Canada's Upstream Hydrocarbon Industry (Part 2)

In Part 1 (Link), we kicked off our analysis of Canada’s upstream industry by covering national-level production, commodity pricing dynamics and market access, and also began our financial assessment of industry revenues and operating expenses. In Part 2, we delve deeper into the financial trends through discussions on the cost of debt, operational cash flow and Capex, while also evaluating Canadian D&C activity before finishing with our financial summary of Canada’s upstream sector.

Should you wish to review the analysis in a single document, feel free to download the pdf below.

OPERATIONAL CASH FLOW AND CAPEX

The historical relationship between cash flow and Capex in Canada’s oil patch is really a tale of two operating environments. Prior to 2017, Canada’s annual capital spend was driven by a flurry of Greenfield Oil Sands mining and in situ projects, along with the widespread adoption and growth of multi-stage hydraulic fracturing. In turn, capital budgeting routinely met or exceeded 100% of Operating Cash Flow, with excess Capex funded care of cheap debt following the 2008 financial recession and the subsequent decline in prime lending rates. However, by late 2014 OPEC (led by Saudi Arabia), decided to maintain the cartel’s production levels despite falling prices to protect market share and pressure high-cost producers, particularly unconventional resources such as US shale and Canada’s Oil Sands. This strategy triggered a dramatic collapse in oil prices, dropping from over $100 per barrel in mid-2014 to below $30 per barrel by early 2016, which in turn strained Canadian and US producers as well as other oil-dependent economies.

While the Saudi oil price war effectively ended in late 2016 when OPEC adopted production cuts to stabilize the market, the consequence was a far greater emphasis on risk management through capital discipline, combined with leveraging the technological advancements of multi-stage hydraulic fracturing. From 2017 to today, capital budgets have been markedly below the 1.0x reinvestment ratio, largely due to D&C efficiencies, coupled with an incompatible risk profile that a Greenfield Oil Sands mine has today. Put another way, think of it like a Hollywood blockbuster movie (Oil Sands) versus a popular streaming series (D&C programs): the blockbuster movie aims for singular, outsized success but is burdened by the significant time, resources, and potential risk of cost overruns; whereas multiple streaming series can be more rapidly produced with smaller budgets per episode and can adapt to audience trends with iterative seasons. That “streaming series” approach appears to be the benchmark for upstream capital budgeting, and while Oil Sands capital spend will continue to carry an outsized weighting, recognize that Canadian E&Ps are reluctant to leverage their balance sheets for the sake of new Greenfield mining development.  

CAPITAL ALLOCATIONS

If the reinvestment ratio trends below 1x, how is free cash flow allocated? The answer lies in debt repayment, dividends, and share buybacks. A decade ago, debt and equity offerings were commonplace, as growth was fueled by capital spending budgets that often exceeded 100% of operating cash flow, with additional funding required during expansion phases and market downturns. Over the past ten years, however, institutional investors and pension funds have increasingly divested from upstream producers to align with decarbonization goals and meet Environmental, Social, and Governance (ESG) targets. This shift has fundamentally reshaped capital allocation strategies among E&P companies, moving the focus from production growth to capital efficiency and maximizing shareholder value. Today, cash flow from financing activities—once heavily reliant on external funding—has become secondary to accelerated debt repayment plans, dividend increases and share buybacks to improve per-share metrics and signal confidence in long-term fundamentals. By my estimation, aggregated base and variable dividends, debt repayment and share buybacks have accounted for 80% to 90% of free cash flow over the past three years. Capital allocation strategies will likely continue to emphasize disciplined cash management and prioritizing sustainable returns, with a laser focus on optimizing shareholder value.

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OPERATIONAL ACTIVITY

For all this financial talk, the industry still lives and breathes in the field. Canada’s upstream sector can be categorized between producers that operate in the Oil Sands and those that drill for conventional oil, gas and NGLs.

CONVENTIONAL OIL & GAS

Rig activity reached a 10-year peak through the second half of 2024, largely due to oil-specific rig activity, and offset by steady natural gas-related rig activity, though below the 10-year average. Steep changes in weekly rig adds/reductions have been the traditional norm, with rig activity typically cresting through the first hundred days of each year before steep declines in April and May for Spring Breakup. The more recent trend over the past two years has been more balanced as commodity oil prices have remained within the $70-$90/barrel price band. Commodity price volatility plays a key role in future rig count with aggregated rig adds typically corresponding to commodity price increases from 3 to 6-months prior, while rig reductions are normally more prompt in responding to recent commodity price decreases.

