Athabasca Oil Corporation is pleased to report its 2021 third quarter results. Record financial results during the quarter, including $57 million of Free Cash Flow, demonstrate the quality of Athabasca’s asset base and unique positioning in the current oil price environment.
Q3 Highlights
• Production: ~34,250 boe/d including ~26,700 bbl/d in Thermal Oil and ~7,500 boe/d in Light Oil.
• Record Operating Income: $121 million ($36/boe) driven by strong oil prices and 90% Liquids weighting. Record Operating Netback of $36/bbl in Thermal Oil.
• Capital Expenditures: $16 million focused on high-value Leismer projects to sustain production.
• Record Funds Flow: Adjusted Funds Flow of $72 million ($0.14 per share) and Free Cash Flow of $57 million.
Recent Operational Highlights
• Leismer: Current production of ~19,000 bbl/d has been supported by the tie-in of the L6 infills and an additional well pair on Pad L7. Pad L8 commenced steaming in October, with first oil expected in early 2022. The five well pairs are anticipated to ramp-up to >5,000 bbl/d in mid-2022.
• Hangingstone: Expanded NCG co-injection has supported field pressure management with current production of ~9,000 bbl/d. Optimization projects have yielded a significantly lower cost structure driving a $33/bbl Operating Netback in Q3.
• Light Oil: Focused on free cash flow generation with continued strong Operating Netback of $37/boe.
• Carbon Capture (CCUS): Continuing to advance a scoping study with Entropy Inc. to determine feasibility of a carbon capture at Leismer with ongoing evaluation of local storage and carbon trunkline options.
2021 Guidance and Outlook (Strip Pricing October 4)1
• Production: increased annual guidance to ~34,250 boe/d (previously 32,000 – 34,000 boe/d).
• Capital: an unchanged ~$100 million annual capital program primarily directed towards Leismer.
• Financial: Adjusted EBITDA ~$255 million; ~$190 million Adjusted Funds Flow; ~$90 million Free Cash Flow.
• Balance Sheet: Resilient and refinanced balance sheet with no term debt maturities until Q4 2026 and strong liquidity of ~$265 million, including ~$195 million cash (2021e year-end).
• Compelling Leverage Metrics: Net Debt to Adjusted EBITDA of ~0.8x (2021e year-end). The Company anticipates being in a net cash position in 2023.
• 2022 Budget: Anticipated to be released in December. Activity will be focused on sustaining base production and maximizing free cash flow generation.
“Athabasca has taken deliberate steps to reposition the portfolio over the past number of years,” said Robert Broen, President and CEO. “The quarterly results and outlook validate the Company’s enviable position in the current environment. The recent balance sheet refinancing provides us significant strategic flexibility. We remain steadfast in our capital allocation priorities and have a clear path to net zero leverage in 2023. Reduced cash flow volatility, consistent operational execution and a best-in-class balance sheet is expected to unlock significant shareholder value through this period and beyond.”
Strategic Outlook
• Managing for Strong Free Cash Flow: Athabasca intends to maximize free cash flow while maintaining its production base. The Company forecasts >$600 million in Free Cash Flow (US$70 WTI & US$12.50 WCS differentials) during the 3-year timeframe of 2022 – 2024.
• Clear Debt Reduction Targets: The Company will direct at least 75% of future free cash flow towards achieving a total outstanding term debt reduction of US$175 million (50% reduction) while maintaining a strong liquidity position. The Company is targeting to achieve this target and to be in a net cash position in 2023. Debt reduction utilizing free cash flow, permitted under the new term note, will commence semi-annually with the first repayment in May 2022 (for the period Q4 2021 – Q1 2022).
• Maintain Annual Corporate Production: The portfolio of long reserve life assets under-pins a low corporate decline rate of ~10%. Athabasca requires low sustaining capital of ~$125 million annually to maintain production. The Company retains a large portfolio of future investment opportunities.
Business Environment
Commodity prices continue to strengthen as the world has emerged from the COVID-19 pandemic and the recovery in oil demand continues to outpace the growth in supply. Global oil demand is set to exceed pre-pandemic levels in 2022 and inventories are below the 5-year average. The OPEC+ supply agreement is expected to keep the market in a deficit and guidance for higher capacity will be needed in coming years given growing under-investment (Goldman Sachs Commodity Research).
