mainline.” April 20, 2017. https://www.neb-one.gc.ca/nrg/ntgrtd/pplnprtl/pplnprfls/ntrlgs/trnscndmnln-eng.html.

———. 2017c. “NEB – Canada’s Energy Future 2017: Energy Supply and Demand Projections to 2040.” October 25, 2017. https://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2017/index-eng.html.

———. 2018. “NEB – ARCHIVED - Estimated Production of Canadian Crude Oil and Equivalent.” February 20, 2018. https://www.neb-one.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/archive/stmtdprdctnrchv-eng.html.

OGJ. 2017. “IEA Forecasts Possible Oil Undersupply, Price Spike after 2020 - Oil & Gas Journal.” Oil & Gas Journal. March 6, 2017. https://www.ogj.com/articles/2017/03/iea-forecasts-oil-undersupply-price-spike-after-2020.html.

PSAC. 2018. “Well Cost Study | PSAC.” 2018. http://www.psac.ca/resources/well-cost-study-overview/.

Wingfield, Brian, Samuel Dodge, Cedric Sam, and Alaric Nightingale. 2018. “OPEC Agrees to Boost Output at Crucial Vienna Meeting.” Bloomberg.Com, 2018. https://www.bloomberg.com/graphics/opec-production-targets/.

Withers, Paul. 2016. “Shell Abandons Dry Oil Well off Nova Scotia’s Coast | CBC News.” CBC News. September 21, 2016. http://www.cbc.ca/news/canada/nova-scotia/cost-shell-ns-dry-hole-topped-million-1.3772266.


July 2018


July 2018

Appendix A: Natural Gas and Crude Oil Production Forecasts and Supply Cost Methodologies

Natural Gas Production Forecast and Supply Cost Methodology The production forecast in this study is an update from CERI Study 159, “Canadian Crude Oil and Natural Gas Production and Supply Costs Outlook (2016-2036)”, released in September 2016. CERI completed supply cost calculations, explained below, which populated the production forecast.

In producing this forecast of drilling and production, CERI relied on and accounted for a variety of data which included historical well-licensing data, historical drilling activity in activity areas, supply costs, the ratio of horizontal and vertical wells, and industry’s interests in a resource play. CERI has accounted for the forecast of domestic demand for conventional crude oil and natural gas and exports. For the latter, the US EIA Outlook 2017 forecast was used for natural gas (US imports and exports to Canada). For exports to the US of non-oil sands oil, it was assumed that Canada’s non-oil sands oil would maintain its market share of total US imports over the study period as it was in 2016. Thus, the forecast reflects the changes in expected trade volumes of natural gas and oil between the US and Canada due to US growth of shale oil and gas volumes.

At the same time, CERI did not constrain the production outlook for any potential bottlenecks in export pipelines or current recoverable reserves estimates.

The supply cost calculations done in this study were also used in CERI Study 159. The supply cost method has not changed, and the assumptions with the royalties have been updated to reflect their changes in 2017.

The WCSB supply costs represent the natural gas price (in real 2017 dollars) required by producer project to receive each year to recover all capital expenditures, operating costs, royalties, taxes, and a specified return on investment for each well.

The supply cost is calculated with a cash flow model where net cash flow equals total revenue less any costs and other payments such as taxes and royalties. The revenues for gas wells do not include sales from NGLs, while revenues from oil wells do not include sales from associated gas.

The net cash flow is discounted back over the lifetime of the well (on average 25 years) to the first time period (2017) using a specified discount rate of 10 percent, thereby allowing the price of natural gas to vary and solve for the supply cost. The supply cost is the gas price that sets the Net Present Value (NPV) of the cash flows to zero.


July 2018

Each well is considered operational when the gross revenue is greater than the operating costs

and royalties. If revenue falls below these costs, the well is shut off and the economic evaluation is conducted for that time-period only.

Historical trends in the number of wells per pad are incorporated into the supply costs to account for economies of scale.

Production Inputs

Historical well data were used to calculate the 2017 production inputs. Information was collected from the Alberta Energy Regulator (AER), the Government of Saskatchewan and the BC Oil and Gas Commission (BCOGC) that details the historic production of hydrocarbon fluids as well as general well characteristics, such as completion date, initial production rate, total depth, true vertical depth, and location.

