CALGARY, Alberta – Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to report its 2021 first quarter results that demonstrate the resilience and quality of its asset base. The Company is also pleased to provide an update on initiatives to further improve its positioning in a post COVID recovery. Athabasca plans to refinance its debt in the coming months that will allow shareholders to capture the unparalleled cashflow generation potential from its long reserve life, oil weighted asset base.
- Production: ~34,400 boe/d including ~25,950 bbl/d in Thermal Oil and ~8,450 boe/d in Light Oil.
- Operating Income: $66 million driven by stronger oil prices and high liquids weighting (89%).
- Adjusted Funds Flow: $19 million ($0.04 per share).
- Capital Expenditures: $36 million focused on high-value Leismer projects to sustain production.
- Netbacks: Industry leading $31.24/boe in Light Oil, and $17.85/bbl in Thermal Oil.
Recent Operational Highlights
- Leismer: Drilled one sustaining well pair and two infill wells with first oil expected in July; drilled five producer wells at Pad L8 with steaming to commence in Q4 2021. The L8 pad will ramp up to >5,000 bbl/d in 2022 and has project economics of ~$270 million NPV10 (US$55 WTI flat pricing).
- Hangingstone: Production at pre-2020 shut-in levels with April averaging ~9,500 bbl/d. Forecasting $5 million in annual savings through the addition of a truck terminal at no capital cost to the Company and contracted third-party volumes up to 5,000 bbl/d (starting July).
- Light Oil: Focused on free cash flow generation; Kaybob East & Two Creeks Duvernay wells screen as top producers with IP180s and IP365s averaging 725 boe/d (85% oil) and ~550 boe/d (83% oil).
Financial Update and 2021 Outlook (US$60 WTI & US$11 WCS heavy differentials)
- Unrestricted Cash: $141 million forecasted to grow to ~$210 million by year-end.
- Cash Flow: Forecasted Adjusted EBITDA of >$210 million (~$155 million of Adjusted Funds Flow); unhedged annual EBITDA sensitivity of ~$70 million for every US$5/bbl move in oil prices.
- Net Debt: $419 million (excl. $135 million of restricted cash), 2x 2021 forecasted Adjusted EBITDA.
- Increased Production Outlook: Revised guidance of 32,000 – 34,000 boe/d (~90% liquids).
- Low Sustaining Capital: Unchanged $100 million capital budget funded within forecasted funds flow and generating free cash flow of ~$55 million.
- Reserve Based Lending Facility: Normal course extension completed to November 30, 2021.
- Balance Sheet: Planning to refinance US$450 million Second Lien Notes in the coming months as energy credit markets continue to improve. The refinancing will be supported by strong asset performance, continued execution on cost initiatives, and compelling cash generating outlook.
Inaugural ESG Report
- Inaugural Report: Proud to publish an Inaugural ESG report following Global Reporting Initiative (“GRI”) and Sustainability Accounting Standards Board (“SASB”) guidelines. The report is available on the Company’s website (https://www.atha.com/responsibility.html) and SEDAR (https://www.sedar.com).
- Environment: Achieved a 20% reduction in GHG emissions intensity since 2015 with a goal of a 30% reduction by 2025 by developing high quality resources and the deployment of new technology.
- Social: In 2020 best in class safety excellence with a 0.1 Total Recordable Frequency and no reportable spills; partnered with the Mikisew Cree First Nation and the Government of Alberta to create the world’s largest contiguous protected boreal forest area (Kitaskino Nuwenëné Wildland Provincial Park).
- Governance: Independent Board with established and robust corporate policies.
Business Environment and the Recovery from COVID-19
The COVID-19 pandemic that began in March 2020 had a significant negative impact on global commodity prices due to a reduction in oil demand as countries around the world enacted emergency measures to combat the spread of the virus. The Company took swift action in response to the pandemic and the economic crisis. Major initiatives included a reduction to the 2020 capital program, temporary production curtailments, partnering with service companies to reduce operating costs and reducing future financial commitments on the Keystone XL pipeline (“KXL”).
In the second half of 2020, commodity prices began to improve with both OPEC+ and North American producers reducing production allowing for global inventories to fall. Economies have started to reopen with positive developments on the vaccine front and world oil demand has almost recovered to pre-pandemic levels. Supply and demand fundamentals are now supporting a much stronger oil futures market.
In Alberta, physical markets and regional benchmark prices (e.g. WCS heavy oil) have also strengthened with higher WTI prices and tighter differentials as a result of curtailed volumes and falling inventories. Athabasca expects current WCS differentials to remain supported by muted industry growth, significant Q2 turnaround programs in the oil sands, and improving basin egress (including Enbridge Line 3 replacement H2 2021). 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 are emerging for WCS heavy oil to be among the most valuable global crude benchmarks.
Balance Sheet Update & Capital Guidance
Athabasca plans to refinance its US$450 million Senior Secured Second Lien Notes (“2022 Notes”) in the coming months as energy credit markets continue to improve. The Company’s goals include providing multi-year funding certainty and lowering the overall quantum and cost of debt.
