A competitive policy and regulatory framework for Alberta s upstream oil and natural gas industry

Transcription

1 A competitive policy and regulatory framework for Alberta s upstream oil and natural gas industry July/

2 The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP s member companies produce about 80 per cent of Canada s natural gas and crude oil. CAPP's associate members provide a wide range of services that support the upstream crude oil and natural gas industry. Together CAPP's members and associate members are an important part of a national industry with revenues from crude oil and natural gas production of about $120 billion a year. CAPP s mission, on behalf of the Canadian upstream crude oil and natural gas industry, is to advocate for and enable economic competitiveness and safe, environmentally and socially responsible performance. 2100, Avenue S.W. Calgary, Alberta Canada T2P 3N9 Tel Fax , 275 Slater Street Ottawa, Ontario Canada K1P 5H9 Tel Fax , 235 Water Street St. John s, Newfoundland and Labrador Canada A1C 1B6 Tel Fax B Harbour Road Victoria, British Columbia Canada V9A 3S1 Tel Fax

3 Executive Summary The upstream petroleum industry provides many economic and other benefits to Albertans and more broadly to Canadians but the industry continues to face challenges and barriers to growth and success. CAPP is proud of our strong and collaborative working relationship with the Alberta government to help achieve our shared goals of growing the economy and creating jobs for Albertans in an environmentally and socially responsible manner. In this report, CAPP examines the health of this vital industry, and presents recommendations to work collaboratively with the province to address current and future challenges to the oil and natural gas sector s ability to grow the economy. A major determinant of the oil and natural gas sector s ability to attract investment and create jobs is improved market access to help ensure Canadian production can reach more customers in more markets. Improved market access is a priority our industry shares with the Government of Alberta. We therefore appreciate the province s consistent support for additional pipeline capacity to markets in North America and tidewater. Alberta s Climate Leadership Plan was also referenced as a supporting factor in the federal government s positive decisions on recent pipeline projects, and we appreciate the province s timely completion of the royalty review. The resulting royalty system provides the clarity and stability investors need to plan for the future, and it puts Alberta on a level fiscal playing field with the United States, our main competitor. Notwithstanding these positive developments, market dynamics and technological advancements, both within North America and globally, have changed dramatically over the past decade and especially in the last two years due to volatile commodity prices. Canada s oil and natural gas producers now face a new normal that is characterized by commodity prices that are forecast to remain lower for longer, as well as changed supply and demand dynamics in North America that make it more difficult to compete in traditional markets and markets our industry is trying to access. Given this new normal, CAPP recommends creating a Sustainable Prosperity Steering Committee where industry and government can work together to find solutions that bring back investment, enhance competitiveness and regulatory timelines, address uncertainty caused by federal initiatives and ultimately create jobs for Albertans. This recommended approach would be highly reliant on political will to enable and empower decision-makers at the policy and regulatory levels to make decisions that enhance Alberta s competitiveness and seek to improve the efficiency and effectiveness of the system overall. In our view, the ultimate goal of this approach would be to create a policy and regulatory system that is the most efficient among comparable jurisdictions, which would ultimately make Alberta a more attractive place for industry investment. 2

4 Contributions to the Alberta Economy Even in times of economic challenge, Alberta s oil and natural gas industry remains a pillar of the province s economy. Based on actual revenues, capital spending and operations spending in 2015 (the most recent year for which complete data are available), there were significant economic benefits from both conventional and oil sands development: one third of all economic activity in Alberta and employment for one quarter of Alberta s workers (direct, indirect and induced). In 2015, Alberta s upstream oil and natural gas sector delivered: $2.9 billion in non-renewable resource revenues $185 million in corporate income tax $2.8 billion in personal income tax from direct and indirect employment $1.25 billion in municipal property tax on upstream assets alone Support for more than 20,000 businesses in Alberta, including 327 Aboriginal companies, representing about $4 billion in activity in 2015 Although substantial, these numbers are down considerably from 2014, when the industry employed approximately one in three Albertans, contributed $10 billion in government revenues and 40 per cent of Alberta s gross domestic product (GDP). Challenges Despite the contributions of Alberta s oil and natural gas industry, our sector continues to face significant policy and regulatory challenges at both the provincial and federal levels that are impacting our ability to attract the investment necessary to grow and generate jobs and prosperity. There are between 40 and 50 different policy and regulatory initiatives currently underway by provincial and federal governments in Canada that have the potential to adversely impact the industry. Some of these challenges are new, while others have existed for some time, and they are occurring at a time when the U.S. is streamlining and reducing the cost of regulations. The cumulative effects of the resultant costs are having significant impacts from an investment perspective. While many of these policy and regulatory changes are ongoing initiatives, some of which precede the tenure of the current government, the combined impacts of numerous recent policy and regulatory changes have resulted in a significant incremental burden over the existing base costs. The costs associated with government policy and regulatory elements could be as high as $5.2 billion annually in the near term. Furthermore, these annual incremental cost increases are expected to rise to by 2023 once the Alberta carbon tax is implemented on natural gas produced and consumed on site by conventional oil and natural gas producers. 3

5 At the same time, upstream capital expenditures in the U.S. are expected to increase 38 per cent to $120 billion in 2017, according to a projection by the Oil and Gas Journal that is based on a survey of companies capital expenditure announcements. In contrast, overall capital spending in Canada is forecast to be $44 billion in 2017, a 46 per cent decrease from a peak of $81 billion in Some of these challenges are outside the control of industry and government. However, opportunities exist for industry and government to work together to meet a common goal: responsibly grow oil and natural gas production in our province to strengthen the economy and get Albertans back to work. Many of these collaborative channels already exist and continue to serve both industry and government well. However, given the complexity of this issue and the new reality our industry and province faces, a focused and determined joint commitment is required to achieve sustainable prosperity and job growth. Sustainable Prosperity Steering Committee CAPP recommends that the province adopt a whole-of-government approach and mandate to strengthen Alberta s investment attractiveness while achieving government policy objectives. This approach could be supported by a Sustainable Prosperity Steering Committee, comprised of senior representatives from the regulated community and the province notably the Premier s Office, the ministries of Energy, Economic Development and Trade, and Environment and Parks and the Alberta Energy Regulator. The intent of the committee would be to provide government and industry oversight to steward reform initiatives and drive performance on key files, with a view to minimizing cumulative costs on industry while still achieving government outcomes. This approach would also rely on political engagement with the federal government to ensure streamlined policies and address uncertainty caused by federal initiatives that directly impact the competitive position of Alberta, such as the potential changes to the National Energy Board and the Canadian Environmental Assessment Agency. For this approach to be effective, we recommend a phased process with clear deliverables. As a matter of priority, the committee would focus on ensuring currently active policy and regulatory changes are proceeding with a view to protecting and enhancing the investment climate. Further, the first phase could be used to assess the overall policy and regulatory framework to prioritize opportunities for regulatory enhancement and protecting investment. Specific reform initiatives could be worked through in subsequent phases, with a view to achieving regulatory efficiencies, eliminating duplication and creating a framework for achieving shared sustainable prosperity in Alberta. Initiatives the committee should work on in the near term include: 4