Cost Inputs

● Drilling and completion costs were estimated from well-specific data provided by the Petroleum Services Association of Canada (PSAC) (PSAC 2018). Drilling and completion costs per metre drilled were estimated for each area and then applied to each area given the assumed well depth.

● Geological, geophysical, tie-in costs (infrastructure), EOR and land costs were all derived from data sourced from the Canadian Association of Petroleum Producers (CAPP) (CAPP 2018).

● Operating costs were estimated from CAPP at the provincial level (CAPP 2018). ● Royalties were derived for all wells consistent with the regulations for natural gas

royalties across the three provinces (Government of Alberta 2018b; Government of British Columbia 2018; Government of Saskatchewan 2018)

o Alberta’s 2015 Royalty Review is important to note. Royalties on new natural gas wells will be at 5 percent until cumulative revenues equal the well’s Drilling and Completion Cost Allowance. This Drilling and Completion Cost Allowance is a function of the well’s vertical depth and lateral length, giving credit for the higher cost associated with drilling deeper than a set threshold. Wells shallower than or equal to 2,000 metres are treated differently than wells deeper than 2,000 metres (Government of Alberta 2018a).

● Within the supply cost model, federal corporate income tax rates were assumed constant at 15 percent. Alberta and Saskatchewan income tax rates were assumed to be constant at 12 percent, and British Columbia income tax rates were assumed to be constant at 11 percent.

Other Economic Assumptions

● The inflation rate applied to operating costs is assumed to be 2 percent per annum, which is within the Bank of Canada’s target inflation of 1-3 percent.

● The results are presented in Canadian dollars in real terms in 2017 dollars. The Canadian dollar was assumed to be 80 cents/USD over the next 20 years.


July 2018

● Supply costs are calculated as field-gate costs, that is, they do not include transportation or processing costs.

● Gas supply costs are presented as Canadian dollars per thousand cubic feet of natural gas ($/mcf).

● The natural gas price is assumed to increase at 2 percent per annum.

Crude Oil Production: Western Canada Forecast and Supply Cost Methodology The production forecast in this study is an update from CERI Study 159, “Canadian Crude Oil and Natural Gas Production and Supply Costs Outlook (2016-2036)”, released in September 2016. The methodology for supply forecast and supply cost calculations have not changed, and the assumptions used have been updated to reflect their changes over time.

The supply cost represents the oil price (in real 2017 dollars) required to recover all capital expenditures, operating costs, royalties, taxes, and a specified return on investment for each well.

The supply cost is calculated with a cash flow model where net cash flow equals total revenue less any costs and other payments such as taxes and royalties.

The net cash flow is discounted back over the lifetime of the well (on average 20 years) to the first time period (2017) using a specified discount rate of 10 percent (real), thereby allowing the price of oil to vary and solve for the supply cost. The supply cost is the oil price that sets the Net Present Value (NPV) of the cash flow to zero.

Each well is considered operational while production rates are 3 bbls/d or greater and the gross

revenue is greater than the sum of operating costs and royalties. Otherwise, the well is shut off and the economic evaluation is conducted for that time-period only.

Companies may evaluate individual projects and investments using higher or lower discount rates

than those used in this analysis. This would result in higher or lower supply costs than those presented here.

The analysis has been undertaken for several study areas, and the results represent the supply cost for a “typical well” located in each area.

Historical trends in the number of wells per pad are incorporated into the supply costs to account for economies of scale.

Production Inputs

Historical well data were used to calculate the production inputs. Information was collected from the AER, the Government of Saskatchewan, the BC Oil and Gas Commission (BCOGC) and the Government of Manitoba that details the historic production of hydrocarbon fluids as well as


July 2018

general well characteristics, such as completion date, initial production rate, total depth, true

vertical depth, and location.

• The initial production (IP) rates for new wells considered the IP rates of wells that were drilled from the years 2010 through 2016. A curve was derived for each area and is used to establish the different IPs for the forecasted years.

• Production decline parameters were derived from historical monthly production rates from wells drilled between 2010 and 2016. A “type” curve was derived for each area and is used to establish the production decline profile for all new wells.

• The average depth of new wells for each area was calculated from an average of the last ten years of wells drilled.

