Q1 Highlights
- 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 (
- 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 everyUS$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”) andSustainability 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 ofAlberta to create the world’s largest contiguous protected boreal forest area (Kitaskino NuwenënéWildland 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
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
Balance Sheet Update & Capital Guidance
Athabasca plans to refinance its
The
Net debt at
In April, the Company’s banking syndicate renewed the reserve-based lending facility until
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
Financial and Operational Highlights
Three months ended | |||||
($ Thousands, unless otherwise noted) | 2021 | 2020 | |||
CONSOLIDATED | |||||
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 | $ | 35,554 | $ | 76,246 | |
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 | $ | 968 | $ | 58,527 | |
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) | |
Capital expenditures | $ | 33,014 | $ | 17,696 | |
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 |
As at ($ Thousands) | 2021 | 2020 | |||
LIQUIDITY AND BALANCE SHEET | |||||
Cash and cash equivalents | $ | 141,130 | $ | 165,201 | |
Restricted cash | $ | 135,120 | $ | 135,624 | |
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 |
(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 |
Operations Update
Thermal Oil
Bitumen production for Q1 2021 averaged 25,949 bbl/d. The Thermal Oil division generated Operating Income of
Leismer
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
Hangingstone
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
In
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
Light Oil
Production averaged 8,452 boe/d (57% Liquids) in Q1 2021. The division generated Operating Income of
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
Minimal capital activity (
Annual General Meeting
Athabasca will hold its Annual General Meeting on
https://web.lumiagm.com/456712114
with additional details available at:
https://www.atha.com/investors/presentation-events.html.
An archived recording of the webcast will be available on the Company’s website for those unable to listen live.
About
For more information, please contact:
Chief Financial Officer
1-403-817-9104
mtaylor@atha.com
Reader Advisory:
This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward-looking information. The use of any of the words “anticipate”, “plan”, “forecast”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “target”, “should”, “believe”, “predict”, “pursue”, “potential”, “view” and ”contemplate” and similar expressions are intended to identify forward-looking information. The forward-looking information is not historical fact, but rather is based on the Company’s current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company’s industry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information included in this News Release should not be unduly relied upon. This information speaks only as of the date of this News Release and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. In particular, this News Release contains forward-looking information pertaining to, but not limited to, the following: our strategic plans and free cash flow potential; the Company’s 2021 Outlook; including expected unrestricted cash, EBITDA, funds flow, net debt, production outlook, capital budget and operating income for Thermal Oil and Light Oil; EBITDA sensitivity; refinancing of its
In addition, information and statements in this News Release relating to "Reserves" are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future.
With respect to forward-looking information contained in this News Release, assumptions have been made regarding, among other things: commodity prices; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct business and the effects that such regulatory framework will have on the Company, including on the Company’s financial condition and results of operations; the Company’s financial and operational flexibility; the Company’s financial sustainability; Athabasca's cash flow break-even commodity price; the Company’s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the applicability of technologies for the recovery and production of the Company’s reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company’s capital programs; the Company’s future debt levels; future production levels; the Company’s ability to obtain financing and/or enter into joint venture arrangements, on acceptable terms; operating costs; compliance of counterparties with the terms of contractual arrangements; impact of increasing competition globally; collection risk of outstanding accounts receivable from third parties; geological and engineering estimates in respect of the Company’s reserves and resources; recoverability of reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities and the quality of its assets. Certain other assumptions related to the Company’s Reserves are contained in the report of
Actual results could differ materially from those anticipated in this forward-looking information as a result of the risk factors set forth in the Company’s Annual Information Form (“AIF”) dated
Also included in this News Release are estimates of Athabasca's 2021 Outlook which are based on the various assumptions as to production levels, commodity prices, currency exchange rates and other assumptions disclosed in this News Release. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca, and is included to provide readers with an understanding of the Company’s outlook. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The financial outlook contained in this New Release was made as of the date of this News release and the Company disclaims any intention or obligations to update or revise such financial outlook, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.
