Suncor Energy 2021 Investor Day | Wednesday, 26 May  

Speaker: Trevor Bell

Welcome to Suncor's 2021 Investor Day. My name is Trevor Bell, Vice President of Investor Relations.
Presenting this morning are Mark Little, President and Chief Executive Officer; and Alister Cowan, Chief Financial Officer.
Please note that today's comments contain forward-looking information. The actual results may differ materially from the expected results because of various risk factors and assumptions that are described in our 2021 Investor Day presentation material – as well in our current Annual Information Form which is available on SEDAR, EDGAR and our website, suncor.com.
Unless otherwise noted all numbers presented here today are in Canadian dollars. Certain financial measures referred to in comments made today are not prescribed by Canadian GAAP. For a description of these financial measures, please see our 2021 Investor Day presentation material.
Following the presentation, we will have a question and answer session moderated by myself. In order to submit your questions please proceed to the panel beside our video presentation window. We will be taking submissions until the end of our formal presentation. In addition, we will incorporate a 5-minute break within the presentation to allow everyone to check their emails and refresh their morning beverage of choice.
Now, it’s my pleasure to introduce Mark Little, President and Chief Executive Officer of Suncor Energy.

Speaker: Mark Little

Good morning and thank you for joining us for our Investor Day.
As most of you are aware, we have not traditionally held annual investor days, and in fact this is the second investor day in the history of our company. It’s important for us to spend today providing clarity and details around the medium-term outlook for our business and answer any questions you may have.
2020 was an unprecedented time in our history. A collapse in crude markets and significant demand shock meant that both sides of our business were under pressure. And we made some difficult decisions to protect the financial health of our company, lower our corporate breakeven and reduce our costs. These decisions had consequences to our business and to you as shareholders. Specifically, there were impacts to our upstream production, $1B of our $2B of free funds flow initiatives were deferred to 2025, and our dividend was reduced, and we suspended our share buyback. We appreciate the direct feedback that you gave us. Given all of these circumstances, it’s important for us to provide details about our plans for our business.

Specifically:

• I will discuss our operational outlook to 2025 which will highlight strong asset performance and the continued outperformance of our downstream;
• Alister will provide details on our $2B of free funds flow initiatives and confirm we’re on track to deliver or exceed our commitments;
• Alister will also discuss how strong operational performance and achieving our $2B of free funds flow growth will translate into significant increases in shareholder returns and substantial debt reductions;
• And I will provide you with our strategic objectives and goal around absolute carbon emissions reductions which is supported by pragmatic and highly economic investments that are in – or synergistic with – our core capabilities.

We have a lot to cover in the next two hours and then we’ll finish the day with an hour of answering your questions.

As I noted in my opening remarks – the events of the past year, and the resulting volatility, had most companies review their business strategies and the macro assumptions on which those strategies were based. In early 2020, oil demand surpassed 100 million barrels a day. Then, in the second quarter as COVID–19 stay-in-place orders were issued globally and global economic activity halted, demand collapsed – resulting in crude and refined product inventories hitting tank tops around the globe. However, even in these extreme circumstances, demand was still above 80 million barrels per day in the second quarter of 2020. While some predicted the effects of 2020 to be a catalyst for permanent crude demand destruction, demand steadily recovered through the remainder of the year as vaccine rollouts began and economies progressively reopened.

As 2020 ended, oil demand averaged over 90 million barrels a day for the entire year. Global oil products demand is expected to continue to increase throughout 2021, accelerating in the second half of the year, reaching pre-pandemic levels in 2022. We anticipate moderate growth into the next decade driven by non-OECD demand, before eventually plateauing. Following this plateau, we expect a gradual, multi-decade reduction in oil demand, as economies continue to shift their energy mix towards low carbon intensity energy sources. However, the trajectory of the world’s total energy needs will continue to rise for decades to come. And oil will remain a significant component of the global energy mix, even as low carbon intensity forms of energy continue to grow.

In 2018 we shifted our strategic focus to maximizing the long-term free funds flow generation of our existing asset base, rather than pursuing mega projects to continue to grow production. This macro energy outlook supports our disciplined strategy.

This strategy is governed by simple principle of optimizing the value capture of the integrated value chain. From this perspective, Suncor’s optimal production level is determined at the intersection of sustainable margin, cost and capital, rather than maximizing production. We are seeking to maximize long-term free funds flow – which may not result in being the lowest cost or capital, but strong performance in each of these is obviously required to generate top quartile free funds flow.

This commitment to value over volume is embedded in our production plans through 2025. Over the next four years, our upstream production is expected to average approximately 800 thousand barrels per day – exhibiting modest absolute growth from 2021. We remain committed to capital discipline and reliably operating at utilizations of at least 90% across our upstream asset base, as we did from 2015 to 2019. At our Base Plant, Syncrude and Fort Hills mining assets, we are targeting 90% utilization and at our in-situ assets we expect utilizations in the range of 95%.

While we have substantial lower margin, bitumen sales growth opportunities in our upstream portfolio, growing greenfield bitumen production today requires costs, capital and market access that would not optimize our long-term free funds flow generation. Instead, this resource will be developed, when needed, to maintain production and ensure reliable feedstock for our upgrading.

A good example of this is the eventual need to replace the bitumen production that feeds the Base Plant upgrader, as the mine comes to its end of life mid-next decade. Our bitumen resource is world class and unmatched in its scale and that means we have many options to backfill this production – however no decisions or capital spend are required until later this decade.

Bitumen production is core for Suncor. However, like all prolific oil basins, it has inherent barriers. For Alberta’s bitumen, these barriers are landlocked geography, crude density and a limited number of North American refineries that can process this heavy oil. We mitigate these challenges through our physical integration and committed pipeline capacity. By reliably operating our upgrading assets to convert bitumen to synthetic crude oil, we are getting four key benefits:

1. We’re reducing our exposure to local bitumen pricing,
2. We’re lowering our transportation requirements and costs
3. We’re expanding the refiners that are capable of using our product, and
4. We’re increasing the price and the value that we receive.

Now, to provide some context – on our 800,000 barrel per day of Upstream production: approximately 85,000 barrels of that is offshore production that’s linked to Brent crude prices; 500,000 barrels a day, or 2/3rds is upgraded SCO production and roughly 215,000 barrels a day leaves the basin as bitumen.

But of the bitumen that leaves the basin, about 30,000 barrels is consumed as feedstock at our Edmonton refinery and 95,000 barrels per day is high quality Fort Hills bitumen that receives global pricing through our secured access to the Gulf Coast. Resulting in only 90,000 barrels per day, or just 10% of our production being exposed to local, and potentially discounted, bitumen prices.

Our ability to convert bitumen into high value products is critical to maximizing margin while limiting our exposure to pricing volatility. Most important, is keeping the upgraders operating at 90% utilization. Flexibility to optimize both our bitumen supply, and the products from the upgrader, combined with superior marketing and logistics capabilities out of the basin, are key strengths that enable this targeted utilization rate.

In particular, feedstock flexibility for the processing units provides valuable optionality when planned or unplanned outages occur. The ability to bring in-situ bitumen from Firebag into Base Plant, and now onto Syncrude, minimizes the risk of our upgraders being short of bitumen feedstock. It also has the added advantage of blending feedstocks to an optimal quality, enhancing our upgrader reliability.

In our E&P business, the principles of maximizing long-term value generation also apply. Our offshore operations are located in high quality, low risk basins and generate funds from operations and geographic diversification for the company. Given Suncor’s long-life reserves in Oil Sands, unlike many pure play E&P operators, our investment decisions are focused on positioning the business to consistently generate free funds flow and high returns, rather than replacing reserves or maintaining production volumes.

During the downturn in 2020, like many others did, we reduced economic investment, largely infill drilling, to conserve capital. These decisions, will have production impacts over the coming years as these are conventional basins with natural declines. However, we have many high return, low capital opportunities across our offshore portfolio and expect to be able to fully produce significant free funds flow going forward.

The underlying principle of our value over volume strategy is to maximize the long-term shareholder returns by optimizing the value of each barrel that we produce.

Our focus is on rationalizing our costs and sustainment and maintenance capital, and by increasing the productivity and efficiency of our operations that produce the crude and products that we sell. Although absolute upstream production profile intentionally plateaus, make no mistake, our funds from operations continues to grow. And these structural cost improvements, rather than greenfield growth, allows us to commit to growing cash returns to shareholders from these increasing free funds flow profile. These are the hallmarks of our ‘value over volume’ strategy.

Moving to Syncrude – when we increased our ownership through our acquisition of Canadian Oil Sands in 2016, and subsequent smaller acquisitions, our stated target was to achieve 90% utilization and reduce our unit cash operating costs to $30 Canadian per barrel. We knew that meeting these targets would require owner collaboration, process improvements, investment in critical infrastructure to ensure access to abundant feedstock and eventually, the reduction of absolute costs.