Cost Inputs

• Drilling and completion costs were estimated from data provided by the Petroleum Services Association of Canada (PSAC) (PSAC 2018). Drilling and completion costs per metre drilled were estimated for each area and then applied to each area given the assumed well depth.

• Geological, geophysical, tie-in costs (infrastructure) and land costs were all derived from data sourced from CAPP. These were derived at the provincial level, so they do not vary between areas or wells (CAPP 2018).

• EOR costs and land costs were estimated by CAPP at the provincial level and are assumed to be constant per barrel of oil produced (CAPP 2018).

• Operating costs were estimated by CAPP at the provincial level and are assumed to be constant per barrel of oil produced (CAPP 2018).

• Royalties were derived for all wells consistent with the regulations for oil royalties across the four provinces (Government of Alberta 2018b; Government of British Columbia 2018; Government of Saskatchewan 2018; Government of Manitoba 2018).

o As well-specific recovery methods are unknown, the Enhanced Hydrocarbon Recovery Program (Government of Alberta 2017) was not considered in the royalty calculations.

• Within the supply cost model, federal corporate income tax rates were assumed constant at 15 percent. Alberta and Saskatchewan income tax rates were assumed to be constant at 12 percent, British Columbia income tax rates were assumed to be constant at 11 percent, and Manitoba income tax rates were assumed to be constant at 12 percent.

Other Economic Assumptions

• Economic assumptions for the crude oil supply forecast and supply cost calculations were consistent with the assumptions used in the natural gas models.

• The oil price is assumed to increase at 3.0 percent per annum (EIA 2018a).


July 2018

Crude Oil Production: Offshore Newfoundland and Labrador Forecast and Supply Cost Methodology The production profile for the Newfoundland and Labrador offshore assets comprises aggregated profiles of producing assets: Hibernia, Terra Nova, White Rose, North Amethyst, and Hebron producing assets as well as all officially approved for development extensions of these projects.

Production Profile Inputs

To establish per asset production profiles, the following inputs were used:

a) Recoverable reserves. For most assets, the C-NLOPB latest reserves estimation (May 2018) was used. For the Hebron project, Operator estimation of reserves was used from Development Plan of 2011. For the perspective asset, an assumption of recoverable reserves had to be made based on best available information issued by Operators in the public domain.

b) Produced up to date reserves. Historical production published by C-NLOPB was used. c) Project life. Due to the maturity of all producing assets and the number of extension

projects underway, a mix of data on project finish year was considered based on approved Development Plans and Amendments, C-NLOPB as well as estimations of Operator’s representatives, usually presented at regional offshore conferences. An economic cut-off level, used in Development plans or Amendments per project, was also taken into consideration while modelling a production profile.

d) Production profile per asset from 2016 to project life finish. The general approach was to rely on the latest approved Development plan or Amendment (hereinafter referred to as Project file) per each asset to obtain a production profile (excluding perspective asset, which lacks such a file). In cases where current remaining reserves estimation or project life finish year was different compared to the latest Project file, appropriate adjustments were made to Operators latest production forecast, which would a) produce remaining reserves, b) get to estimated project finish year and c) finish upon reaching economic cut-off. If no such adjustment were needed, as in the case of Hebron, the latest Operator’s production forecast was used. For a new perspective asset, due to lack of information, production profile, time to first oil after appraisal drilling finish, and project life were assumed based on closest analogues out of Newfoundland and Labrador producing assets.

e) Historical production per well. Historical production per well per asset for the last 3 years and drilling of new wells in 2016-2018 to better estimate production in 2018-2020.

Production Profile Assumptions

• No gas production is modelled irrespective of the presence of gas reserves for producing assets. The reasons behind this are that no Development Plan or Amendment currently contain approved gas project plans. Based on available data in C-NLOPB documents (decisions and staff analysis), some Operators will or already do explore potential commercial gas projects and technologies, including at the request of C-NLOPB, that this data be incorporated into perspective gas production forecasts only upon becoming available.


July 2018


July 2018

Appendix B: Input-Output Model

This appendix discusses the multi-stage process to build CERI’s Canada Multiregional Input-Output Model (the CMRIO 4.0 model). The section is divided into two parts: the development of the CMRIO 4.0 and the economic sectors covered in the CMRIO 4.0.