An additional trend of note is the accelerated pace to drill and complete a well. Canada’s oil patch has seen a shift towards more complex well architectures, including extended-reach and multi-lateral wells that have been facilitated by innovations in horizontal drilling and real-time data analytics. As well, the adoption of advanced completion techniques, including Simulfracs and Trimulfracs, have streamlined operations, reduced non-productive drilling time and enhanced well performance. The net effect is a well that took upwards of 30+ days to drill and complete in 2015 has been cut nearly in half due to the advancements in D&C techniques.

These D&C developments underscore the broader industry trend that technologies have significantly enhanced operational efficiency while also driving cost improvements in the oil and gas sector. By analyzing the D&C Cost per meter drilled (converted to feet), it becomes apparent that operational advancements in the field have translated into material cost savings. While cost inflation post-COVID has seen D&C Cost per Foot spike, the 10-year trend equates to technological advancements contributing to a reduction in overall well costs.

OIL SANDS

As mentioned under the Oil Sands Production section, Oil Sands-related capital spend over the past five years has predominantly been allocated towards debottlenecking and optimization projects to incrementally increase bitumen production. As noted in the table above, upcoming Oil Sands/in situ-related projects reinforce this emphasis on enhancements and optimization, as well as in situ project expansions.

Beyond the capital spend, consolidation has been a major theme of Oil Sands activity over the past decade with non-Canadian producers divesting their interests amid the wave of ESG-related pressures. A summarized list of Oil Sands acquisitions and divestments includes:

• April 2016: SU acquired Murphy Oil’s (MUR) 5% interest in the Syncrude Oil Sands project for $937MM CAD.

• March 2017: CNQ acquiring Shell Canada’s and Marathon Oil’s working interest (70%) in the Athabasca Oil Sands Project. The acquisition totaled $12.7B CAD and included interests in the Muskeg River and Jackpine mines, the Scotford Upgrader, and the Quest Carbon Capture and Storage facility.

• March 2017: Cenovus Energy (CVE) acquired ConocoPhillips’ (COP) 50% working interest in the Foster Creek and Christina Lake in situ projects, as well as most of COP’s conventional assets in Alberta and British Columbia. The acquisition totaled $17.7B CAD.

• June 2019: CNQ acquired Devon Energy’s (DVN) Oil Sands, and other heavy oil and natural gas assets for $3.8B CAD.

• January 2021: CVE completed the all-stock acquisition of Husky Energy valued at $23.6B CAD. Husky’s assets were an assortment of downstream and upstream assets, including international and Eastern Canadian offshore projects, multiple thermal/heavy oil projects in Saskatchewan, and the Sunrise Oil Sands project.

• June 2022: CVE acquired the remaining 50% interest in the Sunrise Oil Sands project from BP Canada, assuming full operating ownership of the project for $600MM CAD.

• October/November 2023: SU closed its acquisition of TotalEnergies’ 31% interest in the Fort Hills Oil Sands project and the 50% interest in the Surmont in situ project. At the same time, TotalEnergies’ divestment triggered a right of first refusal clause, which in turn, allowed COP to acquire the remaining interest in the Surmont project for $4.1B CAD.

• October 2024: CNQ purchased Chevron Canada’s (CVX) 20% non-operating interest in AOSP as well as 70% operating interest in the Duvernay shale for $8.7B CAD.