Through the sharing of operating and maintenance best practices, we’ve seen progress and sustained improvement in operational performance. Then, in late 2020, we completed the interconnecting pipelines between Base Plant and Syncrude to allow for the transfer of bitumen and intermediate products between the assets, providing significant operational flexibility.

Although good progress has been made in driving down the costs at Syncrude from these process and flexibility improvements – more needs to be done to achieve our $30 per barrel target. We knew this required a significant change in the operating structure of the joint venture and our collaboration with other owners over the past few years is set up to reap rewards. At the end of the third quarter Suncor will take over operatorship of Syncrude – similar to the structure and governance employed at Fort Hills.

Once operatorship is transferred, we aim to capture $300 million of gross synergies, through the sharing of regional and functional services, coordinating maintenance programs, and the rationalization of the combined workforce. I would note that these savings are incremental to the $2 billion of free funds flow improvement projects that Alister will speak to later this morning.

• The first $100 million of annual savings are expected to be achieved within 6 months of operatorship through workforce reductions, and the elimination of duplicative costs that many corporate and administrative functions are rolled into Suncor processes and systems.
• We expect the second $100 million to materialize throughout 2022, which will come from further workforce reductions and supply chain management functions, leveraging the joint purchasing power of the neighboring mining operations and consolidating warehousing and inventory management.
• And finally, the second year of operatorship, we expect the final $100 million to materialize in the form of coordinated turnaround, maintenance and equipment strategies.

Syncrude has temporarily achieved our $30 per barrel cash operating cost in the past. Once the full benefits of this cost reductions are realized, we expect to sustainably achieve this target by the end of 2023.

Physically connecting our oil sands assets increases their value through operational flexibility. Similarly, the integration of our broader asset portfolio also adds value by connecting our upstream to our downstream refining complex and through our wholesale and retail networks.

Our midstream operation leverages our marketing and trading capabilities and our logistics assets to optimize the daily balance of: equity crude entering our refineries, the capturing of regional arbitrage, third-party sales and global export logistics, and determining which product slates are optimal for the market on any given day. These capabilities are supported by our assets vast network of storage terminals, pipeline commitments and investments in our people and technology.

The outsized value that this combination generates is demonstrated by our ratable outperformance to benchmark pricing in both the Upstream and the Downstream. In the Upstream, we consistently realized bitumen pricing that has outperformed the WCS benchmark by 5% over the past 2 years. More broadly, across our refineries, it allows us to capitalize on our low-cost refining feedstock and competitive market access – capturing margins of 130% of New York Harbor 2-1-1 crack, on average, over the past 2 years.

Over the past 10 years, the percentage of our refining feedstock sourced from equity barrels has increased from 30% to over 40%, and at times in 2020, exceeding 50%. But it’s important to note that this goal is not to achieve 100% physical integration – it’s about maximizing the margin of each barrel we produce, while managing costs, and capital and market risk. Our logistics and marketing capabilities enable us to source 100% of our downstream feedstock from inland crudes. The flexibility to refine the most discounted feedstock results in increased margin capture.

The combination of our midstream logistics portfolio and marketing and trading capabilities is an underappreciated and undervalued part of our business as it consistently produces outsized value while mitigating downside pricing and sales volumes risk.

Canada is a unique market for refined products. It’s size, cold weather climate, low population density and large GDP reliance on resource-based industries creates strong demand for energy with substantial and complex logistics. Compared to the United States, a major exporter of refined product, Canada and its refineries are typically a domestic centric market. Many of the egress dynamics encountered in the Upstream business are also present in the downstream. However, our strong logistics networks, advantaged refining scale and locations, and midstream capability, results in value accretive performance.

Our downstream profitability is the best in class in North America due to four key factors that we see as structural advantages now, and into the future.

First, our geographical advantage with feedstock flexibility. Our refineries are either located near or have logistics capabilities to source low-cost feedstock. This maximizes our gross margin and reduces the risk of our feedstock costs.

Second and third advantages come from our refineries themselves. While not the most complex, our refineries are weighted toward heavier feedstocks and are configured to produce larger proportion of diesel and asphalt versus gasoline and bunker fuel. We’ve formed this advantage through investments made over the past decade and we’ve enhanced our refining complex in Edmonton to take more heavy sour and physically integrated it with our Base Plant Upgrader. We made metallurgical upgrades at Sarnia to take our own heavy sour crudes. And following the reversal of Line 9 in 2015, we access western Canadian crude feedstock in our Montreal refinery. We invested in Montreal and Sarnia logistics to operate as a single complex, and to maximize the value capture of heavy feedstocks and provide flexibility in product supply for central Canada. Canada’s climate, land mass, resource-based industries and infrastructure spending is expected to continue to drive the demand for refined product, particularly diesel and asphalt.

Our final structural advantage is our connection and proximity to the customer through our retail and wholesale network in key metropolitan areas – and our scale within those areas. In Denver, for example, our Commerce City facility is the largest refinery in this niche US Rockies market and is strategically pipeline connected to the Denver International Airport. Secured channels like this, combined with our tank and terminal infrastructure, enables us to run our refineries with minimal logistics constraints. We have structured our downstream portfolio to sell the vast majority of our refined product though our wholesale and retail channels. We capture maximum value on the remaining product sales through our marketing and trading organization, leveraging both our domestic and export logistics capabilities.

2020 was extremely tough on our industry and especially so on the downstream business. However, it demonstrated the strength of these advantages! In a year where North American products demand eroded by more than 20 per cent and the New York Harbor cracks averaged below US$12 a barrel, our downstream business generated $2.1 billion in funds from operations on a LIFO basis. In addition, our downstream produced $1.6 billion of free funds flow when several of our competitors failed to generate positive cash margins.

As was demonstrated in 2020, we consistently generate industry leading performance. We operate our refineries at higher utilizations than the other refining network in Canada or region in the United States, averaging 11% higher in Canada and 5% above the US national average over the past 10 years. And, most importantly, it results in cash generation per barrel that far exceeds any other refiner in North America.

This past year was a clear proof point of the strength of our downstream operations, particularly in relation to our peers. We experienced strong utilizations throughout the pandemic. In 2020, our refineries averaged 12% higher utilization than the Canadian average and 10% above the US average. While several downstream businesses focused on mitigating cash losses in 2020, our refining business generated positive LIFO EBITDA of nearly $10.50 per barrel. This is nearly twice the margin per barrel generated than the next best refiner and is before the benefits of our retail and wholesale businesses.

2020 also saw the rationalization of a number of North American refineries as refined product demand declined during the pandemic. The refineries that were shut down or converted to other purposes, lacked some, or all, of these four structural advantages and were typically smaller, coastal, light oil refineries, with unsecured channels to consumers. Going forward, we believe our advantages will prove critical to not only maintaining industry leading refining profitability, but to continue to prosper as further rationalization occurs.

Our wholesale and retail channels, which we refer to as rack-forward, are among the best in North America. We are number one market share in Canada and are ranked as the number one fuel brand in the country.

With over one million transactions per day, and over 4.7 million loyalty program members, and over 1,800 stations providing nearly 300,000 barrels per day of product to our customers – Petro-Canada is among the most trusted providers of energy for consumers in North America.

While we have not historically provided detailed disclosure on the funds from operations contribution of this Rackforward business, we intend to provide additional disclosure in the coming quarters. This portion of our business provides a stable margin, even during extreme market events like we saw in 2020, and more importantly a secured destination for our refined product, allowing our refineries to run at the higher utilizations that I’ve already discussed.

Last year our Rackforward business generated over $4.75 per barrel of EBITDA, incremental to the roughly $10.50 per barrel I spoke to earlier. This highlights the insulated nature of Rackforward and the strategic advantage it affords us by maintaining consistent Downstream strength in volatile markets. We expect this margin to continue to grow given the current market dynamics. And we will continue to optimize our assets as consumer demands change.

This consistent outperformance of value capture across the entire downstream business is only possible because of our unique portfolio of physically integrated assets – which could not be recreated in today’s market and would be lost if our integrated downstream assets were disaggregated.

In summary, our value over volume strategy does not rely on significant upstream production growth or involve large new development projects with significant capital requirements and risk. It does however focus on growing and optimizing the funds from operations of our existing assets. Optimization is accomplished through reducing our overall cost structure and sustainment capital requirements, while leveraging the physical integration of our assets to maximize the margin of each and every barrel we produce.