6 Streamlining application processes (defined timelines and continuing to support the Alberta Energy Regulator s Integrated Decision Approach). Managing the potential cost impacts of ongoing initiatives (high priority items include: climate leadership implementation, liability and closure and caribou). Exploring other regulatory opportunities (see Table 4). The ultimate result of the committee work would be to improve regulatory efficiency and effectiveness, which would bolster our industry s ability to attract the investment that creates jobs, generates public revenues, and grows and strengthens Alberta s economy. The Benefits of Action The oil and natural gas industry can play a major role in Alberta s job recovery. Currently, there are more than 100,000 unemployed workers in Alberta than there were on average in 2012, 2013, and Estimates suggest that improved competitiveness could result in the recovery of approximately 180,000 barrels a day of production in the oil sands alone. The capital spending on this incremental oil sands production, combined with incremental conventional production, in the next three years would ensure good paying jobs for more than 20 per cent of Alberta s incremental cyclically unemployed. More specifically, the potential benefits associated with acting on the recommendations outlined in this document would help create, on average, in the near term: More than 24,000 new jobs (full time equivalent) which would reduce current cyclical unemployment in Alberta by close to 25 per cent. $4.5 billion in incremental GDP. $207 million in additional income tax. $79 million in additional royalties. We look forward to working with government on the potential solutions offered in this document for creating a strong, responsibly developed oil and natural gas sector and a prosperous Alberta. 5

7 Contents Executive Summary... 2 Contributions to the Alberta Economy... 3 Challenges... 3 Sustainable Prosperity Steering Committee... 4 The Benefits of Action... 5 Contents Introduction Oil and Natural Gas Benefits to the Alberta Economy Key Challenges Confronting the Upstream Oil and Natural Gas Sector Oil and Gas Market Dynamics and Competition for North American Market Share Government Policy Decisions and Uncertainties in Canada and United States Policy and Regulatory Direction in the U.S Policy and Regulatory Direction in Canada Changing Investment Dynamics Opportunity for Collaborative Solutions: A Sustainable Prosperity Steering Committee Sustainable Prosperity Steering Committee Policy Changes Regulatory Changes Conventional Oil and Gas Regulation Oil Sands Regulation Regulatory Opportunities Oil Sands and Conventional/Unconventional Modernizing Alberta s Regulatory and Policy Framework for the Long Term Benefits of the Proposed Approach Conventional Oil and Gas Oil Sands Incremental Employment in Context

8 6 Appendix Economic Benefits Data Tables Oil and Gas Benefits to the Alberta Economy Conventional Oil and Gas Incremental Benefits Oil Sands Incremental Benefits Oil Sands Company 2017 Expenditure Profiles

9 1 Introduction The Canadian Association of Petroleum Producers (CAPP) represents companies, large and small, that explore for, develop and produce natural gas and crude oil throughout Canada. CAPP s member companies produce about 80 per cent of Canada s natural gas and crude oil. CAPP s mission, on behalf of the Canadian upstream crude oil and natural gas industry, is to advocate for and enable economic competitiveness and safe, environmentally and socially responsible performance. The upstream oil and natural gas industry is currently confronted with significant challenges and risks from a competitiveness perspective, particularly in a North American context. These challenges have the potential to further diminish Canada s and Alberta s ability to attract investment and generate the employment, economic and government-revenue benefits associated with developing our oil and natural gas resources responsibly. The upstream oil and natural gas sector is the largest private sector investor in Alberta, representing one third of all economic activity, one quarter of Alberta s employed, and contributing approximately $7.0 billion in provincial and municipal revenues in These benefits are potentially threatened by challenging dynamics in the investment community. The Government of Alberta and industry have established a strong working relationship to ensure the continued health and responsible development of our energy resources and, if we are to be successful in the future, there is a compelling need for additional effort. CAPP is seeking to continue to build on our strong relationship by working collaboratively with the province to advance our shared interest in creating jobs and prosperity for all Albertans, in a manner that is socially and environmentally responsible. What follows is an analysis of the key challenges confronting our industry and a proposed course of action to address these challenges. 2 Oil and Natural Gas Benefits to the Alberta Economy 1 Alberta s oil and natural gas industry remains an important part of Alberta s economy, even in times of economic challenges. Oil sands and conventional activity represented one third of all economic activity in Alberta and provide employment for one quarter of Alberta s employed when direct, indirect, and induced factors are taken into consideration (approx. 540,000 jobs). These activities contributed substantially to the public purse, with over $2.8 billion in nonrenewable resource revenues, $185 million in provincial corporate income tax, more than $2.7 1 See Appendix for data tables 8

10 billion in personal income tax from direct and indirect employees, and approximately $1.25 billion in the municipal portion of the property tax on upstream assets alone. In addition, the oil and gas sector supports more than 20,000 businesses across the province, including 327 Aboriginal companies in our supply chain representing approximately $4 billion in activity in These economic benefits are down substantially since 2014, when the industry employed approximately one in three Albertans, contributed $10 billion in government revenues and 40 per cent of GDP. This decline has had a profound impact on Alberta s job market Despite slight improvements in recent months, as of April 2017, the number of unemployed workers has reached 210,000, which is about 13,000 more than it was in April of 2016 at 197,000, and 86,000 more than it was in April 2014 (see Appendix). The first quarter of 2016 averaged approximately 217,000 unemployed, close to twice as many as in the pre-recession first quarter of Most disconcertingly, a large share of the unemployed workers are experiencing long-term unemployment (see Figure 1), approximately one in three unemployed workers in April 2017 have been unemployed for more than six months. Close to half of those long-term unemployed have been unemployed for more than a year. Figure 1: Unemployment in Alberta, Seasonally Unadjusted, by Duration Source: Statistics Canada CANSIM Table Long term unemployment is associated with permanently lower wages and increased difficulty finding employment, with the potential causes being skill loss and/or the stigmatization of workers who have been unemployed for long periods, 3 making it especially harmful. Efforts to 2 CAPP Oil Sands Aboriginal Supply Chain Survey Konrad Zmitrowicz and Michael Khan, 2014, Beyond the Unemployment Rate: Assessing Canadian and U.S. Labour Markets Since the Great Recession, Bank of Canada Review, Spring 2014, 9

11 encourage upstream oil and natural gas investment will not only help arrest this trend, but begin to move the province job market back into positive territory. 3 Key Challenges Confronting the Upstream Oil and Natural Gas Sector Global oil and natural gas markets are constantly evolving, and competition for North American market share has intensified, placing Canadian producers at a disadvantage. In addition, government policy decisions and uncertainties within Canada are undermining investor confidence at a time when the U.S., our largest competitor, is actively encouraging oil and natural gas investment. These elements are further discussed below. 3.1 Oil and Gas Market Dynamics and Competition for North American Market Share The dynamics of global oil and natural gas markets have changed dramatically since late Global energy demand is expected to grow at a moderate pace, and most forecasters agree that oil and natural gas prices will continue to remain low for the foreseeable future. Figure 2: West Texas Intermediate (WTI) Crude Oil Price Source: EIA Short-Term Energy Outlook, May accessed May 8,

12 Figure 3: Henry Hub Natural Gas Price Source: EIA Short-Term Energy Outlook, May 2017 In addition to subdued economic growth, the dynamics of North American oil and natural gas markets have changed. Technological advancements have changed North American supply dynamics, and unlocked an abundance of oil and natural gas resources, at lower prices, that only a decade ago was thought to be impossible. The U.S., in particular, has benefited from this development. U.S. tight oil production is now following a similar path as the U.S. shale gas revolution s transformation of North America s natural gas markets. The U.S. is now poised to produce a record amount of crude oil in 2018, according to the EIA. This means that the U.S. will be able to meet an increasing share of its domestic demand by domestic supply at a price much lower than was previously possible. 11