Oil and Gas Information
“BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Operating break‐even reflects the estimated WCS oil price per barrel required to generate an asset level operating income of Cdn
Initial Production Rates
Test Results and Initial Production Rates: The well test results and initial production rates provided in this News Release should be considered to be preliminary, except as otherwise indicated. Test results and initial production rates disclosed herein may not necessarily be indicative of long-term performance or of ultimate recovery.
Reserves Information
The McDaniel Report was prepared using the assumptions and methodology guidelines outlined in the COGE Handbook and in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities, effective
Reserve Values (i.e. Net Asset Value) is calculated using the estimated net present value of all future net revenue from our reserves, before income taxes discounted at 10%, as estimated by McDaniel effective
The 700 Duvernay drilling locations referenced include: 7 proved undeveloped locations and 78 probable undeveloped locations for a total of 85 booked locations with the balance being unbooked locations. The 150 Montney drilling locations referenced include: 63 proved undeveloped locations and 35 probable undeveloped locations for a total of 98 booked locations with the balance being unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by McDaniel as of
Non-GAAP Financial Measures and Production Disclosure
The "Adjusted Funds Flow”, "Light Oil Operating Income", “Light Oil Operating Netback”, “Light Oil Capital Expenditures Net of Capital‐Carry”, "Thermal Oil Operating Income (Loss)", "Thermal Oil Operating Netback", “Consolidated Operating Income”, “Consolidated Operating Netback”, “Consolidated Capital Expenditures Net of Capital‐Carry”, “Adjusted EBITDA”, and “Free Cash Flow” financial measures contained in this News Release do not have standardized meanings which are prescribed by IFRS and they are considered to be non‐GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance with IFRS. The “Advisories and Other Guidance” section within the Company’s Q1 2021 MD&A includes reconciliations of these measures, where applicable, to the nearest IFRS measures.
Adjusted Funds Flow is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Adjusted Funds Flow is calculated by adjusting for changes in non-cash working capital, restructuring expenses and settlement of provisions from cash flow from operating activities. The Adjusted Funds Flow measure allows management and others to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. Adjusted Funds Flow per share is calculated as Adjusted Funds Flow divided by the applicable number of weighted average shares outstanding.
The Operating Income (Loss) measures in this News Release are calculated by subtracting royalties, diluent expenses, operating expenses and transportation & marketing expenses from petroleum and natural gas sales and adjusting for the impacts of inventory write-downs in the first quarter of 2020 within the Thermal Oil division. The Operating Netback measures are calculated by dividing the Operating Income (Loss) by the production and is presented on a per boe basis. The Operating Income (Loss) and the Operating Netback measures allow management and others to evaluate the production results from the Company’s assets. The Consolidated Operating Income (Loss) Net of Realized Hedging measure in this News Release is calculated by adding or subtracting realized gains (losses) on commodity risk management contracts, royalties, the cost of diluent blending, operating expenses and transportation & marketing expenses from petroleum and natural gas sales and adjusting for the impacts of inventory write-downs in the first quarter of 2020. The Consolidated Operating Netback Net of Realized Hedging measure is calculated by dividing Consolidated Operating Income (Loss) Net of Realized Hedging by the total sales volumes and is presented on a per boe basis. The Consolidated Operating Income (Loss) Net of Realized Hedging and the Consolidated Operating Netback Net of Realized Hedging measures allow management and others to evaluate the production results from the Company’s Light Oil and Thermal Oil assets combined together including the impact of realized commodity risk management gains or losses.
The Consolidated Capital Expenditures Net of Capital-Carry and Light Oil Capital Expenditures Net of Capital-Carry measures in this News Release are outlined in the Company’s Q1 2021 MD&A. These measures allow management and others to evaluate the true net cash outflow related to Athabasca's capital expenditures.
Net Debt is defined as face value of term debt plus accounts payable and accrued liabilities plus current portion of provisions and other liabilities less current assets.