With this “value over volume” strategy in mind, you will recall that we set out to strengthen Suncor’s resilience by adding $2 billion of free funds flow, largely independent of pricing and production growth. We said that it would instead - be achieved by optimizing and enhancing our existing portfolio. Achieving this outcome is critical to build a more resilient Suncor.
I will now pass it over to Alister to discuss our progress on these initiatives.

Speaker: Alister Cowan

Thanks, Mark.  Those who havefollowed Suncor for some time will remember when we first introduced our $2billion free funds flow goal in 2018.  We laid out a plan to grow free fundsflow through investments in low capital intensity projects.  These investmentsare made to structurally improve the funds from operations of our existing portfoliothrough reduced costs and improved margin capture.  These initiatives make thecompany more resilient during times of commodity price or demand volatility.  Assuch, we continued to invest in them through 2020, albeit at a slower pace, whenothers chose to reduce spending to sustaining capital or less.  By 2025, theseinitiatives are expected to unlock approximately $1.60/share of increased freefunds flow which will be available for debt reduction and higher cash returnsfor our shareholders.

As Mark mentioned, our goal was toadd $2 billion, or 20%, to Suncor’s free funds flow generation withoutmaterially growing production.  And we have made great progress on this andexpect to realize roughly $450 million this year.  To transparently measureprogress of these initiatives, we have outlined our baseline in the investorday materials for convenience.

While the impact on our businessis significant, the spend required to generate this value is relatively modestover the period.  The total capital investment is approximately $3.5 billionwith roughly $1.5 billion spent to date – leaving approximately $2.0 billion ofspend remaining to complete the $2B of annual incremental free funds flow goal by2025.  I should highlight that, of this remaining spend, 65%, or $1.3 billion,is allocated to the Base Plant Cogen and Forty Mile Wind projects. 

Looking at these initiatives, inaggregate, the overall capital investment has a full cycle return in excess of40% and by 2024 the cumulative benefit generated to date is expected to haveexceeded the total capital budget of the whole program of $3.5 billion – and thencontinue to add over $2 billion of free funds flow each year going forward.

We have grouped the projects into 9broader initiatives.  I will go through each initiative and highlight theirfinancial benefit, but I would encourage you to visit the Investor Daypresentation materials which have additional details.

We expect the benefits of theseinitiatives to begin this year with over $450 million of recurring annualbenefit expected to be realized in 2021.  We’re on track to exceed $1 billionof annual incremental free funds flow by 2023 and over $2 billion annually in2025 and beyond.  This equates to roughly 30 cents/share in 2021, 90 cents/sharein 2023, increasing to $1.60/share in 2025 and thereafter.

Most importantly, these returnsare largely independent of oil prices.

Let’s discuss the initiatives thatare expected to allow us to achieve the first billion dollars of incrementalfree funds flow by 2023.

One of the first structuraloptimization opportunities we identified was to better leverage our midstreamlogistics portfolio.  This resulted in centralizing our Supply, Marketing &Trading organizations in 2018 into a single team and investing in improving ourexpertise.

For example, we are creating adigital framework with which to track the molecule and electron lifecycle throughour integrated business.  This will enable real time hydrocarbon inventorymanagement and increase our ability to more efficiently capitalize on regionalvalue opportunities across our North American midstream and logistics network.  We’vealso expanded our marketing and trading activities to cover all the products weproduce, not just upstream barrels, becoming more active in the management ofour inventories through asset backed trading.  This is only possible due to our50 million barrels of storage across North America, our committed and operatingpipeline access, along with our investment in people, processes and systems.

We are targeting incrementalannual free funds flow generation of $135 million per year by 2025 – splitevenly between improvements in crude and product realizations.

We’ve discussed the Syncrude InterconnectPipelines for some time, but the significance of this infrastructure cannot beoverstated in enhancing the regional synergies of our assets through theconnection of Suncor’s Base Plant to Syncrude.

The pipelines are intended to:

• increase margin on bitumen or sour barrels that can be sent from BasePlant to Syncrude and provide operational flexibility to minimize the impact ofplanned downtime by transferring both bitumen and intermediate feedstock betweenfacilities; and
• also reduce the lost value from unplanned downtime

These pipelines are criticalinfrastructure to consistently achieve the 90% utilization target at Syncrude.  InQ1, only three months after commissioning, Syncrude’s utilization was increasedby 3% because of the pipeline being in place – it’s an investment that’s alreadydemonstrating higher reliability and utilization.

We continue to expect theinterconnect pipelines to generate $100 million of incremental free funds flowby 2023 – increasing to $150 million by 2025.

One of the most significantinitiatives relates to our innovation and investment in tailings management. Not only is this initiative one of the largest in terms of its contribution tothe $2 billion target, with roughly $325 million in annual free funds flowsavings by 2025, the environmental benefits are equally impressive.  PermanentAquatic Storage Structure, or PASS for short, uses a chemical process todramatically accelerate particle settlement of tailings through a processcommonly used in municipal water treatment.  As a result, we no longer requirelarge separate areas of land to dry tailings, which also eliminates the needfor physical handling.

This new process is expected to shorten the timeline to reclamation by approximately 10years, it avoids expensive seasonal earth moving activities, and eliminatesthe need for an estimated 30 square kilometers of land disturbance.

Since the implementation of PASSin 2018, Base Plant has been treating more fluid tailings than it has produced.By the end of 2025, we expect to have reduced Base Plant fluid tailings peak inventoryby more than 15% and to have eliminated another tailings pond from thelandscape.

In addition to the obviousenvironmental benefits, each of these activities – reduced timeline, earthmoving, and land disturbance equate to savings in operating costs, sustainmentand maintenance capital and reclamation spend. These savings largely come from the elimination of approximately 400,000 worker hoursand 250,000 heavy duty equipment kilometers traveled each year that wererequired under the old tailings process.

The operational complexity and componentsof mining oil sands are vast, ranging from the shovel operator at the mineface, to the Autonomous Haul System control room and haul trucks, and finallyto primary and secondary extraction of the bitumen.  Each of these pieces areinextricably linked but until now, due to the inherent complexity of each step,have operated as somewhat independent components of the process.

The key to efficient miningoperations is to move the least amount of material, in the most efficientmanner, and to maximize reliability of processing facilities.  To achieve this,each mining component must work together.  However, there are far too manyvariables for a single individual to manually optimize the entire system inreal time – and this is where the Digital Mine comes in.

Thisinitiative encompasses far more than just autonomous haul systems.  At the mineface, real time efficiencies are made through programs such as the Virtual ShovelCoach, providing shovel operators with live metrics on optimized pay loads andreduced load times.  Approximately 70% of our total mining costs are associatedwith shovels and trucks.  And, as a result, even small improvements in ourefficiency at the mine face can result in tens of millions of dollars ofoperating cost savings.

A digital mine extractioninterface will use real time advanced analytics to support operators with livefeedback to optimize the bitumen froth production.  The program will predictthe optimal process environment for the ore coming into the plant – providing operatorswith valuable time to react to variations in resource quality.  This will lowerthe probability of process interruptions while improving the overall bitumenrecovery at the plant.  The initiative has been completed at our Base PlantPrimary Extraction and since its implementation it has already begun togenerate recurring funds flow benefits of roughly $20 million on an annualizedbasis.

Longer term, maintenance andreliability is expected to improve as we transition to condition-basedmonitoring through remote sensing instead of hourly based maintenanceschedules.  Predictive analytics will reduce failures and maximize equipmenteffectiveness at reduced cost. 

The rollout of Autonomous HaulSystems is ongoing, with reduced labor costs and routine maintenance continuingto validate our $1 per barrel cost reduction.  We believe the Digital Mine, incombination with AHS, will result in approximately $250 million of annual freefunds flow improvements in the form of operating costs and increasedreliability.  We expect roughly $200 million of this benefit to be achieved by2023. 

Every yearSuncor procures roughly $10 billion of services and materials on average.We’veundertaken several initiatives to optimize our supply chain and have begun torealize operating and sustainment and maintenance capital cost savings acrossthe business.

Forexample, in the case of consumable materials, we are on a path to reduce oursupplier list from over 1,000 entities in 2019, to 100 or less in 2022,generating stronger, more strategic supplier relationships.

One of the most impactful changesto how we operate is realized through a strategic partnership with Microsoft inwhich we will be digitizing all our supplier agreements and contracts toleverage the power of cloud computing.  Once complete, the application ofadvanced analytics and machine learning is expected to generate significantsavings over time by doing such things as verifying contract execution,avoiding service contract ‘leakage’, and conducting ‘should cost’ analysis inorder to accurately monitor and mitigate inflationary pressures.

With a structural free funds flowimprovement target of $225 million in 2025, and more than half expected to be achievedby 2023, this reflects a 2% sustainable cost reduction of our total servicesand materials. As we roll out our digital technologyinitiatives closer to 2025, we believe there’s potential upside to thisstructural savings target.  Similar supply chain initiatives in otherindustries have resulted in 2-5% of improvement benefits.

