CALGARY, Alberta – Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) reports its 2020 year-end results and annual reserves. In a year of unprecedented challenges, Athabasca demonstrated the exceptional resilience of its low-decline assets. In 2021, Athabasca is focused on resuming its pre-COVID business plan of free cash flow generation, disciplined operations and preserving long term future projects across its portfolio. Armed with an unrestricted cash balance of $165 million, the Company is focused on refinancing its debt in order to capture the unparalleled cashflow generation potential from its long reserve life, oil weighted asset base.
Q4 2020 and 2020 Corporate Highlights
- Production: 34,233 boe/d (89% Liquids) in Q4 and 32,483 boe/d (88% Liquids) in 2020.
- Adjusted Funds Flow: $11 million in Q4 and ($19) million in 2020.
- Capital Expenditures: $89 million ($39 million in Light Oil and $50 million in Thermal Oil) in 2020.
- Balance Sheet & Sustainability: $165 million of unrestricted cash at year-end; Net Debt of $412 million representing 2.5x 2021 forecasted EBITDA (US$55 WTI/US$12.50 WCS heavy differential). The Company has an unhedged EBITDA sensitivity of ~$70 million for a US$5 move in oil price.
- Reserves: 1.2 billion boe Proved plus Probable (2P) Reserves, with Leismer/Corner underpinning 1 billion barrels of low risk, long reserve life resource.
- Reserve Value (NPV10 before tax): $508 million Proved Developed Producing and $1.6 billion Total Proved reserves under year-end 2020 price forecasts that are conservative relative to current strip commodity prices.
- Maintaining Production with Low Sustaining Capital: $100 million capital budget funded within forecasted funds flow; maintaining production guidance of 31,000 – 33,000 boe/d (90% Liquids).
- Balance Sheet: Athabasca plans to refinance its US$450 million Second Lien Notes during the year as energy credit markets continue to improve. The Company maintains strong Liquidity of $165 million that is forecasted to grow through 2021 under current strip commodity prices.
- Thermal Oil: Activity at Leismer will include drilling two infill wells at Pad L6 and an additional well pair at Pad L7, with an expected on stream in H2 2021. The Company also plans to drill five well pairs at Pad L8 in H1 2021. This highly economic project will support production levels in 2022 and beyond.
- Light Oil: No new wells are expected to be placed on-stream during the year with operations focused on maintaining low operating costs and top tier netbacks. In Q4, the Company achieved operating costs of $7.93/boe and an industry leading operating netback of $22.61/boe.
Recent ESG Initiatives
- Kitaskino Nuwenëné Wildland Provincial Park: In late 2020, Athabasca relinquished 235,000 acres of mineral-land interests, in partnership with the Mikisew Cree First Nation and the Government of Alberta, to create the world’s largest contiguous protected boreal forest area.
- Health, Safety and Environmental Results: The Company continued its impressive record with an industry leading TRIF (Total Recordable Injury Frequency) of 0.1 and zero recordable spills for 2020.
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 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 projects, 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.
Long Term Egress Update
In January 2021, the US Government revoked the KXL Presidential permit and construction on the project was halted. Athabasca holds 10,000 bbl/d of capacity on KXL. This recent development does not impact the Company’s current liquidity position.
Athabasca also has a 20 year firm service transportation agreement with TC Energy for 7,200 bbl/d on the existing Keystone pipeline from Hardisty to the US Gulf Coast. The Company is anticipating an update on this service availability in 2021.
The Company also has 20,000 bbl/d service on the TransMountain Expansion (“TMX”) pipeline, with an expected in-service date in late 2022. The TMX service is increasingly valuable long-term capacity for Athabasca to access world markets.
