CALGARY – Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”) is pleased to report its audited 2021 year-end results and annual reserves, along with a strategic update and corporate outlook. Athabasca is uniquely positioned as a low leveraged company generating significant free cash flow through its low-decline, oil weighted asset base.
Q4 and Year-end 2021 Corporate Highlights
- Production: 35,147 boe/d (91% Liquids) in Q4 and 34,618 boe/d (90% Liquids) in 2021. Exceeded original annual guidance of 31-33,000 boe/d and higher than 2020 production of 32,483 boe/d.
- Capital Expenditures: $92 million, with largest spend of $82 million in Thermal Oil, including five new well pairs at Leismer that are now in operation and will ramp-up to an expected 5,400 bbl/d in 2022.
- Earnings: Net Income of ~$458 million in 2021; Adjusted EBITDA ~$245 million.
- Cash Flow: Cash Flow from Operating Activities of ~$194 million in 2021; Adjusted Funds Flow ~$184 million; Free Cash Flow ~$92 million. Significant cash flow expansion is expected in 2022 and beyond as described below.
- Q4 Netbacks: Operating netbacks in Q4 of $42.95/boe in Light Oil and $33.43/boe in Thermal Oil. All assets are competitively generating strong cash flow for the Company.
- Balance Sheet: ~$300 million of Liquidity at year‐end, including ~$223 million cash. Term on debt until Q4 2026. The Company announced a $32 million (US$25 million) term note repayment effective February 1, 2022 as part of its goal to be in a net cash position by the end of 2022.
2021 Reserves
- 2021 Reserves Increase: 87 MMBoe Proved Developed Producing (PDP) reserves resulting in a ~15% increase over 2020, and 441 MMboe Total Proved (TP) reserves representing a ~10% increase over 2020. Total Proved plus Probable (2P) reserves are 1,301 MMBoe, a ~13% increase over 2020. These increases were attained with a very modest capital program of $92 million in 2021.
- Long-Life Reserves: Athabasca has a large resource base with Total Proved reserve life of ~34 years and a Total Proved plus Probable reserve life of ~100 years.
- Reserve Value (NPV10 before tax): The Company saw a substantial increase in value year over year due to the increase in technical reserves and a significant commodity price recovery. Athabasca holds $1.5 billion of PDP reserves ($2.83 per share), $2.7 billion of TP reserves ($5.17 per share) and $4.5 billion of 2P reserves ($8.49 per share).
Strategic Update and Corporate Outlook
- Managing for Free Cash Flow. For 2022, Athabasca forecasts Adjusted EBITDA of ~$350 million, Adjusted Funds Flow of ~$300 million and Free Cash Flow of ~$180 million (US$85 WTI, US$13.50 Western Canadian Select “WCS” heavy differential). The Company further expects to generate ~$900 million in Free Cash Flow during the three year timeframe of 2022-24 (US$85 WTI, US$12.50 WCS differential flat pricing). Every $5 WTI impacts free cash flow by ~$45 million annually (unhedged).
- Clear Debt Reduction Targets. The Company is planning to utilize 100% of near‐term free cash flow to reduce its term debt and is anticipating being in a net cash position by year end 2022 at current commodity prices. Athabasca expects to also achieve its target term debt of US$175 million (50% reduction) in H1 2023. The Company recently redeemed US$25 million of debt in the open market with scheduled future debt repayments in May and November.
- Excellent Exposure to Commodity Upside. Athabasca has retained excellent exposure to upside in commodity prices with 50% of forecasted 2022 sales volumes unhedged, 20% collars with upside to US$110 WTI and 30% fixed swaps at an implied US$67.50 WTI. The Company has minimal hedging in 2023 and expects lower future hedge levels to protect its capital program as debt targets are achieved.
- Large Tax Pools: The Company has ~$3.2 billion of tax pools, including ~$2.4 billion of immediately deductible non-capital losses and exploration pools.