13 Figure 4: North American Natural Gas Prices and U.S Shale and Alberta Gas Production Source: EIA and AER Figure 5: U.S. Tight and Alberta Oil Production Source: EIA and AER Canadian oil and natural gas producers are not only competing for market share in the U.S. they are competing against U.S. supply in Canada. Imports of U.S. natural gas have increased substantially since about the middle of the last decade, as the shale gas revolution unlocked abundant supplies in the U.S., such as the Marcellus shale in Pennsylvania. Some of these sources of supply are closer to markets in Central Canada, which means western Canadian producers are challenged, from a cost perspective, to compete in these markets. 12

14 Figure 6: U.S. Exports of Natural Gas Source EIA Over the past few years, the U.S. has rapidly taken advantage of growing international demand for oil and particularly natural gas by expanding its export capacity. This is particularly evident in the case of exports of liquefied natural gas (LNG). Sabine Pass LNG began operations in Meanwhile, six other LNG export facilities are in various stages of construction. Once all of these LNG projects start operating, the U.S. at 9.4 billion cubic feet per day is projected to have the third-largest liquefaction capacity in the world, according to the EIA. Canada, meanwhile, remains challenged to develop LNG export terminals on the West Coast. This development has positive and negative implications for natural gas producers in Canada. U.S. LNG exports, once facilities are completed, would move a large volume of natural gas out of the North American basin, including Canada. Downward pressure on prices, due the North American supply glut, could be reduced as a result. However, U.S. LNG would compete in some of the same markets the various LNG proposals on Canada s West Coast are targeting, thus reducing the chance of a significant West Coast LNG industry to be developed. In fact, on May 12, 2017, the U.S. and China announced a bilateral trade agreement that would allow Chinese companies to buy LNG produced in the U.S. The agreement enables Chinese companies to negotiate contractual agreements with U.S. LNG exporters, including long-term contracts. As of April 2017, the U.S. Department of Energy had authorized 19.2 billion cubic feet per day of natural gas exports to non-free Trade Agreement (FTA) countries, according to the U.S. Department of Commerce. U.S. crude oil exports into Canada have also increased sharply. In 2012, Canada imported 67,000 barrels of crude oil per day from the U.S. That number more than quadrupled by 2016, when Canada imported 301,000 barrels of crude oil per day. 13

15 Figure 7: U.S. Crude Oil Exports Source EIA Given these challenges, it is evident that a rebound of Canada s upstream oil and natural gas industry cannot be expected to be driven solely by an increase in commodity prices, as the future paradigm companies are facing is a lower price range with higher price volatility and uncertainty with increased competition for market supply. If Canada is to maintain or even expand its market share, it needs to be competitive with the U.S. in North America and global markets. Figure 8: New Price Paradigm Source: CAPP 14

16 3.2 Government Policy Decisions and Uncertainties in Canada and United States Favourable policy decisions and confidence are critical in creating an environment that attracts investment. Government policy decisions will impact investor decisions based on the impact of the policy itself, as well as the relative policy decisions of jurisdictions that compete for capital. For Canada and Alberta, this means comparing the policy and regulatory regime to the U.S., which is not only our major market for oil and natural gas exports but also our biggest competitor for investment capital Policy and Regulatory Direction in the U.S. U.S. competitiveness measures have resulted in increased investment in that jurisdiction. CAPP and our member companies believe there is an opportunity for Alberta to improve its own competitiveness in response to the direction of the U.S. administration on economic, environmental, fiscal and trade policy. Recent U.S. measures that have resulted in increased investment include: Removal of the oil export ban. Beginning to export LNG. Presidential Executive Order that would require agencies to revoke two regulations for every new rule they want to issue. 4 As well, the U.S. government continues to retreat from its North American commitments on methane and carbon dioxide emissions reductions: Cancelled the Information Collection Request for oil and natural gas operations (March 2). Initiated reconsideration proceedings to suspend, revise or rescind the New Source Performance Standards (NSPS) 40 CFR part 60 subpart OOOO (April 4). Upon withdrawal from the methane NSPS (Quad OOOOa), a stay of 90 days is expected to allow delay in the LDAR and reporting requirements under that statute. Issued request for feedback on reducing regulatory burden (April 18). Withdrawn funding for EPA Climate Office effectively dismantling voluntary programs, such as Natural Gas/ Energy Star and the Methane Challenge. Announced intent to withdraw the U.S. from the Paris climate change accord (June 1). On top of its efforts to support domestic oil and natural gas investment, the U.S. has initiative the process to renegotiate the terms of the North American Free Trade Agreement (NAFTA) and, potentially, introduce fiscal measures, such as a border adjustment tax, that would disadvantage Canadian oil and natural gas exports to the U.S. These factors contribute to the 4 The Hill Times. Trump Signs 2-for-1 Order to Reduce Regulations. January 30,

17 uncertainty that is affecting investment decisions in Canada, placing a higher risk premium on Canadian investment opportunities relative to the U.S. Alberta does not need to simply echo the U.S. approach to competitiveness. The opportunity is to work together on a made-in-alberta competitiveness plan that allows our oil and natural gas industry to compete in a changing world dynamic while maintaining world-class environmental and regulatory standards Policy and Regulatory Direction in Canada While the U.S. is reducing the cost of environmental regulations and streamlining regulations, in some areas Canada is moving in new policy directions that have the potential to increase costs and reduce competitiveness. While we recognize the importance of developing our resources in a responsible manner to help achieve key regulatory, social and environmental outcomes, it is important to do so in a manner that does not unnecessarily adversely impact industry investment. A number of different initiatives have the potential to adversely affect competitiveness and increase uncertainty for industry, including the Aboriginal Consultation Office and its impact on the regulatory system, the Climate Leadership Plan, the Caribou Recovery Strategy, liability and closure, lease tenure reform, the Alberta Wetland Policy and the Land Use Framework. Policy and legislative changes that have been introduced by the federal government, such as the Canadian Environmental Assessment Agency and the National Energy Board reviews, are compounded in Alberta and are contributing to the cumulative negative impact on this province s investment attractiveness. Government has shown a willingness to work with industry to mitigate potential challenges to competitiveness via the royalty review. What industry is seeking is an opportunity to engage in a manner similar to the one employed in the royalty review to ensure these initiatives are managed in a manner that does not negatively impact industry s ability to attract investment. The potential impact of these policy changes on industry s ability to attract investment is reflected in the perceptions of industry as conveyed in the 2016 Global Petroleum Survey, which is an established survey of oil and gas companies regarding barriers to investment in oil and natural gas jurisdictions around the globe. Survey questions focus on tax rates, regulatory obligations, uncertainty over environmental regulations and the interpretation and administration of regulations governing the upstream petroleum industry. According to the survey, Alberta s ranking has fallen every year since 2014 and in 2016 was ranked 43 rd out of 96 jurisdictions. It is now ranked below British Columbia, Saskatchewan, North Dakota, Oklahoma, Pennsylvania and Texas. 16