The $100 million unchanged 2021 capital program is fully funded within forecasted Adjusted Funds Flow of ~$155 million (US$60 WTI & US$11 WCS differential) and the Company is expected to generate ~$55 million of Free Cash Flow through the balance of the year. Capital activity is focused on sustaining production at the Company’s cornerstone Leismer asset. The first quarter results support the strong start to the year and the Company is increasing its production guidance to 32,000 – 34,000 boe/d (90% liquids).
Net debt at March 31, 2021 was $419 million and represents 2x 2021 forecasted adjusted EBITDA (>$210 million). Liquidity is expected to grow from $141 million (unrestricted cash) at March 31, 2021 to ~$210 million at year-end (US$60 WTI & US$11 WCS differentials). The Company is committed to allocating free cash flow in order to achieve its long term debt targets of <1.5x Net Debt to EBITDA at US$55 WTI.
In April, the Company’s banking syndicate renewed the reserve-based lending facility until November 30, 2021. The credit facility remains unchanged at $37.6 million which reflects current outstanding letters of credit for long term transportation commitments. The banking syndicate has been streamlined to four long-term partners (ATB Financial, RBC Capital Markets, BMO Capital Markets and Goldman Sachs). In the current environment the Company’s low risk reserves have the potential to support a first lien credit facility which could provide access to additional liquidity concurrent with the 2022 Notes refinancing. At year-end 2020, McDaniel & Associates assigned reserve value (NPV10 before tax) of $508 million Proved Developed Producing and $1.6 billion Total Proved reserves under conservative price forecasts relative to the current strip commodity prices.
Athabasca’s risk management program targets hedging up to 50% of corporate production with an emphasis on securing funds flow to protect a base sustaining capital program. For the balance of 2021 (Q2 – Q4) the Company has hedged ~5,000 bbl/d of WTI swaps at ~US$60, ~11,700 bbl/d of WCS differentials at ~US$12, and ~13,600 bbl/d of WTI sold calls at ~US$55.75. The Company intends to add additional WTI hedging for 2021 with the recent strength in spot prices.
Financial and Operational Highlights
|Three months ended
|($ Thousands, unless otherwise noted)||2021||2020|
|Petroleum and natural gas production (boe/d)||34,401||36,557|
|Operating Income (Loss)(1)||$||65,928||$||(20,328)|
|Operating Income Net of Realized Hedging(1)(2)||$||44,815||$||1,098|
|Operating Netback(1) ($/boe)||$||21.12||$||(5.98)|
|Operating Netback Net of Realized Hedging(1)(2) ($/boe)||$||14.36||$||0.33|
|Capital Expenditures Net of Capital-Carry(1)||$||35,554||$||53,506|
|LIGHT OIL DIVISION|
|Petroleum and natural gas production(1) (boe/d)||8,542||8,242|
|Percentage Liquids(1) (%)||57%||59%|
|Operating Income (Loss)(1)||$||23,760||$||12,783|
|Operating Netback(1) ($/boe)||$||31.24||$||17.04|
|Capital Expenditures Net of Capital-Carry(1)||$||968||$||35,787|
|THERMAL OIL DIVISION|
|Bitumen production (bbl/d)||25,949||28,315|
|Operating Income (Loss)(1)||$||42,168||$||(33,111)|
|Operating Netback(1) ($/bbl)||$||17.85||$||(12.50)|
|CASH FLOW AND FUNDS FLOW|
|Cash flow from operating activities||$||1,138||$||(3,021)|
|per share – basic||$||–||$||(0.01)|
|Adjusted Funds Flow(1)||$||18,961||$||(27,883)|
|per share – basic||$||0.04||$||(0.05)|
|NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)|
|Net income (loss) and comprehensive income (loss)||$||(17,472)||$||(516,481)|
|per share – basic and diluted||$||(0.03)||$||(0.99)|
|COMMON SHARES OUTSTANDING|
|Weighted average shares outstanding – basic and diluted||530,675,391||523,595,977|
|March 31,||Dec. 31,|
|As at ($ Thousands)||2021||2020|
|LIQUIDITY AND BALANCE SHEET|
|Cash and cash equivalents||$||141,130||$||165,201|
|Available credit facilities(3)||$||98||$||348|
|Face value of long-term debt, including current portion(4)||$||565,875||$||572,940|
|(1)||Refer to the “Reader Advisory” section within this news release for additional information on Non-GAAP Financial Measures and production disclosure.|
|(2)||Includes realized commodity risk management loss of $21.1 million for the three months ended March 31, 2021 (three months ended March 31, 2020 – $21.4 million gain).|
|(3)||Includes available credit under Athabasca’s Credit Facility and Unsecured Letter of Credit Facility (see page 14 of the Company’s Q1 2021 MD&A).|
|(4)||The face value of the 2022 Notes is US$450 million. The 2022 Notes were translated into Canadian dollars at the March 31, 2021 exchange rate of US$1.00 = C$1.2575 (2020 – C$1.2732).|
Bitumen production for Q1 2021 averaged 25,949 bbl/d. The Thermal Oil division generated Operating Income of $42.2 million. The Western Canadian Select heavy oil benchmark averaged C$57.40/bbl for Q1 2021, up 61% from an average price of C$35.58/bbl in 2020. Q1 2021 Operating Netbacks for Leismer and Hangingstone were $20.67/bbl and $12.58/bbl, respectively. Thermal Oil margins have continued to improve year to date with March Operating Netbacks of ~$28/bbl and ~$20/bbl for each asset respectively. Capital expenditures for the quarter were $33.0 million.