CERI CMRIO 4.0 The following illustrates how the CMRIO 4.0 was developed, and how one can trace direct, indirect, and induced effects of the Canadian energy sector on the Canadian economy. The model provides insights at the provincial and national levels for Canada. The base year for the I/O tables is 2011, as this is the latest symmetric table provided by Statistics Canada.

Compilation of the national CMRIO 4.0 includes the following:

1) Statistics Canada provides S level Symmetrical I/O tables (SIOTs) and Final Demand tables for 13 provinces and territories plus Government Abroad. Therefore, there are 14 regional tables for Canada plus one national table. Provincial data are only available at the S level due to confidentiality of more disaggregated data for some sectors in various provinces. The I/O tables used are at producer’s prices (Basic Prices), meaning that CERI did not construct symmetrical tables from the Use and Make tables, as the compiled tables were available. As previously mentioned, the base year for the I/O tables is 2011.1

2) SIOTs are balanced. Hence, the use of inputs in the economy is equal to the production of outputs.

3) To highlight the energy sectors in the Canadian provincial SIOTs, CERI disaggregated the “Mining and Oil and Gas Extraction’’ industry into five subsectors: Conventional Oil, Oil Sands, Natural Gas and NGLs, Coal, and Other Mining. In the same fashion, the manufacturing sector is divided into three subsectors: Refinery, Petrochemical, and Other Manufacturing.

4) It is important to note that the construction sector in this version is already split into the following five sub-sectors by Statistics Canada: Residential Construction, Non-residential Building Construction, Engineering Construction, Repair Construction, and Other Activities of the Construction Industry.

5) CERI combines the SIOTs (13 provincial tables, and one for Government Abroad) to compile one national I/O matrix. The national matrix is then inverted to generate direct, indirect, and induced effect multipliers.

The following is a brief discussion of the modelling.

Based on a standard I/O model notation, and considering total gross outputs vector (X) and final demand vector (FD), the following relationship in I/O context holds as:

1Use tables show the inputs to industry production and commodity composition of final demand. Make tables show the commodities that are produced by each industry.


July 2018

AX+FD = X→(I-A)X=FD → X= (I-A)-1FD→ X= L.FD (Equation 1)

Where: A = the matrix of input coefficients (n×n), I = identity matrix (n×n), and L = the Leontief inverse matrix (n×n).

This is the core formula of the Leontief quantity model. This relationship estimates direct and indirect impacts on a single economy (i.e., no trade flow). CERI can expand this model to include induced effects by endogenizing the most important component of final local demand, namely private consumption. This captures the economic impact of increased consumption due to earned wages from new jobs.

After endogenizing the private consumption expenditure, CERI arrives at the following relationship:

X = (I-Aind)-1FD* (Equation 2)

CERI endogenizes the household’s private consumption expenditures and earnings by adding one column and one row to every province which then creates a new matrix of input coefficients as labelled Aind. This relationship estimates direct and indirect impacts.

CERI can extend the model to involve other economies (regions) by incorporating the interregional trade flow matrix C(n×n). After several steps of calculation, we arrive at the final interregional formula:

X = (I-C.Aind)-1C.FD* (Equation 3)

The above equation to have a finite solution, (I-C.Aind) must be a non-singular matrix. As is the case for standard I/O models, the impact of an industry, such as the oil sands industry, is calculated by modelling the relationship between total gross outputs and final demand as follows:

∆X = (I-C.Aind)-1C.∆FD* (Equation 4)

Where:

X – Changes (or increases) in total gross outputs of all provinces and territories, at the sectoral

level, due to construction and operation of projects (i.e., oil sands). Dimension is either n=485 or 500. As a result, this vector is a 485x1 or 500×1 vector.

I – is a 485x485 or 500×500 identity matrix, unity for diagonal elements and zero for off-diagonal elements.


July 2018

A – is a 485×485 block diagonal matrix of technical coefficients at the sectoral level for Canada.

It is composed of 14 blocks of 33×33 matrix corresponding to each province (or territory’s) input technical coefficient matrix.2 An element of such a matrix is derived by dividing the value of a commodity used in a sector by the total output of that sector. The element represents requirements of a commodity in a sector in order to produce one unit of output from that sector.