CANADA’S UPSTREAM PRICING, PRODUCTION & OPERATING METRICS

FINANCIAL ASSESSMENT OF CANADA’S UPSTREAM HYDROCARBON SECTOR

Since 2015, the financial well-being of Canada’s upstream hydrocarbon sector tells a story of pragmatic decision making amid an evolving sector faced with volatile commodity markets. Revenue struggled during the downturn years with the Saudi oil price war and COVID, with significant pressure reflected in negative EBITDAX margins, which bottomed at -34% in FY15. By 2017, operational efficiency and cost-cutting efforts reversed the trend, delivering a positive EBITDAX margin of 22%, and set the stage for profitability that peaked in 2022. The cash flow statement highlights the impact of disciplined capital management. Free cash flow, initially negative at -$13.37 per BOE in FY15, transitioned to a positive metric for FY17 to FY24. The rebound was driven by improved commodity prices and reductions in capital expenditures, which fell from 53% of revenue in FY15 to 36% by FY17. Cash flow from operations strengthened consistently, reflecting tighter cost control and higher operating cash generation. On the balance sheet, financial discipline is evident in the steady reduction of long-term debt, declining from $150B in FY15 to $114B in FY16. Leverage ratios improved gradually, with Debt-to-EBITDAX reducing from a peak of 6.2x in 2016 to healthier levels as seen over the past two years. The reinvestment rate, a critical measure of capital efficiency, dropped from an unsustainable 202% in FY15 to below 100% by 2017, indicating prudent capital allocation. This disciplined financial approach not only supported deleveraging but also positioned the industry for long-term sustainability. The free cash flow breakeven oil price, calculated by holding historical natural gas and NGL prices constant while adjusting the annual oil price to achieve zero free cash flow, has consistently remained within the $40-$50 per barrel range. Exceptions to this range occurred in 2015 and more recently in 2022/23, when inflationary pressures significantly escalated costs, impacting not only the upstream oil and gas sector but the broader Canadian economy. These periods of elevated costs underscore the sensitivity of breakeven pricing and the price floor necessary to generate sustainable free cash flow under various market conditions. In closing, the financial evolution over this period underscores a clear recovery trajectory. Tight cost controls, capital discipline, and operational efficiency transformed financial metrics, enabling Canada’s upstream sector to weather commodity price volatility and emerge with stronger profitability and balance sheet health.

CONTACT INFORMATION

This publication is available on Crude Calculation’s website, which can be found at: crudecalculations.beehiiv.com. For questions regarding the data and analysis found in this report feel free to contact the author, Patrick Enwright, via email at [email protected] or by phone at (403) 991-8587.

Patrick Enwright Author, Analyst – Crude Calculations

COMPANIES MENTIONED

• ATH: Athabasca Oil Corporation

• CNQ: Canadian Natural Resources Limited

• CVE: Cenovus Energy Inc.

• CVX: Chevron Corporation

• COP: ConocoPhillips Company

• DVN: Devon Energy Corp

• IMO: Imperial Oil Limited

• IPC: International Petroleum Corporation

• MEG: MEG Energy Corp.

• MUR: Murphy Oil Corporation

• NGTL: NOVA Gas Transmission Ltd.

• SCR: Strathcona Resources Ltd.

• SU: Suncor Energy

ACRONYMS

AECO: Alberta Energy Company. Refers to the benchmark spot price for Alberta natural gas on the Nova Gas Transmission Ltd. (NGTL) system. The term is used in reference to the spot price or assessed price for natural gas.

AER: Alberta Energy Regulator

BC: British Columbia

BOC: Bank of Canada

BOE/D: Barrels of oil equivalent per day

CAD: Canadian Dollar

CAGR: Compound Annual Growth Rate

D&C: Drilling and Completion

E&P: Exploration and Production

EBITDAX: Earnings Before Interest, Taxes, Depreciation, Amortization, and Exploration Expense

ESG: Environmental, Social, and Governance

FY: Fiscal Year

GJ: Gigajoule

LNG: Liquified Natural Gas

MMboepd: Million Barrels of Oil Equivalent Per Day

MMcfpd: Million Cubic Feet Per Day

NGL: Natural Gas Liquids

OPEC: Organization of the Petroleum Exporting Countries

SAGD: Steam-Assisted Gravity Drainage. Refers to a recovery technique for extraction of heavy oil or bitumen that involves drilling a pair of horizontal wells one above the other; one well is used for steam injection and the other for production.

SCO: Synthetic Crude Oil. Refers to the grade of oil that is similar to crude oil but is derived by upgrading bitumen from Oil Sands. The term is used in reference to the spot price of upgraded bitumen.

TMX: Trans Mountain Expansion

YoY: Year-over-Year

WCS: Western Canadian Select. Refers to the benchmark price for western Canadian crude blends. The price of other Canadian crude blends produced locally are also based on the price of the benchmark.

WTI: West Texas Intermediate. Refers to the grade of oil that serves as a benchmark oil price in the United States. The term is used in reference to the spot price or assessed price.

DISCLAIMER

_{All information contained in this publication has been researched and compiled from sources believed to be accurate and reliable at the time of publishing. However, in view of the natural scope for human and/or mechanical error, either at source or during production, Patrick Enwright accepts no liability whatsoever for any loss or damage resulting from errors, inaccuracies or omissions affecting any part of the publication. All information is provided without warranty, and Patrick Enwright makes no representation of warranty of any kind as to the accuracy or completeness of any information hereto contained.}