18 Figure 9: Policy Perception Index Rankings reflects the perceived extent of the barriers to investment Source: Fraser Institute, 2016 Global Petroleum Survey The cumulative effects of the resultant costs are having significant impacts from an investment perspective. While many of the contributing policy and regulatory challenges date back a number of years, and in some cases precede the tenure of the current Government, combined they represent a significant overhaul of the oil and natural gas policy framework in Alberta. While some of the impacts may have been neutral or even slightly positive, the net cumulative effect has had a negative impact on the investment attractiveness of Alberta whether as a result of increased costs, longer or more convoluted approval timelines, or greater uncertainty regarding the stability of the investment climate in general. With respect to conventional and unconventional development alone, these costs are conservatively estimated to be between $450 million and $760 million annually (incremental $0.09 to $0.15/Mcfe) in the near term. These increases equate to an approximate 12 to 21 per cent increase over the current estimated annual base policy and regulatory cost of $3.6 billion per year. Furthermore, these annual incremental cost increases are expected to rise to between $1.1 billion and $2.1 billion by 2023 (incremental $0.23 to $0.44/Mcfe) once the Alberta carbon tax is implemented on natural gas produced and consumed on site by conventional oil and natural gas producers. These post-2023 increases represent a 30 to 60 per cent increase over the current base policy and regulatory cost. The potential cost impacts of the carbon tax may vary depending on the design of the output-based allocation framework (OBA). 17

19 Figure 10: Economic Burden from New Regulatory Changes Price Assumptions: $4/Mcf (natural gas), $8/bbl (propane), $19/bbl (butane), $50/bbl (oil/condensate) Source: CAPP membership The graphic above illustrate the cumulative impact current and ongoing regulatory changes would have on the profit margins of an average well in Alberta s Montney play (reflective of the production type curves used in the 2015/2016 royalty review). It also demonstrates that costs associated with any one policy or regulatory change cannot be viewed in isolation: it is the cumulative impact of existing and new cost burdens that is gradually decreasing the profitability of wells in Alberta, which ultimately decreases a play s investment attractiveness. The increasing cumulative cost burden resulting from the combination of existing and new policy and regulatory requirements will directly impact companies drilling programs: the higher the cumulative cost burden, the fewer wells are expected to be drilled. This is a direct result of producers preferentially focusing on the most economic assets within their portfolio, and deferring drilling of less economic assets, to ensure that the overall profitability of the project remains constant. As well, as cumulative costs in any one play or jurisdiction increase and profit margins decrease, the less attractive the play or jurisdiction becomes for companies that have options to allocate funds to drilling programs elsewhere. 18

20 3.3 Changing Investment Dynamics The increasingly competitive North American oil and natural gas market, in combination with the recent policy changes and uncertainties in Alberta, have contributed to reduced investment in Canada s oil and natural gas sector. Investment is critical, as it is the foundation of all economic benefits associated with the upstream oil and natural gas industry. Figure 11: Global E&P Capex spending to flatten in 2017 Source: Bloomberg *2017 is estimate Figure 12: Capex spending in the U.S. Source: Oil and Gas Journal *2017 is estimate 19

21 Capital investment in the global energy market is expected to slightly increase in 2017, following consecutive reductions in 2015 and This is a welcome recovery, and the U.S. market, in particular, is expected to perform quite well. U.S. upstream capital expenditures are forecast to increase by 38 per cent to $120 billion in 2017, according to a projection by the Oil and Gas Journal that is based on a survey of companies capital expenditure announcements. In contrast, the Canadian market is not growing as fast: in 2017, the overall capital spending is forecasted to be $44 billion, a 46 per cent decrease from a peak of $81 billion, and a 19 per cent increase from Figure 13: Upstream Capital Investment in Canada Source: Statistics Canada/CAPP Alberta s conventional sector, following two years of sharp contractions in capital investment, is forecast two recover slowly in 2017, as show in in Figure 14. According to AER data, upstream conventional capital investment is forecast at $12 billion in 2017 compared to $10 billion in Compared to the U.S., however, the recovery in Alberta is not as rapid: while U.S capital investment in the conventional sector is projected to increase by 38 per cent in 2017, according to a projection by the Oil and Gas Journal, investment in Alberta s conventional sector is projected to increase by a more moderate 20 per cent. In other words, while investment contractions on both sides of the border were equally sharp (a 37 per cent contraction in 2015 in both Alberta and the U.S., and a 41 and 40 per cent contraction in 2016 in Alberta and the U.S., respectively), the recovery in the U.S. is projected at a rate that is nearly twice as fast as Alberta s. 20

22 Figure 14: Alberta Conventional Capital Expenditures Source: Alberta Energy Regulator, ST98 Oil sands investment has experienced a more dramatic shift. From 2014 to 2017, capital investment has declined by $19 billion or 55 per cent (Figure 15). Figure 15: Oil Sands Capital Expenditures Source: Statistics Canada/CAPP In a review of the 2017 expenditure plans of the primary 20 companies with Canadian oil sands production (see Appendix 8.2 for full list), the top seven companies are expected to allocate over $500 million each of capital into the Canadian oil sands, representing 88 per cent of total 21

23 oil sands investment (Figure 16). The remaining 13 oil sands companies will be investing approximately 12 per cent combined of total investment in the oil sands in In a review of the 2017 expenditure plans of the primary 20 companies with Canadian oil sands production (see Appendix 8.2 for full list), the top seven companies (CNRL, Suncor Energy, Cenovus Energy, MEG, Teck Resources, Total E&P, Imperial Oil) are expected to allocate over $500 million each of capital into the Canadian oil sands, representing 88 per cent of total oil sands investment (Figure 16). The remaining 13 oil sands companies will be investing approximately 12 per cent combined of total investment in the oil sands in Figure 16: Oil Sands Investment Source: Company corporate strategy, investor presentations and guidance documents. These graphs are based on publically available information and some capex spending is not included. The 13 companies representing 12% of oil sands investment have allocated their capital away from the oil sands and into the U.S. The total pool of oil sands company investment in the U.S. is $23 billion (nearly double the capital going into oil sands), 95 per cent of which is generated by these companies. 5 Note: the estimates in figure 15 are based on a different methodology than in figures 16 and 17. The former is based on a Statistics Canada survey of producers and CAPP estimates, the latter based on a review of publicly available company guidance. The population of companies in both methodologies is essentially the same 22

24 Figure 17: Oil Sands Companies Investment in the U.S. Source: Company corporate strategy, investor presentations and guidance documents. These graphs are based on publically available information and some capex spending is not included. Many of these companies have global operations and are also investing in comparable longcycle portfolio assets across the globe. For example, Chevron, Shell, and ExxonMobil, in one way or another, are prioritizing long-cycle hydrocarbon projects (e.g. LNG, U.S. Gulf Coast, Petrochemicals as shown in the table below) in competing jurisdictions. These findings confirm that companies that traditionally invest in the oil sands, and that have access to capital and optionality, are deploying significant capital in comparable opportunities outside of the oil sands. Table 1 Company Chevron ExxonMobil Shell 2017 projects examples Gorgon and Wheatstone LNG projects in Australia. LNG in Angola Tengiz oil field in Kazakhstan More than 50% of the 2017 upstream budget is on long cycle assets [e.g. Hebron, Upper Zakum (UAE), Odoptu (Russia), Liza (Offshore Guyana) and Tengiz] Announced a 10 year spending plan of $20 Billion on U.S. Gulf Coast chemical and LNG projects Appomattox deep-water project in the Gulf of Mexico and deep water project in Brazil Petrochemicals investment in Nanhai (China), Geismar (U.S.) Source: Corporate guidance and strategy documents, table does not include all 2017 projects. 23