Balance Sheet Outlook
Athabasca plans to refinance its US$450 million Second Lien Notes during the year as energy credit markets continue to improve. The Company’s 2021 capital program is fully funded within forecasted funds flow with strong free cash flow potential. Activity is focused on sustaining production at the Company’s cornerstone Leismer asset. These investments will support strong underlying asset and lending value. The Company maintains liquidity of $165 million at year-end 2020 that is forecasted to grow through H2 2021 with a front-end weighted capital program. The Company’s liquids weighted, long reserve life asset base supports attractive reserve coverage debt metrics with 0.9x Proved Developed Producing reserves to Total Debt and 2.7x Proved reserves to Total Debt (McDaniel NPV10 before tax reserve value / US$450 million Second Lien Notes). With strengthening oil price fundamentals the Company estimates its net debt to 2021 forecasted EBITDA at 2.5x (US$55 WTI & US$12.50 WCS heavy differential). The Company intends to remain nimble and creative in accessing the credit capital markets which could include a combination of term debt and bank debt to optimize its current capital structure. The Company’s goals include providing multi-year funding certainty and lowering the overall quantum and cost of debt.
Financial and Operational Highlights
|Three months ended
|($ Thousands, unless otherwise noted)||2020||2019||2020||2019|
|Petroleum and natural gas production (boe/d)||34,233||36,403||32,483||36,196|
|Operating Income (Loss)(1)(2)||$||30,935||$||42,881||$||81,011||$||233,219|
|Operating Netback(1)(2) ($/boe)||$||9.89||$||13.84||$||6.73||$||17.95|
|Capital Expenditures Net of Capital-Carry(1)||$||17,202||$||46,259||$||88,900||$||140,207|
|LIGHT OIL DIVISION|
|Petroleum and natural gas production (boe/d)(1)||9,394||8,642||9,738||10,138|
|Percentage Liquids (%)||58%||54%||60%||54%|
|Operating Income (Loss)(1)||$||19,542||$||16,287||$||62,002||$||95,004|
|Operating Netback(1) ($/boe)||$||22.61||$||20.49||$||17.40||$||25.68|
|Capital Expenditures Net of Capital-Carry(1)||$||117||$||22,936||$||38,911||$||50,753|
|THERMAL OIL DIVISION|
|Bitumen production (bbl/d)||24,839||27,761||22,745||26,058|
|Operating Income (Loss)(1)||$||20,746||$||28,658||$||(10,140)||$||182,196|
|Operating Netback(1) ($/bbl)||$||9.17||$||12.44||$||(1.19)||$||19.59|
|CASH FLOW AND FUNDS FLOW|
|Cash flow from operating activities||$||16,079||$||32,975||$||(22,910)||$||92,632|
|per share – basic||$||0.03||$||0.06||$||(0.04)||$||0.18|
|Adjusted Funds Flow(1)||$||10,753||$||21,478||$||(18,727)||$||154,760|
|per share – basic||$||0.02||$||0.04||$||(0.04)||$||0.30|
|NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)|
|Net income (loss) and comprehensive income (loss)||$||(56,891)||$||(8,757)||$||(657,525)||$||246,865|
|per share – basic||$||(0.11)||$||(0.02)||$||(1.24)||$||0.47|
|per share – diluted||$||(0.11)||$||(0.02)||$||(1.24)||$||0.47|
|COMMON SHARES OUTSTANDING|
|Weighted average shares outstanding – basic||530,675,391||523,428,276||528,837,646||521,316,320|
|Weighted average shares outstanding – diluted||533,453,490||523,428,276||528,837,646||526,290,689|
|Dec. 31,||Dec. 31,|
|As at ($ Thousands)||2020||2019|
|LIQUIDITY AND BALANCE SHEET|
|Cash and cash equivalents||$||165,201||$||254,389|
|Available credit facilities(3)||$||348||$||85,815|
|Capital-carry receivable (current and long-term portion – undiscounted)||$||–||$||22,740|
|Face value of long-term debt(4)||$||572,940||$||583,425|
(1) Refer to the “Reader Advisory” section within this press release for additional information on Non-GAAP Financial Measures and production disclosure.
(2) Includes realized commodity risk management loss of $9.4 million and gain of $29.1 million for the three months and year ended December 31, 2020, respectively (three months and year ended December 31, 2019 – $2.1 million loss and $44.0 million loss).
(3) Includes available credit under Athabasca’s Credit Facility and Unsecured Letter of Credit Facility (see page 15 of the MD&A).