Aind – is a 500×500 block diagonal matrix of technical coefficients at the sectoral level for Canada. It is composed of 14 blocks of 34×34 matrix corresponding to each province’s (or territory’s) input technical coefficient matrix.3 An element of such a matrix is derived by dividing the value of a commodity or household expenditure and earnings used in a sector by the total output of that sector or household expenditure. The element represents requirements of a commodity in a sector in order to produce one unit of output from that sector.

C – is a 485x485 or 500×500 transposed matrix of multiregional trade coefficients. It includes import and export shares of a sector’s total output in a province or territory. Each element on the row of this matrix measures the share of export to a particular sector in a province from a given sector in another province or territory.

FD* – is a 485x1 or 500×1 vector of changes (or increases) in the exogenous part of final demand at the sectoral level. Outputs from Canada resulted from any change in the final demand components in any province or territory, including commodities directly demanded (or purchased) for the construction and development of any sector.

The calculation of the total impact is based on the multiplication of direct impact and the inverted matrix. Based on the direct impact on a sector, Equation 4 above is used to estimate all the direct,

indirect, and induced effects on all sectors in all provinces, particularly in terms of changes in consumption, imports, exports, production, employment, and net taxes. The direct impact is referred to as ∆FD* in Equation 4. The change in final demand (∆FD*) consists of various types of investment expenditures, changes in inventories, and government expenditures. In the current model, the personal expenditures are not part of the final demand and have been endogenized to accommodate the induced impact.

Direct impacts are quantitative estimations of the main impact of the programs, in the form of an increase in final demand (increase in public spending, increase in consumption, increase in infrastructure investment, etc.). The assumption of increased demand includes a breakdown per sector so that it can be translated into the following matrix notation:

2In other words, one can say all 14 Canadian tables (13 provinces and one Government abroad) technical coefficients matrices are stacked together in construction of a diagonal block matrix at the national level. 3ibid.


July 2018

Direct, indirect, and induced impacts:

∆ X= (I-C.Aind)-1C.∆FD* (Equation 5)

Direct and indirect impacts:

∆ X= (I-C.A)-1C.∆FD (Equation 6)

The difference between Equation 5 and 6 is referred to as the induced impact of any changes in final demand components.

Once the impact on output (change in total gross outputs) is calculated, the calculation of impacts on GDP, household income, employment, taxes, and so forth, are straightforward. As previously

mentioned, the base year for the I/O tables is 2011. CERI utilizes the tax information derived from these tables and federal and provincial tax information from the Finances of the Nation, where these numbers reflect the tax structure of the Canadian economy in the year 2011. CERI acknowledges that there have been changes, and there would be imminent changes to the corporate income tax structure and the goods and services sales tax (GST) since 2011. Any changes to the tax regime will result in changes in estimated tax figures as business responds to the new incentives. Therefore, tax estimates should be interpreted on a 2011 basis.

These impacts are estimated at the industry level using the ratio of each (GDP, employment, etc.) to total gross outputs. Using the technical Multi-Regional I/O table, CERI can perform the usual I/O analysis at the provincial and national levels.


July 2018

Industries in the CMRIO 4.0 This section illustrates the various classification of industries in the CMRIO 4.0. Table B.1 also provides a brief description of the 34 sectors or commodities.

Table B.1. Sectors/Commodities in CERI Canada Multi-Regional I/O Model

Serial No. Sector or Commodity Examples of Activities Under the Sector or Commodity

1 Crop and Animal Production Farming of wheat, corn, rice, soybean, tobacco, cotton, hay, vegetables and fruits; greenhouse, nursery, and floriculture production; cattle ranching and farming; dairy, egg and meat production; animal aquaculture

2 Forestry and Logging Timber tract operations; forestry products: logs, bolts, poles and other wood in the rough; pulpwood; custom forestry; forest nurseries and gathering of forest products; logging

3 Fishing, Hunting and Trapping Fish and seafood: fresh, chilled, or frozen; animal aquaculture products: fresh, chilled, or frozen; hunting and trapping products

4 Support Activities for Agriculture and Forestry

Support activities for crop, animal and forestry productions; services incidental to agriculture and forestry including crop and animal production, e.g., veterinary fees, tree pruning, and surgery services, animal (pet) training, grooming, and boarding services