25 4 Opportunity for Collaborative Solutions: A Sustainable Prosperity Steering Committee Clearly, there is a need to rebalance the playing field to draw investment back into Canada, but it cannot be done at all costs. Alberta is a leader in responsible resource development, and we need to maintain this status to continue to earn the trust and support of Canadians. Industry recognizes the importance of working collaboratively with the province to address our shared challenges, and we are proud of our track record in this regard. If we are truly going to continue to work together to address these issues to create jobs and prosperity for the province, we need to recognize and affirm our shared priorities. Given the sheer size and complexity of issues, no one silver bullet will address these key challenges, as many of industry s priorities are being advanced through existing engagement and policy development channels across government. While we support the opportunity to work collaboratively with government and stakeholders through these channels, if we are to make meaningful headway in achieving sustainable prosperity and job growth together and maintaining it then a joint commitment to a whole of government approach to monitoring and advancing this initiative is needed. 4.1 Sustainable Prosperity Steering Committee CAPP recommends that the province adopt a whole-of-government approach and mandate to strengthen Alberta s investment attractiveness while achieving government policy objectives. This approach could be supported by a Sustainable Prosperity Steering Committee, comprised of senior representatives from the regulated community and the province notably the Premier s Office, the ministries of Energy, Economic Development and Trade, and Environment and Parks and the Alberta Energy Regulator. The intent of the committee would be to provide government and industry oversight to steward reform initiatives and drive performance on key files, with a view to minimizing cumulative costs on industry while still achieving government outcomes. This approach would also rely on political engagement with the federal government to ensure streamlined policy and address uncertainty caused by federal initiatives that directly impact the competitive position of Alberta, such as the potential changes to the National Energy Board and the Canadian Environmental Assessment Agency. For this approach to be effective, we recommend a staged process with clear timelines and deliverables. As a matter of priority, the committee would focus on ensuring currently active policy and regulatory changes are proceeding with a view to protecting and enhancing the investment climate. Further, the first 90 days could be used to assess the overall policy and regulatory framework to identify opportunities for regulatory enhancement and protecting investment. Specific reform initiatives could be worked through over the course of one year, 24

26 with a view to achieving regulatory efficiencies, eliminating duplication and creating a framework for achieving shared sustainable prosperity in Alberta. The ultimate result of would be to minimize adverse policy impacts and improve regulatory efficiency and effectiveness, which would bolster our industry s ability to attract the investment that creates jobs, generates public revenues, and grows and strengthens the economy in alignment with government objectives. 4.2 Policy Changes The oil sands, with 270 billion barrels of potential recoverable reserves, are a resource of global significance. Meanwhile, the Alberta portion of the Montney play s potential for marketable natural gas is estimated at 178 trillion cubic feet. Government is undertaking a number of policy changes that have the potential to impact industry. While we appreciate the opportunity to engage in policy dialogue and consultation to help advance these priorities with government and optimize the value of these vast resources, the SPSC could play a critical role in understanding and mitigating the cumulative cost burden on industry associated with these initiatives. The following table summarizes the key policy initiatives being undertaken by government, as well as industry s proposed position. Table 2 Policy Initiative Climate Leadership (Methane) Climate Leadership (Carbon Pricing - Short Term) Climate Leadership (Carbon Pricing - Long Term) Description Methane reduction target of 40 to 45 per cent by 2025 is expected to result in both capital and annual operational costs. Increased costs due to carbon pricing on electricity and fuel consumption Increased costs due to a ramping up of carbon tax to $50/tonne by 2023 Recommended Approach Align Alberta regulatory timelines with those of the federal government, Near-term focus on offsets and incentives, measurements and reporting Ensure ability to adjust leak detection and repair (LDAR) stringency based on performance, new research and technology Use portfolio approach for pneumatics rather than prescriptive retrofit requirements Examine impact of Federal carbon policy on current provincial legislation Continue to advocate for Alberta 2023 exemption for non-large final emitters under new federal carbon policy Provide mechanisms to protect non-large final emitters post 2023 exemption Provide protection for emissions-intensive trade exposed (EITE) for non-large final emitters through output based allocation (OBA) system 25

27 Climate Leadership (Oil Sands Emissions Limit) Climate Leadership (Output Based Allocation) Caribou Liability Management System Orphan Well Association (OWA) Levy Increases 100MT emissions limit on oil sands creates investor uncertainty pending the release of the emissions limit policies Introduced a output-based allocation performance standard for oil sands facilities Imposes a 30 per cent restriction on the use of offsets to meet compliance obligations To align with Federal Recovery Strategy, Alberta Range Plans will be created for all 15 caribou ranges by the end of 2017 Lack of details on industry s land use requirements within range plans results in great uncertainty for industry While certain elements of the existing system have been effective, there is pressure on industry due to low commodity prices and recent court decisions that have identified areas that could benefit from enhancements The potential for impactful changes to the liability management system results in considerable uncertainty for the industry. Expected increases to OWA levy in forthcoming years as level of corporate insolvencies continues to remain high. Establish a framework that prioritizes investment in technology Applies a trigger based approach escalating management action Enables full access to offsets as a compliance tool Develop an OBA approach that considers and protects the emissions intensive trade-exposed nature of the industry, with separate OBAs for in situ developed based on resource quality characteristics Create methodologies that account for the uniqueness of upgraders and natural gas processing facilities, and manage impacts to the economics of liquids-rich plays Reinvest carbon revenues into technology fund to enable industry to continually invest in and improve its GHG performance Remove restrictions on use of offsets Ensure collaring treatment for adversely affected outlying facilities Enable full use of offsets for compliance Work with industry and the federal / provincial governments to advance a working landscape approach to restore and maintain caribou and caribou habitat while maintaining oil and gas development. Arrange extensions of tenures commensurate with the length and breadth of activity rescheduling commitments. Examine extensions of tenures for companies who are willing to stretch out drilling activity over multiple years but face tenure expiration. An effective liability management system must protect Albertans and industry from undue risk from current and future liability; protect environment, people and communities; and maintain economic growth and competitiveness. Strategic pillars that would benefit from enhancements include: inactive site closure, modernized liability management program and well assurance program. Continued industry support for OWA levy Support enhancements to liability management framework, based on CAPP s three strategic liability pillars, to ensure Albertans and industry are not put at risk due to current and future liability 26

28 Oil Sands Lease Tenure Conventional Lease Tenure Municipal Tax Investment in Oil Sands Technology and Value-Add Current review of lease tenure system creates significant uncertainty regarding investment for existing and future lease holdings. Current review of lease tenure system creates significant uncertainty regarding investment for existing and future lease holdings. Amendments to the Municipal Government Act (MGA) in November 2016 enable the application of different tax rates to non-residential property, which will likely increase the municipal tax burden on industrial property outside the oil sands Proposed changes to assessment regulations (e.g. construction cost reporting guide, land at wellsites) could increase municipal assessments substantially across the province Significant opportunities exist for industry and government to work together to meet a common goal of responsibly optimizing the value of this vast resource and future growth. Innovation is key to remaining competitive globally. The oil and natural gas sector is undergoing transition at an unprecedented pace and scale. Alberta needs to match or exceed this pace to remain cost- and carbon-competitive. Adopt a lease tenure approach based on marginal level of investment as opposed to marginal level of expenditure Maintain current ability to continue lease terms to reflect long oil sands project timelines Enable companies to group leases according to project plans Review tenure system to ensure that it aligns with and supports horizontal drilling and play-based resource development Enable greater clarity and predictability for tenure continuations Remove distortions for gas/oil classifications, in line with Modernized Royalty Framework and Alberta Energy Regulator approaches for unconventional plays Explore a reduced ratio to improve competitiveness in municipalities with conventional assets, and require municipalities to be compliant within five years Rescind the subclass authority for municipalities, or introduce significant limitations on the use for industrial properties Retain current industrial assessment practice for construction cost reporting guide and land at well sites. Prioritize oil sands technology commercialization, such as solvents, that lower costs and per barrel GHG emissions. Meaningful policy changes to encourage investment in the commercialization of technology such as solvents and partial upgrading the Increases bitumen value to the Province, reduces SOR and GHG foot print in development of the resource, and Increases market share and competitiveness Potential financial levers include Accelerated Capital Cost Allowance for clean technology (federal and provincial coordination), municipal tax caps (pre and post payout), investment/ R&D tax credits, favorable financing terms/ access to capital. 27