- Modest Capital Program to Hold Production Flat. The Company is maintaining its previously announced $128 million capital program in 2022, including a turnaround at Leismer. Corporate production is expected to be maintained at 33-34,000 boe/d. The largest capital allocation of $115 million will be to Thermal Oil, including the drilling of two infill wells and another five well pairs at Leismer following a successful 2021 drilling program. Light Oil allocation is $13 million and includes the completion of three Duvernay wells in Q1.
- Thermal Oil Differentiation. The top tier Leismer/Corner project underpins the Company’s free cash flow profile and long reserve life. Thermal Oil has strong operational netbacks ($34.97/bbl and $30.15/bbl at Leismer and Hangingstone in Q4 2021) and is forecasted to generate ~$390 million in Operating Income in 2022 (US$85 WTI, US$13.50 WCS heavy differential). At current commodity prices, these assets compete exceptionally well on cash flow metrics against top plays in North America with capital investments generating double-digit recycle ratios. Volumes are forecasted to grow through 2022 as Leismer Pad L8 ramps-up to its expected plateau rate of 5,400 bbl/d (five well pairs). The existing L8 gathering pipeline will support future development for a total of 14 well pairs on Pad L8. The Company will drill two additional infill wells at Pad L6 and five additional well pairs at Pad L8 in H2 2022.
- Pre-payout Royalty Position on Thermal Assets. Strong margins are supported by a pre-payout Crown royalty structure with Leismer forecasted to remain pre-payout until 2028 and Hangingstone well into the 2030s (US$85 WTI, US$12.50 WCS differential).
- High Margin Light Oil. The Company has a flexible development portfolio of ~850 de-risked Montney and Duvernay locations with existing infrastructure in place and minimal near-term land expiries. Athabasca’s Light Oil assets generate top tier netbacks ($42.95/boe in Q4 2021) with a long inventory of short cycle-time, high returning investment options. These assets are also a natural hedge for Thermal Oil assets through their production of diluent and natural gas. In Q1 2022, three Duvernay wells were completed and are expected to be on stream by the end of the quarter. These wells are in the Two Creeks area and the 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).
- Carbon Capture and Storage (CCS). Athabasca has a partnership with Entropy Inc. to develop and implement a carbon capture and storage project at Leismer using Entropy’s proprietary CCS technology. The partnership is currently progressing detailed design engineering plans and has developed a commercial model for investment with no expected capital costs for Athabasca. The partnership will share emissions credits and help achieve Athabasca’s target of reducing carbon emissions by 30% by 2025 (from 2015) and its aspiration of producing a net-zero barrel long term.
- Annual Environmental Social Governance “ESG” Disclosure. The Company will release its comprehensive ESG update in the Spring of 2022, following the release of its inaugural 2021 ESG report.
- Unlocking Shareholder Value. Transitioning the enterprise value to equity holders is expected to unlock significant shareholder value. Upon achieving its debt target the Company will enhance shareholder returns through the distribution of free cash flow and cash balances, including the consideration of share buybacks and dividends. The Company sees tremendous intrinsic value not reflected in the current share price. Additional guidance on the Company’s return of capital strategy will be provided in H2 2022.
Footnote: Refer to the “Reader Advisory” section within this news release for additional information on Non‐GAAP Financial Measures (e.g. Operating Income, Adjusted Funds Flow, Free Cash Flow, Adjusted EBITDA) and production disclosure.