Bitumen production for Q1 2021 averaged 17,002 bbl/d.
Current activity is focused on sustaining production at Leismer. In Q1 2021 the Company completed the drilling of two infill wells at Pad L6 and an additional well pair at Pad L7 with first production expected in July. Drilling operations are underway on a five well-pair sustaining pad (Pad L8). The five producer wells encountered the highest quality reservoir across all of Leismer’s wells drilled to date. The Company anticipates completing the drilling of the five injector wells and facility construction through Q2 and Q3 2021. Initial steam circulation is expected before year-end with first production in early 2022. The initial five well pairs on Pad L8 are expected to ramp-up to in excess of 5,000 bbl/d in 2022. The existing pipeline will support future development for up to 14 well pairs on Pad L8.
The Company is expanding its non-condensable gas co-injection (“NCG”) program across the field following successful implementation in 2020 (Pad L1 – L4) which has lowered mature pad SORs by ~16% from 4.2x to 3.5x (2019 vs. Q1 2021). NCG is expected to be operational on Pad L5 and L6 in Q2 2021.
Leismer has an estimated US$27/bbl WCS 2021 operating break-even. The asset is forecasted to generate ~$155 million of Operating Income in 2021 (US$60 WTI & US$11 WCS differentials).
Bitumen production for Q1 2021 averaged 8,947 bbl/d. The field restart has exceeded expectations with volumes recovering to pre shut-in levels. Current production is ~9,500 bbl/d (April). The standing well pair (AA03) started steaming in April with first oil expected in September. The Company is implementing NCG field-wide in 2021 that will support more efficient steam and pressure management.
During 2020, the Company implemented several cost saving measures reducing non-energy operating costs to a record low of $5.70/bbl in Q1 2021.
In March 2021, the Company executed a commercial arrangement with an industry leading marketing company to construct a truck-in terminal at no cost to Athabasca. Operations are expected to commence in July with up to 5,000 bbl/d of third party truck-in capacity. The additional volumes are expected to generate up to $5 million in annual savings through a processing fee and by leveraging existing volume commitments under Athabasca’s transportation agreements.
In 2021, Hangingstone will have no capital allocation other than routine pump replacements and has no sustaining capital requirements for the next several years.
Management’s execution to date on streamlining Hangingstone’s cost structure has materially improved the assets resiliency and profitability. Hangingstone now has an estimated US$33/bbl WCS operating break-even. The asset is forecasted to generate ~$55 million of Operating Income in 2021 (US$60 WTI & US$11 WCS differentials).
Production averaged 8,452 boe/d (57% Liquids) in Q1 2021. The division generated Operating Income of $23.8 million ($31.24/boe). Athabasca’s Light Oil Netbacks continue 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. Capital expenditures were $1.0 million during the quarter.
At Placid, the asset is positioned for flexible future development with an inventory of ~150 gross drilling locations and no near-term land retention requirements. Activity will be revisited following a successful refinancing.
At Kaybob, production results have been consistently strong with wells screening as top liquids producers in the basin. Well results in Two Creeks and Kaybob East have seen average productivity of ~725 boe/d IP180s (85% liquids) and ~550 boe/d IP365s (83% liquids). Under full development, well costs are expected to be less than $7.5 million in the volatile oil window. These 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.
Minimal capital activity ($5 million) is planned for 2021 with operations focused on facility maintenance and readiness for Duvernay completions in 2022. Light Oil is forecasted to generate ~$75 million of Operating Income in 2021 (US$60 WTI).
Annual General Meeting
Athabasca will hold its Annual General Meeting on Wednesday, May 5, 2021 at 9:00am (MDT). Due to restrictions on gatherings implemented by the Government of Alberta in response COVID-19 the Company is hosting a virtual meeting. Shareholders can listen to the Meeting via live webcast at:
with additional details available at:
An archived recording of the webcast will be available on the Company’s website for those unable to listen live.
About Athabasca Oil Corporation
Athabasca Oil Corporation is a Canadian energy company with a focused strategy on the development of thermal and light oil assets. Situated in Alberta’s Western Canadian Sedimentary Basin, the Company has amassed a significant land base of extensive, high quality resources. Athabasca’s common shares trade on the TSX under the symbol “ATH”. For more information, visit www.atha.com.
For more information, please contact:
Chief Financial Officer