29 Oil Sands Royalties Workplace Legislation Review The new Modernized Royalty Framework (MRF) brought changes to the Alberta royalty structure that resulted in a neutral impact to industry Inequities and inefficiencies continue to remain Government made changes to Alberta Labour Relations Code and Alberta Employment Standards Code in Bill 17 Changes could reduce labour market flexibility and increase costs for employers in an already depressed labour market Some of the changes with the biggest impact include those making it easier to unionize (including remote site access for union organizers, which appears to directly target our industry) and the changes to group termination notice requirements, which will require working notice for employees, with significant safety and productivity impacts Recognition of the full development and operational costs in Alberta s oil sands royalty system (e.g. HR, IT, accounting, and research) would result in royalties that more accurately reflect the full cost of project development. Better align the marker price for royalty calculation purposes with price realization for Alberta bitumen sold. Replace WTI $CDN oil price marker with Alberta based Western Canadian Select (WCS) $CDN marker price, which is now becoming the heavy oil benchmark standard in North America. It is important that the province develop labour policy that enables continued economic prosperity and competitiveness Work with industry to consider alternative approaches to site access Commit to evaluating the impact of your changes and consult stakeholders on making changes to the legislation to reduce negative consequences of your changes 4.3 Regulatory Changes Alberta is one of the most stringently regulated jurisdictions in the world. In a 2014 Worley Parsons study comparing regulatory stringency, transparency and compliance across relevant jurisdictions over the project life cycle (approval, operations and closure), Alberta s regulatory system was ranked best in the world. Figure 18: Overall Scoring Results 28

30 Source: Worley Parsons While we are proud to be part of such a well-regarded and robust framework, such a rigorous approach, if not applied thoughtfully and ever-greened, gives rise to systemic inefficiencies. In terms of regulatory effectiveness, the regulator does a good job of managing routine applications in an effective and efficient manner. We appreciate the regulator s desire to improve on these timelines and streamline processes through its Integrated Decision Approach. However, challenges in receiving timely decisions on non-standard applications with Statements of Concern have negatively impacted industry certainty and reduced competitiveness Conventional Oil and Gas Regulation As a comparison, CAPP conducted a cross-jurisdictional assessment to better understand timeline impacts and opportunities. This included a comparison among Alberta, B.C., Saskatchewan and select jurisdictions in the U.S. To enable an apples to apples comparison, CAPP used the well licensing process as a proxy for comparison, and specific elements of the Alberta process were used as the baseline to compare other jurisdictions. The elements of the Alberta well licensing process included the following: Pre-application First Nations consultation Surface tenure acquisition Well licensing The jurisdictional data was confirmed by nine companies in Alberta, five in B.C., two in Saskatchewan and five in the U.S., as outlined in the following table. Table 3 29

31 Alberta B.C. Saskatchewa n U.S. Federal U.S. Freehold - Texas U.S. Freehold - Other Non-Routine with SOC*: days Non-Routine: days Routine: days days (up to 130 day advantage) days (up to 148 day advantage) 120 days (up to 100 day advantage) <30-60 days (up to 190 day advantage) 90 days (up to 130 day advantage) *Note that while these timelines provide estimates based on recent operator data with respect to applications involving SOCs, in some cases, SOCs may result in even more protracted timelines. The resulting analysis demonstrated up to a 148 day advantage for applications in B.C. and Saskatchewan, and up to a 190-day advantage compared to some jurisdictions within the U.S., relative to the full Alberta non-routine well-licensing process (and in particular in the event that statements of concern (SOCs) are filed). The timeline advantage for B.C. and Saskatchewan is primarily attributed to the following: B.C. has agreed-upon timelines as stated in the Consultation Protocol Agreement. Alberta has a pre-application First Nations consultation requirement that is not required in B.C. or Saskatchewan. First Nations consultation is conducted by the B.C. Oil and Gas Commission and Saskatchewan Ministry of Environment (MOE) in B.C. and Saskatchewan, respectively, once both the well license/permit and surface disposition applications have been submitted. The timeline advantage in Texas can be attributed to: Surface and mineral rights are privately held and are not specifically regulated in terms of timelines. Two types of well licensing permits: expedited and standard, which take three and five business days, respectively, provided permit applications are completed correctly. By contrast, the current routine well licensing process in Alberta demonstrates comparable application timelines (79 to 119 days) compared to B.C. and Saskatchewan. This indicates that the Government of Alberta has an opportunity to improve regulatory effectiveness by enhancing existing application review processes / best practices at the AER and ACO and thereby reduce timelines for non-routine applications. Doing so would provide: An opportunity to continue to maintain high standards and deliver timely, cost-effective, and an accountable decision making process that aligns with comparable jurisdictions. 30

32 Certainty to industry, Indigenous communities and stakeholders by providing clear timelines and processes for consideration of concerns. To achieve this, we recommend the following: Short term: Implement a more timely decision-making process. o Defined timelines for all application processes to provide both industry and stakeholders with project certainty. o Timelines should be benchmarked against other jurisdictions where possible. Long term: Integrated Decision Approach / Integrated Decision Making o Continue advancement of the Integrated Decision Approach (IDA) project which enables efficiencies and streamlining of upstream authorizations and applications. o As well, often in the regulatory process, proponents are asked to conduct work for a project application that has already been completed for previous applications, creating duplication, unnecessary project delays and costs. This work often includes engagement with stakeholders at several points during the decision making process, thereby causing unnecessary duplication. o Both the regulatory and engagement processes should be empowered to incorporate or rely on previous regulatory decisions as well as information provided by proponents in earlier applications. o This approach would provide significant administrative benefits for regulators, as they would not have to re-review decisions that had been previously made while also reducing timelines, costs and uncertainty for industry. Efficient approval timelines are critical for conventional producers, as the velocity of capital is one of the attractive attributes of these types of investments. These findings suggest that Alberta would benefit from a more rigorous focus on approval timelines with very firm and comparable targets to other jurisdictions Oil Sands Regulation Oil sands projects require significant up front capital costs, have longer timelines and lower production decline rates relative to conventional investments, and tend to be unique in terms of comparability to other projects and jurisdictions (due to the limited geographic nature of the resource). However, oil sands approval processes tend to be quite complex and lengthy, and even duplicative. Recently, the Alberta Energy Regulatory (AER) completed an Integrated Decision Approach (IDA) pilot for Suncor s Meadow Creek. The pilot created a simultaneous approval process that that established one process for consultation, environmental assessment, stakeholder engagement (e.g. Public Lands Act, water, wells, Oil Sands Conservation Act approval to recover the resources) over multiple phases at the front end of the process. 31