Financial and Operational Highlights
Three months ended December 31, |
Year ended December 31, |
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($ Thousands, unless otherwise noted) | 2021 | 2020 | 2021 | 2020 | ||||||||||||
CONSOLIDATED | ||||||||||||||||
Petroleum and natural gas production (boe/d)(1) | 35,147 | 34,233 | 34,618 | 32,483 | ||||||||||||
Petroleum, natural gas and midstream sales | $ | 292,405 | $ | 155,109 | $ | 1,016,323 | $ | 464,648 | ||||||||
Operating Income (Loss)(1) | $ | 110,648 | $ | 40,288 | $ | 390,353 | $ | 51,862 | ||||||||
Operating Income (Loss) Net of Realized Hedging(1)(2) | $ | 65,735 | $ | 30,935 | $ | 278,664 | $ | 81,011 | ||||||||
Operating Netback ($/boe)(1) | $ | 35.43 | $ | 12.88 | $ | 31.00 | $ | 4.31 | ||||||||
Operating Netback Net of Realized Hedging ($/boe)(1)(2) | $ | 21.05 | $ | 9.89 | $ | 22.13 | $ | 6.73 | ||||||||
Capital expenditures | $ | 18,352 | $ | 17,202 | $ | 92,142 | $ | 111,640 | ||||||||
Capital Expenditures Net of Capital-Carry(1) | $ | 18,352 | $ | 17,202 | $ | 92,142 | $ | 88,900 | ||||||||
Free Cash Flow(1) | $ | 24,291 | $ | (6,449 | ) | $ | 91,923 | $ | (107,627 | ) | ||||||
THERMAL OIL DIVISION | ||||||||||||||||
Bitumen production (bbl/d) | 28,084 | 24,839 | 26,805 | 22,745 | ||||||||||||
Petroleum, natural gas and midstream sales | $ | 265,076 | $ | 132,635 | $ | 914,058 | $ | 383,940 | ||||||||
Operating Income (Loss)(1) | $ | 82,729 | $ | 20,746 | $ | 287,261 | $ | (10,140 | ) | |||||||
Operating Netback ($/bbl)(1) | $ | 33.43 | $ | 9.17 | $ | 29.49 | $ | (1.19 | ||||||||
Capital expenditures | $ | 12,355 | $ | 16,915 | $ | 81,985 | $ | 49,787 | ||||||||
LIGHT OIL DIVISION | ||||||||||||||||
Petroleum and natural gas production (boe/d)(1) | 7,063 | 9,394 | 7,813 | 9,738 | ||||||||||||
Percentage Liquids (%)(1) | 56% | 58% | 56% | 60% | ||||||||||||
Petroleum, natural gas and midstream sales | $ | 40,237 | $ | 30,180 | $ | 147,705 | $ | 107,600 | ||||||||
Operating Income (Loss)(1) | $ | 27,919 | $ | 19,542 | $ | 103,092 | $ | 62,002 | ||||||||
Operating Netback ($/boe)(1) | $ | 42.95 | $ | 22.61 | $ | 36.15 | $ | 17.40 | ||||||||
Capital expenditures | $ | 5,291 | $ | 117 | $ | 6,931 | $ | 61,651 | ||||||||
Capital Expenditures Net of Capital-Carry(1) | $ | 5,291 | $ | 117 | $ | 6,931 | $ | 38,911 | ||||||||
CASH FLOW AND FUNDS FLOW | ||||||||||||||||
Cash flow from operating activities | $ | 81,189 | $ | 16,079 | $ | 194,253 | $ | (22,910 | ) | |||||||
per share – basic | $ | 0.15 | $ | 0.03 | $ | 0.37 | $ | (0.04 | ) | |||||||
Adjusted Funds Flow(1) | $ | 42,643 | $ | 10,753 | $ | 184,065 | $ | (18,727 | ) | |||||||
per share – basic | $ | 0.08 | $ | 0.02 | $ | 0.35 | $ | (0.04 | ) | |||||||
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | ||||||||||||||||
Net income (loss) and comprehensive income (loss) | $ | 384,073 | $ | (56,891 | ) | $ | 457,608 | $ | (657,525 | ) | ||||||
per share – basic | $ | 0.72 | $ | (0.11 | ) | $ | 0.86 | $ | (1.24 | ) | ||||||
per share – diluted | $ | 0.70 | $ | (0.11 | ) | $ | 0.84 | $ | (1.24 | ) | ||||||
COMMON SHARES OUTSTANDING | ||||||||||||||||
Weighted average shares outstanding – basic | 530,744,156 | 530,675,391 | 530,692,724 | 528,837,646 | ||||||||||||
Weighted average shares outstanding – diluted | 551,124,848 | 533,453,490 | 546,717,181 | 528,837,646 |
(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 $44.9 million and $111.7 million for the three months and year ended December 31, 2021 (three months and year ended December 31, 2020 – $9.4 million loss and $29.1 million gain).