Adjusted EBITDA is defined as Net income (loss) and comprehensive income (loss) before financing and interest expense, depreciation, depletion, impairment and taxation (recovery) expense adjusted for unrealized foreign exchange gain (loss), unrealized gain (loss) on risk management contracts, gain (loss) on revaluation of provisions and other, gain (loss) on sale of assets and non-cash settled stock-based compensation.
Free cash flow is defined as Adjusted Funds Flow less Consolidated Capital Expenditures.
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
2021 | 2020 | ||||||||||||
Production | Q1 | Q4 | Q3 | Q2 | Q1 | Annual | |||||||
Greater Placid: | |||||||||||||
Condensate NGLs | bbl/d | 1,540 | 1,841 | 2,612 | 1,916 | 1,480 | 1,964 | ||||||
Other NGLs | bbl/d | 460 | 523 | 632 | 389 | 351 | 474 | ||||||
Natural gas(1) | mcf/d | 15,599 | 17,900 | 19,668 | 14,221 | 12,939 | 16,197 | ||||||
Total Greater Placid | boe/d | 4,600 | 5,347 | 6,522 | 4,675 | 3,988 | 5,138 | ||||||
Greater Kaybob: | |||||||||||||
Oil(2) | bbl/d | 2,511 | 2,845 | 3,685 | 3,226 | 2,708 | 3,117 | ||||||
Other NGLs | bbl/d | 327 | 264 | 332 | 291 | 359 | 311 | ||||||
Natural gas(1) | mcf/d | 6,083 | 5,629 | 7,746 | 7,642 | 7,123 | 7,032 | ||||||
Total Greater Kaybob | boe/d | 3,852 | 4,047 | 5,308 | 4,791 | 4,254 | 4,600 | ||||||
Light Oil: | |||||||||||||
Oil(2) | bbl/d | 2,511 | 2,845 | 3,685 | 3,226 | 2,708 | 3,117 | ||||||
Condensate NGLs | bbl/d | 1,540 | 1,841 | 2,612 | 1,916 | 1,480 | 1,964 | ||||||
Oil and condensate NGLs | bbl/d | 4,051 | 4,686 | 6,297 | 5,142 | 4,188 | 5,081 | ||||||
Other NGLs | bbl/d | 787 | 787 | 964 | 680 | 710 | 785 | ||||||
Natural gas(1) | mcf/d | 21,682 | 23,529 | 27,414 | 21,863 | 20,062 | 23,229 | ||||||
Total Light Oil division | boe/d | 8,452 | 9,394 | 11,830 | 9,466 | 8,242 | 9,738 | ||||||
Total Thermal Oil division bitumen | bbl/d | 25,949 | 24,839 | 20,231 | 17,601 | 28,315 | 22,745 | ||||||
boe/d | 34,401 | 34,233 | 32,061 | 27,067 | 36,557 | 32,483 |
(1) | Comprised of 99% or greater of shale gas, with the remaining being conventional natural gas. |
(2) | Comprised of 99% or greater of tight oil, with the remaining being light and medium crude oil. |
This News Release also makes reference to Athabasca's forecasted total average daily production of 32,000 - 34,000 boe/d for 2021. Athabasca expects that approximately 78% of that production will be comprised of bitumen, 10% shale gas, 6% tight oil, 4% condensate natural gas liquids and 2% other natural gas liquids.
Liquids is defined as bitumen, light crude oil, medium crude oil and natural gas liquids.
Additionally, this News Release makes reference to Athabasca's well results in Two Creeks and Kaybob East that have seen average productivity of ~725 boe/d IP180s (85% oil), which is comprised of ~80% tight oil, ~15% shale gas and ~5% NGLs, and ~550 boe/d (83% oil) IP365s, which is comprised of ~78% tight oil, ~17% shale gas and ~5% NGLs.
Source:
2021 GlobeNewswire, Inc., source