(4) The face value of the 2022 Notes is US$450 million. The 2022 Notes were translated into Canadian dollars at the December 31, 2020 exchange rate of US$1.00 = C$1.2732 (2019 – C$1.2965).
Bitumen production for Q4 2020 and 2020 averaged 24,839 bbl/d and 22,745 bbl/d, respectively. 2020 production was impacted by voluntary curtailments at Leismer in Q2 and the suspension of operations at Hangingstone during Q2 and Q3 due to unprecedented low pricing. The Thermal Oil division generated Operating Income of $20.7 million and ($10.1) million in Q4 2020 and 2020, respectively. Operating Income was disproportionally impacted by extreme low pricing during Q2 and Q3 and subsequently strengthened with the return of production and stronger commodity prices in Q4 2020. Operating Netbacks for Q4 2020 were $9.17/bbl ($13.20/bbl at Leismer and -$0.29/bbl at Hangingstone). Capital expenditures for Q4 2020 and 2020 were $16.9 million and $49.8 million, respectively.
Bitumen production for Q4 2020 and 2020 averaged 17,379 bbl/d and 18,264 bbl/d, respectively.
In 2020, Pad L7 bitumen production ramped up to ~5,000 bbl/d. The pad demonstrated the successful utilization of technologies to increase well lengths by 50% (achieving lateral lengths of ~1,250 meter). In addition to improved economics, the successful implementation of longer well pairs decreases Athabasca’s pad surface footprint by ~50% in the Leismer long-term development program.
During 2020, Athabasca implemented a number of permanent costs saving measures at Leismer. A water disposal project was completed in Q1 reducing non-energy operating costs by ~$10 million on an annual basis. Additionally, non-condensable gas co-injection (“NCG”) was implemented on the mature pads and in conjunction with Pad L7 has reduced the projects Steam Oil Ratio (“SOR”) to 3.3x in 2020 (from 3.7x in 2019) and supported reduced emissions intensity by ~10% when compared 2019.
In 2021, capital will be focused on sustaining production at Leismer. The Company recently completed the drilling of two infill wells at Pad L6 and an additional well pair at Pad L7 with first production expected to be on stream in H2 2021. Athabasca has continued to progress project readiness for a five well-pair sustaining pad (Pad L8) and has sanctioned drilling to commence in March. The L8 project is highly economic with go-forward capital costs of $25 million and is expected to drive competitive capital efficiencies. L8 drilling operations are expected to be completed mid-year, followed by facility construction in Q3, and initial steam circulation before year-end. The Company anticipates first production in Q2 2022 with plateau rates of greater than 5,000 bbl/d in Q4 2022. The existing pipeline will support future development for up to a total of 14 well pairs on Pad L8.
Leismer has an estimated US$27/bbl WCS 2021 operating break-even (US$12.50 WCS heavy differential).
Bitumen production for Q4 2020 and 2020 averaged 7,460 bbl/d and 4,481 bbl/d, respectively. Operations were suspended in April 2020 for approximately five months in response to unprecedented commodity prices.
During the summer, the Company completed Hangingstone’s first major scheduled plant turnaround. Operations resumed on September 1 and the asset is expected to ramp-up to previous bitumen rates of 9,000 – 9,500 bbl/d in late 2021. The reservoir is responding well and production averaged ~8,800 bbl/d in February 2021. During 2020 the Company implemented several cost saving measures reducing non-energy operating costs to ~$9/bbl and resulting in ~$7 million of permanent annual savings.
The Company received regulatory approval in 2020 for the implementation of NCG co-injection. Injection was recently implemented on two well pairs with early results demonstrating strong pressure maintenance and reduced energy intensity. The Company plans to implement this technology field-wide in 2021.
In 2021, Hangingstone will have no capital allocation other than routine pump replacements and has no sustaining capital requirements for the next several years. The asset has an estimated US$36/bbl WCS 2021 operating break-even (US$12.50 WCS heavy differential).
Production averaged 9,394 boe/d (58% Liquids) and 9,738 boe/d (60% Liquids) in Q4 2020 and 2020, respectively. The business division generated Operating Income of $19.5 million ($22.61/boe) and $62.0 million ($17.40/boe) during these periods. 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 net of capital-carry were $0.1 million and $39 million in Q4 2020 and 2020, respectively.