We have been undertaking a rationalizationand standardization of Suncor’s management and administrative processes.  Ourcurrent data and IT platforms are legacy from the Suncor/ PetroCanada merger,and multiple pre-merger acquisitions undertaken by PetroCanada. Standardization will change how our people work and interact with each other,access data and use our systems.

Currently, our administrative processesare standardized across only 30% of the enterprise, with data often spreadacross multiple systems – resulting in manual processes to plan and executework.  Once implemented in 2022, we will have standardization across 90% of theenterprise.

Standard systems and processes mayappear mundane, but the savings and efficiencies from this initiative aresignificant.  $275 million of recurring free funds flow generation is expected,largely resulting from a 10 to 15% workforce reduction as automated systemsreplace manual processes.

More importantly, this is afundamental enabler for numerous other initiatives and their associatedbenefits.  This project will provide accurate real time information to numerousareas of our business including crude inventory management, productsdistribution, spare parts management, and contract procurement, to name a few.

These first six initiatives I haveoutlined, comprise our plan to achieve approximately $1.3 billion ofincremental annual free funds flow by the end of 2023, of which we expectroughly $450 million to be achieved this year.  Of these benefits in 2023, 50%are intended to be achieved through reduced operating, selling and generalexpenses, or OS&G, 35% from increased utilization or margin, 10% throughreductions to sustainment and maintenance capital, and 5% from reclamationsavings.

All of the benefits are structuralimprovements to our free funds flow generation and amount to a lowering ofSuncor’s operating breakeven by approximately $4.50 per barrel, to US $25 WTI perbarrel by the end of 2023, resulting in roughly 90 cents/share of incrementalcash available to be returned to shareholders annually.

Specifically, on the OS&Gfront, by 2023 on a pre-tax basis, we plan to lower our total OS&G by over$900 million.  Now, I know you’re also looking to see how this progress will impactour long-term asset specific cost targets, and I will review these later.

The initiatives which make up theremainder of the $2 billion of incremental free funds flow generation are onplan to be achieved by 2025.

The Coke Boiler Replacement at ourBase Plant, and the Forty Mile Wind project in southern Alberta, are two highlyeconomic projects which are significant drivers to achieving our free fundsflow and carbon emissions reduction targets.

The Coke Fired Boiler Replacement,or ‘Cogen’, has numerous benefits. It improves the reliability of the BasePlant operations; it reduces sustainment and maintenance capital; it generates bothlow carbon steam for the mining operations and power to displace baseload coalfired power in Alberta and it generates carbon credits as a result.  All ofthis results in a ~20% full cycle rate of return.

The existing coke fired boiler, hasreached the end of its useful life and needs to be replaced.  Instead ofreplacing the unit in kind, our decision was instead to supply steam in a lowercost and carbon way through natural gas combustion.

Moving to Forty Mile, wind powergeneration, and our unique approach to being a merchant clean power producer,is nothing new to Suncor.  The Forty Mile merchant wind power project insouthern Alberta is another investment in our renewable portfolio that we’vebeen developing since the early-2000s.  The project has strong full cyclereturns with an estimated IRR of approximately 15% and is on track to becommissioned in late 2022.

It’s important to note we areselective in the jurisdictions in which to invest and we have chosen to be a merchantpower producer, utilizing our existing expertise in marketing power from ourcurrent 1,400 MWs of power generation, instead of signing low return governmentpower purchase agreements.  In addition, given that these power projects are inAlberta, we are able to generate carbon credits to offset against our basebusiness, strengthening the project economics.  This is a very unique approachto a wind investment, which enables us to generate mid-teens returns or greater.

The BasePlant Cogen and Forty Mile projects are expected to result in roughly $300million per year of incremental free funds flow – of which $250 million is fromnet power sales and carbon credit generation and roughly $50 million is fromreduced sustainment and maintenance capital at Base Plant. 

Combined,these projects will also avoid over 5 Megatons of CO₂ emissions peryear for Alberta – or the equivalent of over 1 million vehicles’ annualemissions on the road today. 

This next initiative highlightshow we are making modest capital investments to capture efficiencies in theBase Business and improve operational performance while reducing costs.  Weapply the industry standard term ‘debottleneck’ across our integrated model –and so these investments go beyond just adding production.

Our recent investments to increasethe nameplate capacity of Firebag by 6%, the Edmonton refinery capacity by 3%and expand our Burrard terminal are examples of this.  We have a number ofopportunities to make low capital, enhancements to our existing asset baseincluding future debottlenecking opportunities at Firebag and Fort Hills.

From these low capital investments,we expect to generate nearly $100 million of incremental annual free funds flowas debottlenecks improve our ability to capture value across our physicallyintegrated model.

Lastly, I am going to discussinitiatives focused on leveraging the power of data analytics to capitalize onnew ways of creating value.  Of the 30-plus projects currently in flight, I amgoing to highlight the two largest projects, which amount to over 60% of theinitiative’s $400 million of total annual free funds flow generation.

The first project we refer to asthe Integrated Energy Value Chain.  Now, integrationhas been a key competitive advantage for Suncor for over a decade, however, webelieve there’s still significant opportunity to extract more value from ourmodel as we leverage the power of technology.

This project will ultimately leadto an integrated ‘Central Optimization Center’.  This center will havevisibility across the whole value chain through a system-wide planning andoptimization platform, fed by real time data. 

A great example of the power ofthis platform is with respect to product blending.  Due to the current manualnature of determining the optimal crude blending schedule to maximize value,and the fact that we produce at least 16 distinct crude blends out of our OilSands operations, the ability to run multiple scenarios based on changingvariables and constraints is limited.  This also inhibits responsiveness duringunplanned events or quickly changing market conditions.

Data analytics will be able tochange the static, manual process to an automated, dynamic one that generatesoptimal values for blending while accounting for all the operationalvariables.  We expect this to ensure we consistently produce the highest valueproducts in real-time.

The Integrated Energy Value Chainis an initiative that will not only span crude, but also our refined products,natural gas, biofuels, power, hydrogen and carbon credit portfolios.  Weanticipate this one initiative to generate over $150 million per year in marginimprovements.

The next project to highlight is aprogram we refer to as Digitally Optimized Assets that empower Suncor fieldworkers to improve personal and process safety, to increase reliability, andoptimize cost performance of our assets.  To achieve this, workers will have adigital toolkit connecting them to Suncor personnel at other sites, enablingreal-time decisions from the field.

The remote capabilities will rangefrom having access to all the technical data required to operate and maintainthe assets – to the ability to simulate optimal production scenarios with adigital process model and the application of artificial intelligence.  And allof this occurs from the field with a handheld tablet.

We expect this initiative toreduce operating costs by over $100 million annually.

What’s important to understandabout the broader ‘Digital Technology Adoption’ category of initiatives and the$400 million of free funds flow we have attributed to it, is that these 30-plusinitiatives are only the start.  As the company continues to embrace itsdigital transformation, and our workforce becomes increasingly adept at beingdigitally enabled, we are confident there will be many more opportunities inthe future.

Our strategic objective ofincreasing the structural annual free funds flow generation of the existingasset base is being achieved today.  We expect to generate annual free fundsflow improvements of $450 million this year, $1.3 billion by the end of 2023,and more than $2.1 billion by the end of 2025.

On a pre-tax basis, by 2025, weanticipate these initiatives to have reduced absolute OS&G by $1.3 billionand increased our margin capture by $1.1 billion relative to our 2018/2019baseline.  While also reducing sustainment and maintenance capital by over $200million per year.

We now have all the initiativesidentified and being progressed to achieve the $2 billion target we committedto!   

These initiatives create astronger, more resilient and competitive company generating incremental freefunds flow to support increasing shareholder returns, while reducing debt and loweringour operating breakeven.  

We will now take a short 5-minutebreak and when we return, Mark will speak to our new carbon objectives and howSuncor is going to capitalize on low carbon energy opportunities.

Speaker: Mark Little

Suncor’s been on a sustainabilityjourney for decades and it’s one of the key reasons I joined the company over adecade ago.  And, to us, sustainability means all facets of ESG, not just onecomponent. Strong governance underlies strong ESG performance.  Strong ESGperformance leads to process and technology advancements which lower cost andcreates long term value – the PASS and Cogen investments Alister just spokeabout are excellent examples of this.  We’ve been evolving and growing ourbusiness, embracing technology change and innovation, and doing the rightthings.  We have expanded through the energy value chain and worked withdiverse stakeholders to turn a budding oil sands resource into one of theworld’s most reliable and ESG-leading oil basins.