33 Preliminary estimates suggest that the process led to the following benefits: Reduced construction costs due to regulatory readiness and improved efficiency. Created project cost savings of about 3 per cent of the project capital cost. About $50 MM for a bbl/day project. Return on investment for an in situ oil sands project to industry has the potential to improve by approximately 0.5 per cent. It is through efforts such as the IDA process that government can work with industry and key stakeholders to substantially streamline the regulatory approval process eliminating redundancies and providing greater certainty while continuing to achieve social and environmental outcomes. This approach can be applied to both oil sands and conventional projects Regulatory Opportunities Oil Sands and Conventional/Unconventional The table below summarizes issues and specific regulatory initiatives and recommendations for government consideration that are either underway or in need of prioritization. There is an opportunity to establish a process to review these operational and regulatory items through a competitiveness lens, reducing burdens on both industry and government and the regulator. Table 4 Regulatory Initiative Inter-Agency Advisory Committee (IAAC) Conventional Approval Timelines Description Many Industry priority issues cross policy/regulatory dimensions and would benefit greatly from cross-jurisdictional collaboration. CAPP has instituted an interagency advisory committee (IAAC) consisting of senior representatives AER, ADOE, AEP, IR and CAPP CAPP conducted a cross-jurisdictional comparison to characterize approval timelines. The analysis demonstrated up to a 148 day advantage for applications in B.C. and Saskatchewan, and up to a 190- day advantage compared to some jurisdictions within the U.S., relative to the full Alberta non-routine well-licensing process (and in particular in the event that statements of concern (SOCs) are filed). Recommended Approach Endorse and support the mandate and activity of the IAAC. Identify and resolve policy and regulatory barriers that can improve outcomes through an integrated effort led by an Inter- Agency Advisory Committee. Adopt benchmark targets for conventional application timelines that are in line with comparable jurisdictions (in particular with respect to management of statements of concern and non-routine applications) 32

34 Regulatory Initiative Integrated Decision Approach (IDA) AER/ACO Interactions and Statement of Concern Process Borrow Pit Requirements Description To fully support the Integrated Decision Approach (IDA), the manner in which the shared legislation (PLA, Water Act, and Environmental Protection and Enhancement Act) between AER and AEP is administered needs to be reviewed to assess implications the legislation will have the implementation of IDA. There are known processes which should be addressed before the IDA project gets too far in implementation: Surface lease variance Harmonization of AEP/AER expiry dates Enhanced public notice and Directive 56 consultation The ACO and AER processes are not harmonized and too frequently lead to inconsistent guidance to proponents. The failure to effectively manage the interface between these bodies frequently results in the need to revisit questions. The lack of harmonization between the Alberta process and federal processes also creates further complication. Multiple regulatory bodies still exist with overlapping jurisdiction with respect to borrow pits for conventional and oil sands developments. This has created a number of issues that jeopardize construction and production project schedules for operators, thereby resulting in deferred royalties. These requirements have also lead to negative environmental and social outcomes such as increased fragmentation, proliferation of access roads and pits, and increased traffic. Recommended Approach Continue to support the development of the Integrated Decision Approach (IDA) as a standard approach to approving conventional, unconventional and oil sands resource projects. Establish firm approval targets and timelines for all projects, to help reduce the number and frequency of Supplemental Information Requests (SIRs) to help drive toward elimination of out of scope questions Implement a collaborative and focused effort to improve and integrate the Statement of Concern management process with the Aboriginal Consultation Office s First Nation and Metis Settlement consultation adequacy decisions. In the short term, a collaborative review of the Joint Operating Procedures that includes the opportunity for industry feedback could lead to improved outcomes. Key elements include establishing Best in Class guidelines to identify goals for the time required for decision making and processing of applications In the long term, centralizing the AER s directly and adversely affected test with the ACO s test of adverse impact to exercise Treaty Rights and traditional uses would provide proponents additional regulatory certainty, while continuing to respect Aboriginal interests. As well, seeking to harmonize the Alberta processes with federal processes as well as between the ACO and the AER would help to avoid duplication and inconsistencies. Implement a collaborative and focused effort to improve and integrate the borrow pits application review process. Doing so will result in significant operational, environmental and safety enhancements. 33

35 Regulatory Initiative Enhanced Approval Process (EAP) Integrated Standards & Guidelines (IS&G) PLA Renewals PLA In Situ Oil Sands (ISOS) Development Planning Flexibility Description The IS&Gs are based on a consolidation of SRD requirements in existence before September 1, This predates the oil and gas industry s move to explore unconventional resource plays, such as the Duvernay and Montney. As a result, the consolidated standards do not address unconventional resource requirements for larger pads and wider, year-round access roads. This incongruence of the current requirements also results in timeline delays as referred to previously. In an unanticipated move, the AEP has recently rescinded the EAP IS&G and replaced with the Master Schedule of Standards and Conditions. Significant concerns were identified, primarily related to: substantive changes to the approval conditions within the guidance documents; the lack of consultation with industry on the changes; and previously raised industry-identified EAP enhancements/opportunities that were not addressed. Prior to September 2014 pre-eap dispositions that had a term of 20 or 25 years would be automatically renewed by the SRD via a letter sent to the disposition owner. In September 2014 the AER introduced a new process for the renewal of these dispositions resulting in significant increases to timing and costs The AER has completed a short term fix which addressed these issues in the near term, but a long term fix has policy constraints. The systems in place for Public Land Act Dispositions do not consider the flexibility necessary to place surface pads within an approved ISOS development and this leads to unnecessary applications. This item will limit the effectiveness of the IDA approach for ISOS. Recommended Approach Provide opportunity to collaboratively review and provide feedback to the Master Schedule of Standards and Conditions. Review opportunity to advance from the short term solution that is currently underway at the AER to a longer term one. Such a solution would require engagement of multiple agencies via an inter-agency review of the renewal processes to scope enhancement opportunities. Reduce the number of surface applications or provide location variance to support an approved mineral extraction development for related activities (where past AER decisions and EPEA approvals are in place); Provide flexibility for pre-construction changes in the design and placement of infrastructure to support an approved mineral extraction development within an approved boundary; Provide a stronger approach to integration and the minimization of footprint within the project. 34

36 Regulatory Initiative Tailings Management Framework, Mine Financial Securities Plan Update Directive 82 Sulphur Recovery Description Recent decision to not approve Suncor Tailings management plan creates significant additional process and outcome uncertainty for all OS mines. TMF MFSP multi-stakeholder discussions regarding MFSP to determine additional potential security requirements due to profile deviation triggers. Options deliverable to be prepared by end of Q3 by AEP for review. MFSP Auditor General Report, CAPP/industry submission reviewed with AEP, AE, ATB and AER in June to provide clarity and context. AEP indicating they may be recommending changes to MFSP in the fall. Operators are motivated to develop the oil sands resources in a manner that balances the three pillars of sustainability: economics, environment and social. Flexibility and discretion within legislation and D082 should be leveraged by approvers to address aspects related to other properties within the ore (e.g. fines, chemistry, etc.). that can have implications to plant efficiency, reliability and the accumulation of fluid tailings. To ensure compliance with ID most operations have undertaken to install sulphur scavenger systems (liquid/solid). Fluctuating sulphur production rates coupled with challenging produced gas concentrations of carbon dioxide have made sulphur recovery at most mid-size in situ oil sands (ISOS) operations not a viable alternative. AER has completed a short-term project, whereby AER did not require over recovery of sulphur subsequent to when removal plants are down for maintenance, that provided an operational cost savings of $3.22 MM across industry for 2017 Recommended Approach Work with industry and proponents to develop a tailings management and MFSP framework that is outcomes focused, recognizes existing tailings technologies, enables compliance and does not unnecessarily hinder the economic viability of industry. OAG report in 2015 made a number of recommendations/comments that may not have been well informed regarding the MFSP. The MFSP program was designed and continues to ensure that each approval is fully secured at all times. Asset security transitions to financial security towards the end of mine life. To complement the current Directive, issue an information letter to require consideration of recent policy development (e.g. CLCP and TMF) and to give due consideration to other oil sand properties, in addition to bitumen and ore grade. Support AER long term decisions on proposals from operators as necessary. Extend the short term solution realized to the next 5 years or greater. 35