Dec. 31, | Dec. 31, | ||||||
As at ($ Thousands) | 2021 | 2020 | |||||
LIQUIDITY AND BALANCE SHEET | |||||||
Cash and cash equivalents | $ | 223,056 | $ | 165,201 | |||
Restricted cash | $ | — | $ | 135,624 | |||
Available credit facilities(3) | $ | 77,844 | $ | 348 | |||
Face value of long-term debt(4) | $ | 443,730 | $ | 572,940 |
(3) Includes available credit under Athabasca’s Credit Facility and Unsecured Letter of Credit Facility.
(4) The face value of the term debt at December 31, 2021 was US$350 million (December 31, 2020 – US$450 million) translated into Canadian dollars at the December 31, 2021 exchange rate of US$1.00 =C$1.2678 (December 31, 2020 – C$1.2732).
Operations Update
Thermal Oil
Bitumen production for Q4 2021 and 2021 averaged 28,084 bbl/d and 26,805 bbl/d, respectively. The Thermal Oil division generated Operating Income of $82.7 million and $287.3 million in Q4 2021 and 2021, respectively. Operating Netbacks for Q4 2021 were $33.43/bbl ($34.97/bbl at Leismer and $30.15/bbl at Hangingstone). Capital expenditures for Q4 2021 and 2021 were $12.4 million and $82.0 million, respectively.
The Company’s Thermal Oil portfolio is expected to contribute significant cash flow in 2022 with an estimated Operating Income of ~$390 million (US$85 WTI, US$13.50 WCS differential).
Leismer
Bitumen production for Q4 2021 and 2021 averaged 18,794 bbl/d and 17,707 bbl/d, respectively. The asset generated $202.1 million Operating Income in 2021 with a Q4 Operating Netback of $34.97/bbl.
In 2021 the Company completed the drilling of two infill wells at Pad L6, an additional well pair at Pad L7 and five well pairs at Pad L8. At L8, the producer wells encountered the highest quality reservoir across all of Leismer’s wells drilled to date. Facility construction was completed in October, steaming commenced last Fall and three wells were converted to full SAGD production in January, with the remaining wells to be placed on production in early Q2. Volumes are forecasted to grow through 2022 as Pad L8 ramps-up to its expected plateau rate of ~5,400 bbl/d (five well pairs). The existing L8 gathering pipeline will support future development for a total of 14 well pairs on Pad L8.
The Company will drill two additional infill wells at Pad L6 and five additional well pairs at Pad L8 in the second half of 2022. These wells will support production through 2023 and have unparalleled Profit to Investment Ratios (NPV/Investment) of ~10x and double-digit recycle rations at current commodity prices. Leismer production is expected to exit 2022 at ~21,000 bbl/d.
The Company has expanded non-condensable gas (“NCG”) co-injection across the field on mature pads supporting lower energy intensity with a current project steam oil ratio (“SOR”) of ~3.2x (February 2022).
Athabasca and Entropy Inc. are progressing their partnership under a letter of intent. Detailed engineering is underway and a commercial framework has been established that results in no capital commitments from Athabasca and a sharing of emissions credits. The plan is to implement a carbon capture module at the Leismer central processing unit along with evaluating local storage and future carbon trunkline options. It is expected that implementation will be done in stages with the aspiration of producing a net zero barrel longer-term.
Leismer has a significant Unrecovered Capital Balance of $1.6 billion which ensures a low Crown royalty framework as the asset is forecasted to remain pre-payout until 2028 (US$85 WTI, US$12.50 WCS differential).
Hangingstone
Bitumen production for Q4 2021 and 2021 averaged 9,290 bbl/d and 9,098 bbl/d respectively. The asset generated $85.2 million Operating Income in 2021 with a Q4 Operating Netback of $30.15/bbl.