Our leadership is reflected in ourenvironmental and social legacy, strategic investments and diversepartnerships, all underscored by leading governance practices.  We’ve disclosedour sustainability performance for over 25 years and publicly supported acarbon price for over 20 years.  We made our first renewable energy investmentin 2002 and set our first long-term sustainability goals in 2009.  In 2018, wedeclared our support for TCFD – the first North American oil producer to do so.And we’re the first Canadian oil producer to develop its own two-degreeclimate scenario, which we published in 2020 and it informed and enhanced our carbonstrategic objectives I will discuss.

We’ve achieved over 90% waterrecycle rates at our legacy oil sands operations and improved tailingsmanagement to the point now that we treat more tailings than we produce at ourBase Mine.  And in 2010, we were the first oil sands company to reclaim atailings pond, which has transformed a 220-hectare area that replicates thenatural environment in the region – and which we now call Wapisiw Lookout.

In 2016, we released our firstsocial goal: to change the way we think and act to build greater mutual trustand respect with Indigenous Peoples in Canada.  Since then, we entered into whatwe believe is Canada’s largest indigenous-private sector equity investment,with the East Tank Farm, setting a powerful precedence for the meaningfulinvolvement of Indigenous Peoples in energy development.  We’ve spent $4.5Bwith Indigenous businesses since 2014 and our $900 million 2020 spendrepresented approximately 10% of our total supplier expenditures.  We alsocontinue to expand our partnerships with First Nations across our retail andwholesale and refined products business, with close to 60 such arrangementstoday.  And we’ve had indigenous representation on our board of directors formore than 20 years.  Our social goal has shifted to a journey of reconciliationwith the aim of further strengthening our relationship through cultural andbehavioral changes within our organization. 

Over the past decade, we’ve alsomade significant investments in projects and technologies designed to lower ourcarbon emissions in our base business, and in new opportunities for energysystem expansion.  Our focus on technology and operational excellence hasreduced the emissions intensity of our Oil Sands Base Plant by approximately 55%since 1990.  We deployed leading new mining technologies at Fort Hills whereits greenhouse gas emissions on a full life cycle basis is equal to the averageemissions of barrels refined in North America.  And we’re investing incommercial pilots of in-situ solvent technologies that have the potential tolower emissions by 50-70%.  As part of our expanding energy offerings, we’vecompleted Canada’s first Electric Highway, we’re increasing low powergeneration with our cogeneration facility at Oil Sands and our Forty Mile windproject, and we’re enabling advanced low carbon technologies by way ofinvestments in Enerkem, Lanzatech, LanzaJet and, most recently, Svante.

This brief introduction outlinesour proud history and leadership track record in sustainability.  Our focusedapproach on continuing to improve is underpinned by leading governancepractices and a track record of delivering on our commitments.

Over the past several years, thefocus has been on one specific area of ESG, carbon emissions. In the past year,many organizations have announced net zero carbon ambitions, with varyingtimelines, approaches and levels of detail on how they plan to achieve them.  We’vebeen measured in developing and communicating any new carbon strategicobjectives.  Our approach has always been to be thoughtful, substantive andtransparent in our goal setting, both in our environmental and financialperformance.

Unlike many energy peers who aresetting carbon emission targets and ambitions for the first time, the strategiccarbon objectives I’m discussing today are not the first time that we’ve setclimate targets – rather this is our third set of targets for driving down ouremissions.

In 2009, we set four environmentalgoals, including energy efficiency, that we substantially met or exceeded by2015.  In 2015 we set a new goal to reduce the carbon emissions intensity ofour production by 30% by 2030.  We have made considerable progress on this goaland continue to advance it with many of the investments that I’ve justreferenced.

In establishing our strategicobjectives associated with carbon emissions, we’re continuing this evolutionwhile improving the resilience and competitiveness of our business.  We areconfident we can profitably grow returns for investors while lowering ourcarbon emissions – and helping others reduce theirs.  We have a strongfoundation to build on, and expertise in many of the areas needed to makesubstantial progress and continue to build on this momentum.

We aim to produce globallycompetitive energy on a cost basis – while also leading the world in ESGperformance – including carbon emissions.  Our current intensity-based carbonreduction target puts us on a path to achieving this objective.  However, wecan be more ambitious and set new objectives that provide opportunities tofurther reduce carbon emissions across our entire integrated value chain.

As a result, we have set a newstrategic objective to become a net zero carbon emissions company by 2050 onemissions produced in running our facilities, including those which we have aworking interest in, and substantially contribute to Canada’s net zero goals.  Wewill achieve this by:

• Reducing our emissions in our base business;
• Investing in profitable low emissions businesses;
• Taking action that reduce others’ emissions; and
• Investing in offsets outside of our business.

As part of our net zero strategicobjective – by 2030, we plan to reduce and offset annual emissions by 10 MT peryear, representing approximately 35% of our 2019 working interest emissions.  Althoughwe’re making substantial progress on our intensity goal, an absolute goalbetter aligns with our objective to reach net zero emissions and is a clearerway to demonstrate progress.  We will continue to track and report ouremissions on both an absolute and intensity base - to remain transparent.

We anticipate achievingapproximately half of this 10 MT target by reducing emissions from ourfacilities through energy efficiency, carbon capture and use and storage, orCCUS, and fuel switching.  The other half come from reducing emissions outsideof our operations, but we will only count these reductions where we’ve directlyintervened, caused change or invested to make these reductions happen. 

So, let’s put this into context. In 2019 our operational GHG emissions were approximately 29 MT on a workinginterest basis.  Just five processes account for 98% of these emissions – with approximately60% being associated with heat and steam production, 15% with hydrogenproduction, 10% with power production, 7% with on-site transport, and finally 6%with energy imports.  We expect CCUS to be the solution for over 50% of ourdecarbonization plan; fuel switching can address all of our power generation,on-site transportation and a substantial portion of our heat and steamemissions; and energy efficiency projects can be implemented across ouroperations.  In other words, we know where our emissions are and where they comefrom and almost 100% can be managed with technologies that are wellunderstood.  That’s not the challenge!  The challenge is to reduce theseemissions economically while keeping our industry and Suncor globallycompetitive – often with other jurisdictions that are ranked low on ESGperformance!

Carbon capture, use and storage isa critical technology for the globe to meet its climate goals of net zero by2050.  Thankfully, Alberta is one of the best jurisdictions in the world toimplement this technology due to the province’s geological characteristics.  Weexpect that this technology will be a significant part of our approach toachieve our strategic objective of net zero by 2050.  I believe that this willalso be true for many of the oil sands companies and we fully expect acollaborative approach across the industry to accelerate learnings and drivedown the overall costs.

Governments, both federal andprovincial, must play a vital role in providing regulatory certainty andappropriate fiscal framework to support the industry to reduce emissions whileremaining competitive.  And, we’re encouraged by the increased support andattention that this has been given by all levels of government.  Given thecurrent cost estimates of CCUS – we are expecting that the economics of theseinvestments may be compressed compared to other low carbon investments – but we’retargeting returns of at least our weighted average cost of capital withgovernment support.

There are some opportunities toleverage CCUS technology and drive higher returns.  One of our first isswitching our hydrogen production, which represents 15% of our emissions, toclean hydrogen made from natural gas. Our current hydrogen production processcreates a relatively concentrated CO2 stream – making carbon capture more costeffective than many other sources of CO2. But with new technology – we cancreate a very concentrated CO2 stream – allowing higher percentage of CO2 to besequestered at a lower cost.  And, we’ve recently announced a partnership withATCO on a potential project which I will discuss a little bit later.

Our state-of-the-art cogen projectat Base Plant, which will replace our aging coke-fired boilers to produce heatand steam, is an excellent example of a fuel switching application that willdrive down our base business emissions by approx. 1 MT/yr – and this is just inone project.  And the rest of these emissions reduction from this project, over4 megatons/yr, comes from the much lower carbon power being exported to thegrid to allow Alberta to transition off coal based power.

As I mentioned, approximately half of our 10 MT reduction inemissions target would come from reducing emissions outside of our facilitiesthrough growth in expanded energy offerings along our existing value chain,like the cogen investment.  We plan to grow our customer connection through lowcarbon emission energy products and services and we will continue to developchoices for customers – such as the Electric Highway and renewable liquid fuels– to help lower their carbon footprint.  We plan to use our influence withsuppliers to encourage emission reductions within our supply chain, whileremaining cost competitive.  We will continue to work with governments toensure policy and regulatory clarity and effective fiscal frameworks are inplace to support climate and economic goals.

And we will not sell assets toachieve emission reduction targets – and if we do buy or sell assets, we will continueto adjust our historical emissions to show them on a comparable basis.  Emissionsare global, and the world will only get to net zero by focusing on emissionreductions – not by changing who’s reporting them.