5 Conventional Oil4 Conventional oil, all activities e.g., extraction and services incidental to conventional oil

6 Oil Sands Oil sands, all activities e.g., extraction and services incidental to oil sands

7 Natural Gas and NGL Natural gas, NGL, all activities e.g., extraction and services incidental to natural gas and NGL

8 Coal Coal mining, activities and services incidental to coal mining

9 Other Mining Mining and beneficiating of metal ores; iron, uranium, aluminum, gold and silver ores; copper, nickel, lead, and zinc ore. Mining; non-metallic mineral mining and quarrying; sand, gravel, clay, ceramic and refractory, limestone, granite mineral mining and quarrying; potash, soda, borate and phosphate mining; all related support activities

10 Utilities Electric power generation, transmission, and distribution; natural gas distribution; water & sewage

4Statistics Canada reports the oil, gas, coal, and other mining as one sector due to some confidentiality issues. CERI uses an in-house developed approach to disaggregate this sector into to five sectors: oil sands, conventional oil, natural gas + NGL, coal, and other mining.


July 2018


11 Residential Construction Residential building construction

12 Non-residential Building Construction

Industrial, commercial, and institutional buildings

13 Engineering Construction Engineering construction includes transportation, oil and gas, electric power, communication, and other engineering construction

14 Repair Construction Repairing and renovating construction

15 Other Activities of the Construction Industry

Other activities of the construction industry

16 Refinery Petroleum and coal products; motor gasoline and other fuel oils; tar and pitch, LPG, asphalt, petrochemical feedstocks, coke; petroleum refineries

17 Petrochemical Chemicals and polymers: resin, rubber, plastics, fibres and filaments; pesticides and fertilizers; etc.

18 Other Manufacturing Food, beverage, and tobacco; textile and apparel; leather and footwear; wood products; furniture and fixtures; pulp and paper; printing; pharmaceuticals and medicine; non-metallic mineral, lime, glass, clay and cement; primary metal, iron, aluminum and other metals; fabricated metal, machinery and equipment, electrical, electronic and transportation equipment, etc.

19 Wholesale Trade Wholesaling services and margins

20 Retail Trade Retailing services and margins

21 Transportation and Warehousing

Roads, railways; air, water & pipeline transportation services; postal service, couriers and messengers; warehousing and storage; information and communication; sightseeing & support activities

22 Information and Cultural Industries

Motion picture and sound recording; radio, TV broadcasting and telecommunications; publishing; information and data processing services

23 Finance, Insurance, Real Estate and Rental and Leasing

Insurance carriers; monetary authorities; banking and credit intermediaries; lessors of real estate; renting and leasing services

24 Owner Occupied Dwellings Owner-occupied dwellings

25 Professional, Scientific and Technical Services

Advertising and related services; legal, accounting and architectural; engineering and related services; computer system design


July 2018


26 Administrative and Support, Waste Management and Remediation

Travel arrangements and reservation services; investigation and security services; services to buildings and dwellings; waste management services

27 Educational Services Universities; elementary and secondary schools; community colleges and educational support services

28 Health Care and Social Assistance

Hospitals; offices of physicians and dentists; Misc. ambulatory health care services; nursing and residential care facilities; medical laboratories; child and senior care services

29 Arts, Entertainment and Recreation

Performing arts; spectator sports and related industries; heritage institutions; gambling, amusement, and recreation industries

30 Accommodation and Food Services

Traveller accommodation, recreational vehicle (RV) parks and recreational camps; rooming and boarding houses; food services and drinking establishments

31 Other Services (Except Public Administration)

Repair and maintenance services; religious, grant-making, civic, and professional organizations; personal and laundry services; private households

32 Non-Profit Institutions Serving Households

Religious organizations; non-profit welfare organizations; non-profit sports and recreation clubs; non-profit education services and institutions

33 Government Sector Hospitals and government nursing and residential care facilities; universities and government education services; other municipal government services; other provincial and territorial government services; other federal government services including defence

34 Household (Labour) Household labour


July 2018

Canadian Crude Oil and Natural Gas Production, Supply Costs 81 Economic Impacts and Emissions Outlook (2018-2038)

July 2018

Appendix C: Production Forecasts

Oil and Condensate Production Forecasts

Table C.1: Oil and Condensate Production Forecast (bpd)