In early 2022, the Hangingstone asset continues to exceed internal expectations with current production of ~9,500 bbl/d. 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. Trucking operations commenced on schedule in July. The additional volumes are forecasted to generate in excess of $5 million in additional annual cash flow through a processing fee while leveraging existing volume commitments under Athabasca’s transportation agreements. In May, Athabasca amended the Hangingstone Transportation and Storage Services Agreement that resulted in a $44 million prepayment from restricted cash, a ~$5 million reduction to annual tolls and a reduction in financial assurances by ~$44 million to ~$27 million.
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. The Company recently started up an additional well pair (AA03) and NCG co-injection is aiding in pressure support and reduced energy usage. The project achieved a record low SOR of ~3.7x (February 2022).
In 2022, Hangingstone will have no capital allocation other than routine pump replacements. Strong operational performance, cost enhancements and improved commodity prices are driving competitive margins.
Light Oil
Production averaged 7,063 boe/d (56% Liquids) and 7,813 boe/d (56% Liquids) in Q4 2021 and 2021, respectively. The business division generated Operating Income of $27.9 million ($42.95/boe) and $103.1 million ($36.15/boe) during these periods. Athabasca’s Light Oil Netbacks continue to be top quartile 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 $5.3 million and $6.9 million in Q4 2021 and 2021, respectively.
The Company’s Light Oil portfolio is expected to contribute significant cash flow in 2022 with an estimated Operating Income of ~$95 million (US$85 WTI, US$13.50 WCS differential).
Placid Montney
At Greater Placid, production averaged 3,902 boe/d (44% Liquids) in Q4 2021 with an Operating Netback of $36.13/boe. Placid is positioned for flexible future development with an inventory of ~150 gross drilling locations and minimal near-term land retention requirements.
Kaybob Duvernay
At Greater Kaybob, production averaged 3,161 boe/d (70% Liquids) in Q4 2021 with an Operating Netback of $51.40/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.
Three Duvernay wells in the oil window at Two Creeks were recently completed. The wells are expected to be placed on-stream by the end of Q1. The Kaybob area is supported by a strong Joint Development Agreement, established infrastructure and minimal near-term land retention requirements. The Company remains encouraged by competitor activity and recent new entrants into the play.
2021 Year-End Reserves
Athabasca’s independent reserves evaluator, McDaniel & Associates Consultants Ltd. (“McDaniel”), prepared the year-end reserves evaluation effective December 31, 2021. The Company achieved an increase in total reserves through its modest capital program and a substantial increase in NPV value due to the significant improvement in commodity prices.
The Company’s 2P reserves base is 1.3 billion boe, with Leismer/Corner underpinning over 1 billion barrels of low risk, top tier, long reserve life resource. McDaniel’s estimated reserve values (NPV10 before tax) are $1.5 billion PDP ($2.83 per share), $2.7 billion TP ($5.17 per share) and $4.5 billion 2P ($8.49 per share).
For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2021 Annual Information Form which is available on the Company’s website or on SEDAR www.sedar.com.
Light Oil | Thermal Oil | Corporate | ||||
2020 | 2021 | 2020 | 2021 | 2020 | 2021 | |
Reserves (mmboe) | ||||||
Proved Developed Producing | 14 | 13 | 61 | 74 | 76 | 87 |
Total Proved | 37 | 27 | 365 | 414 | 403 | 441 |
Proved Plus Probable | 73 | 72 | 1,083 | 1,230 | 1,156 | 1,301 |
NPV10 BT ($MM)1 | ||||||
Proved Developed Producing | $165 | $191 | $343 | $1,313 | $508 | $1,504 |
Total Proved | $234 | $278 | $1,321 | $2,466 | $1,555 | $2,744 |
Proved Plus Probable | $414 | $568 | $2,307 | $3,940 | $2,721 | $4,507 |
1) Net present value of future net revenue before tax and at a 10% discount rate (NPV 10 before tax) for 2021 is based on an average of McDaniel, Sproule and GLJ pricing as at January 1, 2022.
2) Numbers in the table may not add precisely due to rounding.
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:
Matthew Taylor Chief Financial Officer 1-403-817-9104 mtaylor@atha.com |
Robert Broen President and CEO 1-403-817-9190 rbroen@atha.com |