In Alberta, physical markets and regional benchmark prices (e.g. Western Canadian Select “WCS” heavy oil) have improved with higher WTI prices. Athabasca expects current WCS differentials to remain stable with muted industry growth and improving basin egress, including the recently completed Enbridge Line 3 replacement. There is strong demand for heavy oil from US Gulf Coast refineries as they face structural declines in global heavy oil supply (Venezuela and Mexico). Athabasca believes conditions have emerged for WCS heavy oil to be among the most valuable global crude benchmarks.
Balance Sheet and Risk Management Update
On October 22, 2021, Athabasca announced the closing of US$350 million of 5-year Senior Secured Notes (“New Notes”) and a $110 million reserve based credit facility. The refinanced capital structure provides certainty to shareholders of the Company’s ability to utilize free cash flow to further reduce debt and enhance long-term resiliency.
The Company estimates 2021 year-end liquidity of ~$265 million (including ~$195 million of cash) with a 2021 Net Debt to Adjusted EBITDA of 0.8x (US$67.50 WTI & US$12.50 WCS differentials). The New Notes provide Athabasca the ability to further reduce debt in the near-term by utilizing at least 75% of free cash flow semi-annually to retire notes at 105% of face value. The Company is targeting to be in a net cash position in 2023.
Athabasca has commenced its 2022 hedging programing which includes 13,500 bbl/d of fixed WCS swaps at an average price of ~US$54 (implied WTI of ~US$66.50 assuming a US$12.50 WCS differential). These swaps fully protect the sustaining capital program down to ~US$50 WTI. Additional hedges are anticipated to include collars and puts to strategically balance downside protection while maintaining upside exposure to the current price environment.
Financial and Operational Highlights
Operations Update
Thermal Oil
Bitumen production for Q3 2021 averaged 26,729 bbl/d. The Thermal Oil division generated Operating Income of $94.8 million and capital expenditures were $15.2 million. Operating Netbacks for Leismer and Hangingstone were a record $37.09/bbl and $32.92/bbl, respectively.
Leismer
Bitumen production for Q3 2021 averaged 18,023 bbl/d. Production has increased over Q2 volumes following the tie-in of two L6 infills and L7P6 in late June and Leismer is currently producing ~19,000 bbl/d.
The Company has significantly advanced the completion of Pad 8. Facility construction was completed in October and steam circulation has commenced ahead of schedule. First production is anticipated in early 2022. The initial five well pairs on Pad L8 are expected to ramp-up in excess of 5,000 bbl/d in mid-2022. The existing pipeline will support future development for a total of 14 well pairs on Pad L8. Preparations are underway for drilling operations to commence on the next sustaining pad in 2022.
Hangingstone
Bitumen production for Q3 2021 averaged 8,706 bbl/d. Reservoir performance through 2021 has been strong as a result of excellent facility run time and the implementation of NCG co-injection aiding in pressure build-up and reduced energy usage. Production is expected to be supported by an additional well pair (AA03) that is currently steaming and will be placed on production in November.
Light Oil
Q3 production averaged 7,526 boe/d (55% liquids) in Q3 2021. The division generated Operating Income of $25.8 million ($37.25/boe) and capital expenditures were $0.1 million. Athabasca’s Light Oil netback continues to be top tier when compared to Alberta’s other liquids-rich Montney and Duvernay resource producers and are supported by a high liquids weighting and low operating expenses.
At Greater Placid, production averaged 4,205 boe/d (44% liquids) with an Operating Netback of $30.02/boe. The asset is positioned for flexible future development with an inventory of ~150 gross drilling locations and no near-term land retention requirements.
At Greater Kaybob, production averaged 3,321 boe/d (69% liquids) with an Operating Netback of $46.38/boe. Production results have been consistently strong with wells screening as top liquids producers in the basin. Athabasca’s latest 12 wells at Kaybob East and Two Creeks have average IP180s of ~725 boe/d (85% liquids) and IP365s of ~550 boe/d (83% liquids). Strong well results coupled with a large well inventory (~700 gross drilling locations) and flexible development timing indicate significant value to Athabasca. The Kaybob area is supported by a strong Joint Development Agreement, established infrastructure and no near-term land retention requirements. The Company remains encouraged by competitor activity and recent new entrants into the play.