37 Regulatory Initiative EPEA/Water Act Monitoring and Reporting Directive 50 Drilling Waste Management related to Evaluation holes to support Oil Sands Scheme Approvals Description All monitoring data collected has cost associated. Approval monitoring program requirements are not focused in a manner commensurate with risk Regional monitoring requirements are under the jurisdiction of the government department formerly AEMERA and yet are still maintained within EPEA approvals. Reporting information submitted to AER as required by EPEA and other pieces of legislation is not in a usable format (i.e. PDF) that allows the AER to easily compile or analyze the data. For much of the data submitted there is no clear link to risk or regulatory utility. This results in the AER manually seeking out and entering data in order for it to be used in any AER performance assessment processes The disposal of drilling waste into an external tailings facility (ETF) does not pose any adverse air, soil, surface water, or groundwater impacts and will achieve the equivalent level of environmental protection as methods currently listed in D 050. The overall environmental impacts of an evaluation well can be decreased by utilizing existing disposal structures, such as an ETF, rather than the typical method of mix bury cover disposal in excavated pits or transported to licensed facilities. Recommended Approach Remove all regional monitoring conditions that are the responsibility of the GoA department Immediate relief on submission requirements of reports that are not needed at the prescribed frequency outlined in EPEA to assess performance or mitigate risk Move to Annual or By Exception reporting cadence for all monitored components that do not have a monthly performance evaluation process Harmonize the reporting requirements for sector EPEA approvals Explore other formats and means to review or submit the data to the AER to meet needs of KPI efforts Enable an ETF as a prescribed method of disposal for drilling waste from evaluation wells that are located outside of an approved mine scheme. 36

38 Regulatory Initiative Alberta Wetland Policy Implementation Description The Alberta Wetland Policy has been in effect province-wide since July 2016, but the regulatory processes required to implement the policy for oil and gas activities in the Green Area are still under development. There is ongoing regulatory uncertainty and an inconsistent understanding of the expectations and requirements for industry. Forthcoming changes with respect to how the Water Act is administered in the Green Area are expected to have regulatory load, costs and schedule implications. Since the Alberta Wetland Policy was released in September 2013, CAPP has engaged at length with AEP and the AER to seek clarity on policy scope and regulatory processes. The suite of policy directives, guides, tools and forms used in wetland assessments and regulatory applications has created a complex system to navigate. Lack of industry engagement prior to posting updates to policy implementation documents leads to uneven interpretation of the requirements and unintended consequences for projects. Recommended Approach Issue publicly available, simplified guidance (e.g., fact sheet/bulletin, process map) to provide the necessary regulatory clarity for oil and gas activities and achieve consistent interpretation of requirements. Deliver a policy implementation information session for industry in Engage with industry in advance of issuing updated policy implementation documentation to convey new requirements and test proposed language for clarity. Seek ways to minimize the additional regulatory burden for industry in fulfillment of Water Act requirements in the Green Area. 37

39 Regulatory Initiative Oil Sands Monitoring Description Government and industry share a common goal of implementing monitoring systems that are integrated, effective and efficient and have the confidence of all stakeholders Currently industry pays $50million annually to the government for monitoring. Recommended Approach Greater transparency on the program budget, program elements, and annual spend should be offered to all program stakeholders, including industry. The focus on stakeholder input should be expanded to include assessment and prioritization of environmental monitoring. The expanded involvement should provide a governance structure that incorporates ENGO and industry stakeholders in advisory groups, in addition to indigenous stakeholders. Progress needs to be made on aligning and coordinating regional monitoring with existing regulatory requirements to minimize redundancies, reduce monitoring costs and increase efficiencies. This is a key commitment of the program from 2012 that has yet to be realized. For the monitoring to drive improvement in environmental performance, greater transparency is required on monitoring and research data gathered and faster, more effective reporting. An initial positive step would be to make project outlines available and to complete a report on the state of the environment. 38

40 Regulatory Initiative Land Use Planning Integrated Water Management (Mine Water Returns) Description LARP still missing critical framework the Biodiversity Management Framework (BMF), 9 years after the plan was released. Landscape Management Plan (LMP) also outstanding from government. Moose Lake Access Management Plan (MLAMP) decision outstanding, initial report was expected summer Current lack of stakeholder engagement process puts credibility of LARP at risk. The first mine will need to return water by 2023 in order to successfully reclaim tailings ponds and achieve mine closure. A process to return water needs to be in place years in advance. If this does not occur, additional tailings storage will be required, which is contrary to the stated objectives of the TMF and the desires of stakeholders. Focus to date has been on regulatory processes in place, however, focus is needed on the next phase of development, and associated regulatory oversight, to ensure that effective management of water associated with oil sands mining. Recommended Approach Completion of all elements of LARP is critical to provide the certainty necessary for future oil sands development. Government must develop regional plans that provide predictability in resource access through the active management of landscapes while providing confidence in responsible resource development through a system of management to address cumulative effects to land, air and water. Government must provide confidence in regional plans and associated land management tools can be used as a means for fulfilling obligations under federal legislation (i.e., stewardship (s. 10) and recovery (s.11) under SARA). Sub regional plans (including MLAMP) should always be developed transparently using established land use planning principles and process and demonstrate consistency and computability with the broader LARP LMP and environmental management frameworks. A functioning LARP multi-stakeholder engagement process that enjoys the support of all stakeholders is essential to the credibility of provincial regional planning, and to support future oil sands development. Actively pursue initiatives relative to the regulatory processes for water release applications as well as the development of appropriate, science based, criteria for release of water to mitigate potential for unacceptable local or regional effects. Stand up SAG to close technical gaps required to enable water return. 39

41 4.4 Modernizing Alberta s Regulatory and Policy Framework for the Long Term The government has undertaken significant efforts to modernize Alberta s climate plan and royalty regime. A similar effort could be undertaken to modernize Alberta s regulatory and policy regime, maintaining strong environmental and social outcomes in an effective and efficient manner. The foundation of Alberta s regulatory framework for the oil and natural gas sector depends on the proper functioning of four key pillars: AER, ACO, Monitoring, and Regional Land-Use Planning. Currently, this framework is unbalanced, leading to tensions between stakeholders, indigenous communities and industry, and resulting in difficult decisions for government and regulators. Figure 19: Alberta Regulatory Framework A truly world class regulatory framework requires each pillar of the framework to function properly, not over relying on any individual pillar at the expense of another. A modernized regulatory framework would provide for stronger environmental performance, more meaningful consultation and increased industry certainty, thereby improving competitiveness. This will allow for truly sustainable development in every sense: environmental, social and economic. 40