In order for us to achieve our strategic objective to reach net zero emissions fromour operations by 2050, we will continue to invest in technologies thatlower our business costs while improving our emissions profile.  The key focusareas to accomplish this are low carbon power, renewable fuels, and clean hydrogen.

We are located in one of the mostsocially conscious, environmentally stringent, and politically stablejurisdictions in the world.  Our long life, low decline oil resource will bestrategically important for many decades to come.  And we intend to be part ofthe transition to lower carbon emissions and contribute to Canada’s net zerogoals and we see the opportunity to help supply global energy as needs continueto grow. However, we recognize the need to continue to lower our carbonfootprint, as we have done on an intensity basis for several decades, and whichwe are now focused on doing in reducing absolute emissions.

Suncor has been evolving andexpanding along the energy value chain for nearly 50 years as we sawopportunities to increase shareholder value.  We began as a bucketwheel oilsands mining business in 1967, and over the subsequent decades expanded intoin-situ technologies, low carbon power and renewable liquid fuels – adding‘Energy’ to our name almost two and a half decades ago in 1997.  We continuedto expand along the energy value chain with the merger of Petro-Canada in 2009,and becoming a physically integrated company with direct connection to theconsumer.

Throughout this evolution, theoilsands has been at the core of our business.  And we will continue to produceoilsands for many decades to come – and in doing so increasingly in a sustainableway.  The Energy Transition for Suncor will be a continuation of our EnergyExpansion of low carbon energy products.  We will stick to our corecompetencies and make additional investments that are synergistic across thecompany, as we’ve done for decades.

Our Energy Expansion strategy willsupport our strategic objective of reaching net zero on our operationalemissions by 2050.  We will focus on investments that leverage one or more ofthe following attributes to drive incremental value.

Opportunities where we haveexisting expertise that we can leverage into competitive advantages; 

Expanded energy offerings that aresynergistic with our Base Business by lowering the cost and carbon profile ofour assets and the products used in our operations, or;

Opportunities that can be integrated,to maximize the margin capture along the value chain, from production to the customer.

We believe Suncor is well positionedin the energy industry to benefit from additional energy offerings due to ourdecades of operating similar assets, our extensive midstream expertise and ourconnection to the energy consumer.  As we continue to expand our integratedenergy offering, we will do so in business lines we already have a deepunderstanding of – Low Carbon Power, Renewable Liquid Fuels, and clean Hydrogen.

These opportunities have thepotential to generate mid-teens returns, improve the cost performance andmargin capture of the base business and strengthen our environmentalperformance.  We acknowledge that this may be challenging for standalone CCUSinvestments, and will work with our other industry peers and Governments to drivedown these emissions – while driving down the cost and capital deployed.

Over the medium term, we expect toallocate approximately 10% of our annual capital budget, or around $500 millionper year, on investments that advance our low carbon energy offerings.  And inareas where the technology is advanced, we see significant synergies and cangenerate strong returns, such as the Base Plant Cogen and the Forty Mile windprojects, we are making significant investments.  Over the next three years, asmentioned earlier, the majority of Energy Expansion capital will be allocatedto these two projects.

You willnot see us invest heavily in initiatives which have not reached technologicalmaturity and economic viability.  This discipline is illustrated by ourEnerkem, LanzaTech, LanzaJet, and Svante investments.  These four investmentsare a cumulative investment of roughly $150 million over the past seven years.  Whilerelatively small in capital, these are key partnerships and technologies tofacilitate future competitiveness, drive down emissions and give us a commercialedge – particularly in renewable liquid fuels.

These are the types of targeted,modest investments we will make until we have proven commercial andeconomically viable technologies – and by saying this – I’m referring totargeting mid-teens returns on investment.  This is what investors shouldcontinue to expect from Suncor. 

Suncor has been generating lowcarbon power for over 20 years. Our initial intent in developing natural gascogeneration facilities was to generate steam and power for our oil sands assets.Although some of these assets were originally owned by third parties, we now ownand operate most of the cogens that support our business - providing morecontrol and visibility of a significant cost driver of our business.  Thedevelopment of the portfolio has evolved from a cost and reliability benefit,to generating incremental revenue from selling surplus low carbon power to thegrid.  Through this approach, we are now the 5^th largest powerproducer in Alberta, exporting roughly 40% of the 1,400 megawatts of power wegenerate, to the grid. 

And today we have wind projects inOntario and Alberta. Going forward, we expect to focus our low carbon powerinvestment in deregulated markets where we have the ability to capture fullvalue of carbon offsets that are generated.  This is a very unique way toinvest in this market – unlike many of the projects that are underwritten bygovernment purchase agreements and as such, capture lower returns in projectsthat only generate power revenue.  Our approach to investing in this business narrowsour current focus to the Alberta market.  As the proposed federal carbon levyprices become more stringent, it will strengthen the value of these credits –supporting the returns of the projects which generate them.

Following the commission of theBase Plant Cogen and Forty Mile Wind, we estimate that we’ll be the 3^rdlargest power producer in Alberta.  As we’ve increased our power production, we’vealso expanded our marketing and trading capabilities by investing in people,processes and systems.  This capability increases the value of every megawatt thatwe produce, boosting project returns, and in some cases, we even sell to the endconsumer through the electric highway.

As ethanolblending requirements were mandated in the early 2000s, we began producingethanol in 2006 to meet these obligations with completion of the St. Clairethanol facility in Ontario.  Today, St. Clair is the largest ethanol facilityin Canada, producing nearly 7,000 barrels-per day and meeting roughly one-thirdof PetroCanada’s current fuel blending requirements.

Going forward, the objective offuture investment in our renewable liquid fuels business is to both minimizethe cost of regulatory compliance of our base business and leverage nextgeneration technologies to expand margin capture from the growing global lowcarbon liquid fuel demand.

As European, American and Canadianregulators mandate increasingly stringent low carbon fuel blendingrequirements, the entire global market is going to be short low carbon fuels.  Andin Canada, we’re expecting the market to be significantly short to meetcompliance.  This will either require large volumes to be imported from abroad,which may or may not exist, or investment in domestic production capacity. 

Independent forecasts showrenewable liquid fuel demand in Canada increasing rapidly from approximately70,000 barrels a day in 2019 to roughly 140,000 a day by 2030.  To give contextto the current macro supply shortfall, in 2019, Canada imported roughly 35,000barrels per day of renewable liquid fuels, or half of its demand due to a lackof domestic supply.

There is a significant marketopportunity to supply this demand growth and generate significant shareholdervalue.  And we are well positioned to leverage our experience with low carbonliquid fuels, logistics capabilities and our existing asset base to capitalizeon this opportunity.

However, there’s currently atiming dislocation between the future blending requirements mandated by thegovernments and the evolution of biofuel technology.  During this transitionaltimeframe, it does not make sense to expand capacity with first generationbio-fuel production – and given the strategic advantages and the industryleading profitability of our refineries, we do not have any near-term plans toconvert any of this capacity to fill the market need. 

Instead, we’ve made modest butstrategic, investments in promising second generation bio-fuel technologieswhich create ethanol and methanol from waste streams including municipal waste,biomass, or industrial flue gases.

We are de-risking thesetechnologies today in order to capture the value of changing regulations in thefuture.  We have a number of small equity investments with leading biofuelscompanies and are currently progressing two projects.

The first is the Carbon Recyclingplant located in Varennes, Quebec where we are partnering to build a biofuels facilitywith Enerkem, Shell, Investment Quebec, and Proman.  The facility is designedto take 200,000 tonnes per year of non-recyclable municipal waste and forestryresidue and convert it to 2,100 barrels per day of bio-methanol – with theoption to eventually expand capacities to bio-gasoline.  The project isexpected to be on stream in 2023 and generate mid-teens returns. 

The second project with LanzaJet, who we share equityownership of, along with Mitsui, British Airways, Shell and LanzaTech.  Theproject is located in Georgia where a commercial pilot plant is being built toconvert ethanol derived from waste streams into either sustainable aviationfuel or biodiesel.   This roughly 650 barrels per day project is scheduledto come online in late 2022 and generate mid-teens returns.  It’s worthwhilehighlighting that Suncor has offtake rights for roughly half of the sustainableaviation fuel and renewable diesel from the Georgia facility and we also have certainexclusive rights to the technology.

From a design perspective, both projects are beingconstructed using a design that can be replicated, enabling quick expansion tocapture the sizable growth opportunities projected for renewable liquid fuelsshould economics be attractive.