At Placid, the Company completed and placed 10 gross Montney wells on production during the year. Well costs continue to improve with the 2020 program achieving $6.2 million drilling and completion (“D&C”) costs. No capital activity is budgeted for 2021. Placid is positioned for flexible future development with an inventory of ~150 gross drilling locations and no near-term land retention requirements.
At Kaybob, the Company placed 17 gross Duvernay wells on production during the year across the volatile oil window. 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). Under full development, D&C 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 across the play) and flexible development timing indicate significant value to Athabasca.
During Q1 2020, the capital-carry provision associated with the Kaybob partnership was completed, after an investment of C$1 billion over four winter drilling seasons. The play has seen significant commercial de-risking and is ready for future development. In 2021, minimal capital has been budgeted towards Kaybob until a more robust macro environment is certain. The Kabob area is supported by a strong Joint Development Agreement, established infrastructure and no near-term land retention requirements.
2021 Budget and Outlook
Athabasca is forecasting a 2021 capital budget of $100 million ($95 million Thermal Oil and $5 million Light Oil). The updated budget reflects $25 million for the increased scope of drilling and commissioning Pad L8 at Leismer. The capital program will support base production levels in H2 2021 and beyond. The program is anticipated to be fully funded within 2021 forecasted funds flow with upside potential at current strip pricing. Annual production guidance is maintained between 31,000 – 33,000 boe/d (90% Liquids).
2020 Year-End Reserves
Athabasca’s independent reserves evaluator, McDaniel & Associates Consultants Ltd. (“McDaniel”), prepared the year-end reserves evaluation effective December 31, 2020. The Company’s 2P reserves base is 1.2 billion boe Proved plus Probable, with Leismer/Corner underpinning 1 billion barrels of low risk, long reserve life resource. McDaniel’s estimates reserve value (NPV10 before tax) of $508 million Proved Developed Producing and $1.6 billion Total Proved reserves under conservative year-end 2020 price forecasts relative to the current strip commodity prices.
For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2020 Annual Information Form which is available on the Company’s website or on SEDAR www.sedar.com.
|Light Oil||Thermal Oil||Corporate|
|Proved Developed Producing||13||14||68||61||81||76|
|Proved Plus Probable||72||73||1,225||1,083||1,297||1,156|
|NPV10 BT ($MM)1|
|Proved Developed Producing||$170||$165||$963||$343||$1,133||$508|
|Proved Plus Probable||$604||$414||$4,364||$2,307||$4,968||$2,721|
1) Net present value of future net revenue before tax and at a 10% discount rate (NPV 10 before tax) for 2020 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2021. NPV 10BT for 2019 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2020.
2) Numbers in the table may not add precisely due to rounding.
Environment, Social and Governance (“ESG”) Update
Athabasca believes that strong performance in health, safety, and environment is essential to achieving our business goals and meeting the needs of stakeholders. We are focused on being a valued partner in local communities and industry programs while developing Alberta’s energy resources responsibly. We have developed policies, programs and strong governance practices to be consistent with these objectives.
In February 2021, the Government of Alberta announced an 143,800 hectare expansion of the Kitaskino Nuwenëné Wildland Provincial Park (“KNWP”) in Northern Alberta creating the largest continuous area of protected boreal forest in the world. Athabasca relinquished ~95,000 hectares of oil sands rights to support the expansion of the KNWP.
“Since 2019, Athabasca Oil has been collaborating with the Mikisew Cree First Nation and the Government of Alberta to expand the Kitaskino Nuwenëné Wildland Park. Athabasca Oil has relinquished over 95,000 hectares of mineral rights to help make this park expansion a reality. The expansion of the park will help the province meet its biodiversity and conservation goals in this culturally and ecologically significant area. This represents a significant success for Indigenous communities, industry and Albertans.”
Rob Broen, President and CEO, Athabasca Oil Corporation
The Company plans to release its inaugural ESG report in 2021.
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.