Year AB-Oil

AB-Pentane Plus and Condensate Production

SK-Oil BC-Oil

BC-Pentane Plus and Condensate Production

BC- Pentane Plus and Condensate Production with LNG

MB-Oil NL-Oil Canada-Oil

Canada-Pentane Plus and Condensate Production

Canada-Pentane Plus and Condensate Production with LNG

2013 581,994 429,397 484,712 19,901 21,506 21,506 51,973 229,004 1,367,585 450,903 450,903

2014 589,305 439,602 512,724 21,421 27,955 27,955 48,335 215,688 1,387,471 467,557 467,557

2015 530,247 393,484 486,462 21,116 33,733 33,733 45,807 172,013 1,255,645 427,217 427,217

2016 445,335 327,657 459,452 23,256 26,789 28,052 40,077 209,667 1,177,786 354,446 355,709

2017 442,955 251,479 482,616 21,072 46,261 47,073 38,846 220,738 1,206,227 297,740 298,552

2018 492,758 217,704 539,459 20,891 42,602 45,746 46,231 253,621 1,352,960 260,306 263,450

2019 510,741 230,017 540,993 19,906 41,524 47,385 47,245 297,797 1,416,682 271,541 277,402

2020 519,568 248,710 539,208 19,028 41,220 51,283 47,870 303,512 1,429,185 289,930 299,993

2021 522,494 283,569 541,964 18,129 41,366 53,975 48,285 282,769 1,413,640 324,935 337,544

2022 521,399 302,323 545,407 17,296 41,757 56,231 48,620 269,695 1,402,418 344,080 358,553

2023 520,717 305,309 546,251 16,539 42,199 68,216 48,931 291,862 1,424,299 347,507 373,525

2024 518,229 310,792 546,347 15,854 42,783 70,363 49,242 284,189 1,413,861 353,575 381,155

2025 518,927 314,631 546,250 15,280 43,442 113,864 49,713 288,013 1,418,183 358,072 428,495

2026 514,232 313,952 546,125 14,689 44,599 114,163 49,956 266,293 1,391,295 358,551 428,116

2027 515,381 313,432 546,113 14,165 45,667 115,202 50,300 224,685 1,350,644 359,099 428,634

2028 520,051 315,190 547,210 13,689 46,712 116,549 50,725 198,586 1,330,261 361,903 431,740

2029 527,329 315,357 549,588 13,252 47,862 117,930 51,225 175,342 1,316,735 363,219 433,286

2030 533,620 311,444 552,755 12,849 49,127 119,065 51,770 158,441 1,309,435 360,571 430,510


July 2018

2031 541,965 311,444 556,600 12,477 50,367 119,994 52,352 121,292 1,284,687 361,811 431,438

2032 549,864 311,444 561,054 12,132 51,711 120,813 52,971 113,950 1,289,970 363,155 432,257

2033 559,827 311,444 566,061 11,811 52,904 121,317 53,621 99,382 1,290,701 364,348 432,761

2034 568,393 311,444 571,492 11,512 54,019 121,827 54,298 86,735 1,292,430 365,463 433,271

2035 579,405 311,444 577,375 11,233 55,158 122,140 55,006 77,030 1,300,049 366,602 433,585

2036 591,167 311,444 583,688 10,971 56,532 122,359 55,743 67,125 1,308,694 367,976 433,803

2037 604,444 311,444 590,354 10,726 57,710 122,399 56,506 57,720 1,319,750 369,154 433,843

2038 618,038 311,444 597,434 10,497 58,689 122,385 57,295 48,715 1,331,979 370,133 433,829


July 2018

Gas Production Forecasts

Table C.2: Natural Gas Production Forecast (mmscf/d)