Given Suncor’s strategicinvestments in these companies, it also provides additional opportunities forus to consider deployment in jurisdictions where regulations are increasing thedemand for low carbon liquid fuels.  Investing in platforms for future lowcarbon energy products are what investors should continue to expect fromSuncor.  These investments are critical in developing cost-effective ways tomeet future blending requirements while also keeping Suncor at the forefront ofthese opportunities.

Clean hydrogen is quickly gainingtraction around the world as a strong candidate for becoming a meaningful partof the future energy mix.  While we agree with its potential, the road to broadadoption of hydrogen is long and will require industry collaboration andsignificant government support.  Today, Suncor is both the largest producer andconsumer of hydrogen in Canada, accounting for approximately 15% of thenational supply and 20% of Canada’s demand – all of which is grey hydrogen.  Wehave over 50 years of expertise in hydrogen as it is a critical component of bothour upgrading and refining processes. 

Given our significant use ofhydrogen and our existing customer base, we’re strategically positioned to oneday supply an alternative low carbon industrial fuel, or feedstock, to thosewho are committed to lowering their carbon intensity for their operations.  Inaddition, we’re also well positioned to participate should hydrogen bedeveloped as a fuel for mobility, particularly for heavy commercial use.  Butmore broadly, we believe with the right fiscal and regulatory support, Albertacould be positioned as a world leader in the field of clean hydrogen production,just as they are today in the area of grey hydrogen.

Alberta has an abundance of twokey elements to generate clean hydrogen: an abundance of natural gas; and thegeology that allows for the sequestration of significant quantities of CO2 overa long period of time.  However, while hydrogens acceptance within the broaderenergy mix is still at early stages, partnerships between industry andgovernments are going to be very important.  They will be needed to bothachieve hurdle rates to warrant investment, as well as facilitate the buildingof infrastructure required to support its use as a broader energy source.

A great example of this is therecent partnership we announced with ATCO Energy.  Together we’re studying theeconomic feasibility of a 300,000 tonnes per year of clean hydrogen plant nearour Edmonton refinery.  Being a major feedstock for Edmonton, 65% of thehydrogen output would be used at the refinery, – replacing grey hydrogen whichwe currently purchase from a third-party supplier.  20% of the output is expectedto be used by ATCO to blend into the natural gas distribution system – loweringthe carbon intensity of Alberta’s gas consumption.  The remaining 15% would besold to third parties.

Improving the carbon emissionsprofile of hydrogen production is necessary for us to achieve our strategicobjective of net zero emissions in our operations by 2050.  Consistent with ourlow carbon power and renewable liquid fuels strategies, we see ourselves asbeing our own best customer in the expansion of this clean energy product – whilealso positioning ourselves in future markets given our strong customer base.

If the project proves economic, itwill expand the margin capture of the Edmonton refinery along with energy valuechain by lowering costs.  The project would broaden our revenue base andimprove the environmental footprint of our operations, with the potential toreduce our Edmonton refinery emissions by up to 60%.  This is a very similarapproach we took with the Cogen project at base plant.  We also believe thatthis asset will be able to operate for many decades to come under almost anyscenario regarding energy transition.

I’m sure that many of you willhave questions around the details of the project.  The ultimate cost andeconomic viability of the project will require greater regulatory and policycertainty and clarity on the fiscal framework to determine if it generatesadequate returns.  We’re working collaboratively with our partner and theProvincial and Federal Governments to address these areas.  We do not expect asanctioning decision before 2024.  And as a result, the project is unlikely tosee material spending in the outlook we provided here today.

This opportunity is just anexample of how, as consumers’ needs evolve, Suncor plans to expand its energyproduct offering along its integrated value chain to meet them, as we have donefor decades.  But investors should continue to expect us to invest in expandedproduct offerings at a measured pace, deploying capital that will generate accretivereturns. 

While the energy industry may haveonce considered such investments purely as cost mitigants, to us they fulfill astrategic objective.  Our focus areas in Low Carbon Power, Renewable LiquidFuels and Clean Hydrogen will leverage our core competencies, improve margincapture, and improve the environmental performance of our operations and theproducts we sell.  All this while developing assets that we expect to generatereturns for shareholders for decades to come.  And we believe these investmentsare also consistent with our purpose that guides the Suncor team: to providetrusted energy that enhances peoples’ lives, while caring for each other andthe earth.

And with that, I’ll turn it backto Alister to discuss our financial outlook and plans to increase shareholderreturns.

Speaker: Alister Cowan

Thank you, Mark,

Throughout the morning, both Markand I walked you through our strategic corporate objectives, and theinvestments needed to achieve them.  We outlined details around the $2 billionof annual, incremental free funds flow goal, and how many of the investmentswere structurally reducing the cost base and sustainment capital requirementsof the company.  We highlighted how roughly $450 million of the benefits are expectedto be achieved in 2021 – and why we are confident in exceeding our $1 billionannual goal by 2023 and the $2 billion annual goal by 2025.

Mark discussed how we’re investingin the improvement of our environmental performance while economicallyexpanding our energy offerings across the existing value chain with projectsthat have mid-teens returns and enhance the free funds flow of our business.

So now I am going to outline howthese initiatives come together in our financial plan to improve the resilienceof Suncor and increase shareholder value and cash returns.

Before I start, let me say thisdiscussion is based on the financial scenario we have outlined here today whichis on a defined set of commodity price assumptions and, of course as usual,dividends and buybacks are always subject to Board approval. 

Our key commodity priceassumptions for this scenario are a flat nominal commodity price of $55 US/bblfor WTI, a $17 US/bbl New York Harbor crack spread, and a 76 cent FX rate forthe US dollar.

As I highlighted during the $2billion incremental free funds flow section, a significant proportion of theinitiatives target our OS&G expenses. When we include our working interest in the Syncrude cost synergies Mark spoke aboutearlier, we have a defined path to lowering our absolute OS&G to $9.5billion in 2025 or, a reduction of $1.7 billion from 2019 levels, whilemodestly growing our upstream production to 800,000 barrels per day.

When we reflect these absolutesavings into the operating segments of the business, we see significant andsustainable improvements in the cost structure of our operations. 

As the $2 billion of initiativesand the Syncrude synergies continue to materialize, we expect to see the perbarrel cash operating cost targets at all three of these operations achieved. At Syncrude we anticipate achieving the $30 Canadian per barrel target inlate-2023 and at Fort Hills and our broader Oil Sands Operations, we expect toachieve our $20 per barrel targets in 2024 and 2025 respectively.

The other structural improvementgenerated by the $2 billion initiative is a lowering of our asset sustainmentand maintenance capital.  Through these initiatives we expect our annualsustainment capital to be reduced to a range of $2.75 to $3.50 billion throughthis period and further reduced to a range of $2.75 - $3.25 billion by 2025.  Theinvestments we’ve been making will generate structural reductions to ourcapital requirements, resulting in a lower operating breakeven and greater freefunds flow. 

Based on the scenario shown heretoday, this means that our sustainment and maintenance capital requires only roughly30% of our funds from operations to be reinvested going forward.  This coversboth our upstream and downstream assets.

I want to remind you that thesesustainment and maintenance figures exclude our in-situ well pad investments.  Thiscapital which averages $200 -$250 million a year, is included in our economiccapital expectations outlined here today.  We view maintaining or expandingproduction as an economic decision which needs to be justified in terms of freefunds flow, payback and return on capital.

The combination of theimprovements from the $2 billion initiative, and the capacity it affords us toreturn increased cash to shareholders, is best summarized through a depictionof our operating and corporate breakeven price, under various assumptions. 

We believe that a $35 US/bbl forWTI, a $17 US/bbl New York Harbor crack spread and a 76 cent FX rate is anappropriate corporate breakeven for the company.  For clarity, our corporatebreakeven is our operating breakeven plus the dividends.  Our $35 US WTI corporatebreakeven target positions us well within our industry.  Assuming thesestructural improvements to our business materialize as we expect, we areanticipating them to lower our operating breakeven to roughly $22 US per barrelby 2025.

Our goal with this breakevenimprovement is to unlock free funds flow which can be sustainably returned toshareholders in the form of increased dividends, without impacting thefinancial resiliency of the company. 

As a result – of the $2 billion ofincremental free funds flow, we intend to allocate $1.5 billion of thisimprovement to our current dividend by 2025, as the initiatives are realized. We expect to allocate the first billion fully and 50%, or $500 million, of thesecond billion to the dividend.  Including the impact of share buybacks, thiswould increase the dividend to around $2.00/share by the end of 2025 – from thecurrent $0.84/share, an increase of roughly 140% over the next four years. 

This results in resilient, sustainable,per-share dividend growth that equates to a compounded annual growth rate of approximately25%, through 2025.  All while maintaining an overall corporate breakeven of $35US per barrel WTI.

We define discretionary free fundsflow as, funds from operations, less sustainment and maintenance capital anddividends.

Based on the commodity pricescenario shown today, we estimate that we will generate discretionary freefunds flow of over $5 billion a year on average through 2025 – after providinginvestors with a compounded-annual-growth-rate of approximately 25% in theirdividend over the same timeframe.  Said another way, at $55 US/bbl WTI, weexpect to generate over $26 billion, after sustainment capital and dividends,that will be available for debt repayment, share buybacks and investing in the freefunds flow growth of the company over the next five years.  If you have ahigher commodity price view, of course that number will be higher.

But obviously, forecastingcommodity prices is challenging.  What we do know, is that the volatility ofthe commodity markets is increasing in both frequency and intensity.  Ourlearnings, when reflecting over the past five-years, is that going forward weneed to maintain a stronger balance sheet and financial position than we havehistorically.  Combined with the lower corporate breakeven I just outlined, this will ensure that we are able to sustain shareholder returns and progresskey strategic initiatives in the low points of future cycles, without stressingour balance sheet.

In addition to re-setting our $35 USWTI corporate breakeven, which we achieved in 2020, we are also lowering ourdebt targets to strengthen the balance sheet.  We are now targeting less than2x net debt to funds from operations in a $55 US WTI environment.  We are alsoadding an absolute 2025 net debt target range of $12-$15 billion.  Longer term,by 2030, we are targeting a net debt to funds from operations ratio of lessthan 1.5X and $9 to $12 billion of net debt.

And I would remind everyone that, hereat Suncor, we define our net debt comprehensively and include all of ourcapital leases which currently sit at approximately $3 billion.

To accelerate reaching these debttargets, we plan to continue to allocate two-thirds of our free funds flow,after our dividend, towards debt reductions in 2021, and one-third towardshareholder cash returns through share buybacks.  In addition to this, in 2021we will also be receiving our 2020 cash tax refund of roughly $800 millionwhich we will also put towards reducing debt.  As a result, we anticipate, atcurrent strip prices, to return to 2019 net debt levels of roughly $16 billion bythe end of this year.  This equates to around $4.0 billion of debt reduction in2021.

Once we return to this net debtlevel, you will see an ongoing structural and disciplined approach to debtreduction built into our go-forward capital allocation plan.  We expect toreduce net debt by $1 billion per year, on average, through 2025 to achieve ournet debt and net debt to FFO targets and by $500 million per year beyond 2025.

Assuming a $55 US/bbl WTI pricingscenario, and the achievement of our $2 billion of increased free funds flow initiatives,we are able to strengthen our balance sheet with ratable debt reductions,afford the dividend increases I described, and still allocate to sharebuybacks.  Of the roughly $4 billion of remaining discretionary free funds flowper year that is expected to be unallocated after debt reductions, roughly $2billion per year is expected to be returned to shareholders in the form ofshare buybacks, which will accelerate the growth in investor’s per sharereturns and increase the portion of the company’s assets that each shareholderessential owns.  That said, we will be thoughtful, value buyers of our stock –treating the program the same as other uses of economic capital. 

The outlook on funds flowallocation in the next four years looks meaningfully different than it did from2016 to 2019.  We have transitioned from an era of upstream investment in largemega projects driving top line production growth, to one of optimizing andmaximizing funds from operations across the business.  From 2016 to 2019, wewere developing mega projects such as Fort Hills and Hebron and as a result, anaverage of 35% of our funds from operations was reinvested into the business aseconomic capital to grow production.

Since 2018 we have not beeninvesting in large, greenfield mega projects to grow production. Instead, inthe Base Business, our economic investment opportunities are focused onlowering the breakeven of the business and growing funds from operations.  As aresult, major greenfield mega project investment is not something shareholders shouldanticipate from Suncor during this period.  Where we are growingproduction volumes, we are focusing on low capital intensity debottlenecks atour existing operations and expanding our energy offerings along the energyvalue chain.

As projects continue to competefor a finite pool of economic capital, the split between Base Business andEnergy Expansion may shift.  However, we plan to maintain the overall totalquantum of capital, at $5 billion per year through 2025 – of whichapproximately $1.5 to $2 billion is anticipated to be economic in nature.

When we put this level of totalcapital spending in the context of a nominal $55 US/bbl WTI environment, onaverage, it implies a total capital reinvestment of less than 50% of funds fromoperations – markedly below the two-thirds reinvestment ratio we employedbetween 2016 to 2019.

We expect capital associated with theEnergy Expansion investment to account for roughly 10% of our total capitalspend, or approximately $500 million annually, for the next several years. Investment will be made at a measured pace given that over 50% of thiscumulative energy expansion capital through 2025, is already allocated to theBase Plant Cogen and Forty Mile wind projects.  As Mark mentioned earlier, wehave a clear vision of where Suncor is strategically advantaged to extractsignificant value within the energy expansion – however, in many casesregulatory certainty and transparency, as well as government fiscal support,are still needed before proceeding.

Finally, and this is an importantpoint, we will pace all economic capital on the basis of maintaining financialstrength.  Should commodity prices fall significantly for an extended period oftime, we will take action as we did in 2016 and 2020.  We will be flexible andagile to reduce costs and economic capital to ensure our financial strength ismaintained. 

We are improving the resilience ofthe company, fortifying our business model and at the same time significantlyincreasing shareholder returns by:

• Lowering our corporate breakeven through cost reductions andmargin improvements, which relentlessly challenges ourselves to run ourbusiness more efficiently;
• By returning an estimated 40% of funds from operations toshareholders which will come in the form of significant structural increases toour dividend and ratable share buybacks of approximately $2 billion annually;
• By strengthening our balance sheet by building systematic debtreductions into our capital allocation plans, to achieve a net debt range of$12-15 billion by 2025 and even lower by 2030; and
• Growing long-term value by generating reliable year-over-year improvements from capital efficient investments, with little reliance on production growth or oil price;
• And lastly, employing unwavering capital discipline, as we do notexpect our annual capital program to exceed $5 billion during the providedoutlook, regardless of the prevailing commodity environment.  And remember, wewill have the flexibility to reduce it if required.

Our philosophy and commitment toshareholder returns has not changed. During our growth phase, Suncor averaged$9 billion of funds from operations and allocated approximately 40% of it toshareholder returns in the form of dividends and buybacks.  The remainder ofwhich was invested in the business towards mega projects, which were alsopartially funded by increased debt. 

As we look forward, we expect toallocate a similar 40% of our funds from operations to shareholders, again inthe form of dividends and buybacks.  But there are fundamental and significantdifferences in the company you are invested in today from the one you owned in2015.  One of them being that our funds from operations in the next five-yearwindow are much greater than our growth phase.  As such, the actual cashallocated to shareholder returns is significantly higher.

However, there is more:

• Our plan outlined here today will see shareholders receive 25% more cashper share returned to them over the next five years, then they received in thefive years leading up to 2020, and significantly higher than current levels;
• Our value over volume strategy is growing our free funds flow throughabsolute cost reductions. Our breakeven of $35 US/bbl WTI makes us moreresilient now than ever before;
• Our focus on debt reduction will significantly lower leverage of thecompany, at a much lower commodity price deck; and
• Lastly, capital discipline will underpin and guide the execution of ourplan. We will keep total capital spend to $5 billion;

I would now like to turn it backto Mark for some closing remarks.

Speaker: Mark Little

Thanks, Alister.

And as we just highlighted, theplan we have been executing since 2018 to optimize our asset base, makes ourbusiness significantly stronger, and is delivering cash now, in 2021.

The execution of our strategypositions us for increasing shareholder value and returns.

We expect to deliver:

• 25% higher returns through a growing dividend and a $2 billion annual buyback,
• A low-cost business model with $US35 WTI breakeven,
• And a lower risk profile with approximately $8 billion of debt reduction and a focus on capital discipline.

These are the hallmarks of theoptimization strategy.

In the coming five years, underour $55 WTI scenario we expect to deliver more funds from operations than everbefore.

• We plan to allocate roughly 30% towards our high standards ofoperational excellence and 15% to economic investments,
• Approximately 55% of nearly $53 billion from funds from operations isexpected to be allocated back to shareholders, which is $29 billion by 2025.  That’sa phenomenal amount of returns, so let’s break it down into three categories:
  • With the dividend growth I just highlighted, shareholders can expect to receive $8 cumulative per share,
  • Our buyback adds another $7 per share of value,
  • And finally, the debt reduction results in $6 per share of incremental value while fortifying the company.

Combined, this returns an impressive $21 per share over the next five years.

That concludes our presentation,so thank you for taking the time to better understand our strategy and hear whywe think Suncor is a great investment.

We will now take a 5-minute breakand when we come back, Alister and I will answer your questions.