Year AB SK BC BC-Additional Gas Production for LNG Projects

Canada Canada with LNG

2013 11,395 536 4,312 16,243 16,243

2014 11,735 563 4,568 16,866 16,866

2015 12,070 561 4,738 17,369 17,369

2016 12,174 519 4,908 17,601 17,601

2017 12,465 513 4,988 17,965 17,965

2018 13,913 523 4,964 277 19,400 19,677

2019 13,303 501 4,710 488 18,514 19,002

2020 12,794 484 4,570 754 17,848 18,602

2021 12,665 470 4,500 920 17,635 18,555

2022 12,739 459 4,468 1,043 17,666 18,709

2023 12,522 450 4,458 2,340 17,430 19,770

2024 12,453 442 4,467 2,446 17,362 19,808

2025 12,368 436 4,492 4,928 17,296 22,224

2026 12,281 430 4,565 4,855 17,276 22,132

2027 12,011 425 4,635 4,854 17,071 21,925

2028 11,832 421 4,707 4,876 16,961 21,836

2029 11,650 417 4,794 4,893 16,861 21,754

2030 11,498 414 4,891 4,884 16,803 21,686

2031 11,463 411 4,988 4,862 16,862 21,724

2032 11,032 408 5,095 4,823 16,535 21,357

2033 10,884 406 5,194 4,774 16,484 21,258

2034 10,483 403 5,290 4,729 16,177 20,905

2035 10,323 401 5,391 4,666 16,115 20,781

2036 10,031 399 5,513 4,576 15,943 20,519

2037 9,584 398 5,622 4,489 15,603 20,092

2038 9,377 396 5,716 4,415 15,489 19,905


July 2018


July 2018

Appendix D: Study Supply Areas Table D.1 describes the study areas used to estimate production and supply costs. Figures D.1-D.4 show the maps of drilling natural gas wells in British Columbia, Alberta, Saskatchewan, and Manitoba. As the analysis for offshore Newfoundland and Labrador was aggregated by asset, a map of the producing assets is shown in Figure D.5.

Table D.1: Supply Study Areas

Area ID Province Area Description

PIA01 AB Suffield Medicine Hat Area

PIA02 AB Bow Island Area

PIA03 AB Foothills Area west of Calgary

PIA04 AB Hussar to Princess Area

PIA05 AB Didsbury to Hussar Area

PIA06 AB Nevis and Ghostpine Area

PIA07 AB Bens Lake to Princess (North Lateral) Area

PIA08 AB Bens Lake to Canendish (East Lateral)

PIA09 AB Edson to Caroline (Plains Mainline)

PIA10 AB McLeod to Caroline (Foothills Mainline)

PIA11 AB Edmonton Area

PIA12 AB Bens Lake upstream to Calling Lake

PIA13 AB Gold Creek to Edson Area

PIA14 AB Vahalla to Gold Creek Area

PIA15 AB Judy Creek, Kaybon to Edson and McLeod

PIA16 AB Doe Creek to Teepee Creek Area

PIA17 AB Heart River Wolverine Creek Area


July 2018

Area ID Province Area Description

PIA18 AB Darling Creek to Slave Lake Compressor

PIA19 AB Fort McMurray Area

PIA20 AB Owl Lake Area

PIA21 AB Thunder Creek to Tanghe Creek

PIA22 AB Zama Lake to Meikle Compressor

PIA23 AB Princess to Empress Mainline

PIA30 BC Pine River Lateral

PIA31 BC Tupper Creek/Noel Area

PIA32 BC Groundbirch Area

PIA33 BC Dawson Creek

PIA34 BC Fort St. John Area

PIA35 BC Chinchauga River

PIA36 BC Ring Area

PIA37 BC Kahntah Area

PIA38 BC Shekilie Area

PIA39 BC Peggo-Pesh Area

PIA40 BC Helmut North Area

PIA41 BC Fort Nelson to CS2

PIA42 BC Fort Nelson to NWT Border

PIA45 BC CS2 to Summit Lake Area

PIA50 SK Southwest

PIA51 SK Central West

PIA52 SK Northwest

PIA54 SK Northeast


July 2018

PIA55 SK Central East

PIA56 SK Southeast

PIA70 MB Bakken - Tourquay, Bakken

PIA71 MB Lodgepole

PIA72 MB Amaranth

PIA73 MB Mission Canyon

PIA79 MB Others

Source: CERI


July 2018

Figure D.1: Map of British Columbia Study Areas


July 2018

Figure D.2: Map of Alberta Study Areas


July 2018

Figure D.3: Map of Saskatchewan Study Areas


July 2018

Figure D.4: Map of Manitoba Study Areas


July 2018

Figure D.5: Map of Newfoundland and Labrador Study Areas*

*Study areas are Terra Nova, Hibernia, White Rose and North Amethyst, Hebron assets

Source: CNLOPB

Study No. 173 July 2018 - CERI

Documents

Transcript of Study No. 173 July 2018 - CERI