Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or “the Company”)
is pleased to announce its 2023 budget and return of capital
strategy, focused on Free Cash Flow generation and shareholder
returns.
2023 Budget and Guidance
Highlights
Capital Program. Athabasca is
planning expenditures of ~$145 million ($120 million Thermal Oil
& $25 million Light Oil) with activity primarily focused on
sustaining and growth projects at Leismer, a Montney pad in Placid
and routine maintenance across the portfolio. Resilient
Production. The portfolio of long reserve life assets
underpins a low corporate decline rate of ~5% annually. In 2023,
the Company plans to maintain year-over-year corporate production
with guidance of 34,500 – 36,000 boe/d (~93% Liquids) and growth to
materialize into 2024 as longer cycle projects come on-stream.
Debt Target Achieved. The Company has proactively
achieved its debt target of US$175 million through the retirement
of ~50% outstanding term debt principal, ahead of initial
expectations. Athabasca expects to be in a net cash position in Q1
2023.Managing for Strong Free Cash Flow. Athabasca
anticipates generating ~$415 million of Adjusted Funds Flow and
~$270 million of Free Cash Flow (US$85 WTI & US$17.50 WCS
differential)1. A $5/bbl change in WTI impacts Free Cash Flow by
~$50 million annually. Athabasca forecasts ~$1.1 Billion in Free
Cash Flow1 during the three year timeframe of 2023-25, representing
~70% of current equity market capitalization.Return of
Capital Strategy. In 2023, Athabasca plans to allocate a
minimum of 75% of Excess Cash Flow (Adjusted Funds Flow less
Sustaining Capital) to shareholders. Athabasca plans to commence a
share buyback program in April, the earliest date permitted under
the Company’s term debt agreement.Capital Efficient Growth
at Leismer. Leismer is expected to exit 2023 with
production of ~24,000 bbl/d. A facility debottleneck project will
support sustainable growth to ~28,000 bbl/d in 2024. The expansion
program has a competitive capital efficiency of ~$14,000/bbl/d and
provides tremendous long term value creation for shareholders. This
expansion program will not impact the return of capital strategy
and bolsters future Free Cash Flow generation through enhanced
margins.Carbon Capture. The Company has partnered
with Entropy Inc. to implement a carbon capture and storage (“CCS”)
project at Leismer, funded by Entropy using their proprietary CCS
technology. The project is expected to be sanctioned in 2023 and
will be built in conjunction with Leismer’s expansion plans. The
Company is on track to achieve its stated target of a 30% reduction
in emissions intensity by 2025.Thermal Oil
Differentiation. Strong margins and Free Cash Flow is
supported by ~$3 billion in corporate tax pools and a Thermal Oil
pre-payout Crown royalty structure, with royalty rates between 5 –
9% anticipated to last into 20271.
Risk Management. Athabasca has
a minimal 2023 hedge program in place. Strong Liquidity and low
sustaining capital advantage provides protection against price
volatility.
Footnote: Refer to the “Reader Advisory” section within this news release for additional information on
Non‐GAAP Financial Measures (e.g. Adjusted Funds
Flow, Free Cash Flow, Excess Free Cash Flow,
Sustaining Capital, Net Debt/Cash,
Liquidity) and production disclosure.1 Pricing
Assumptions: 2023 US$85 WTI, US$17.50 Western Canadian Select “WCS”
heavy differential, C$5 AECO, and $0.75 C$/US$ FX. 2024-25
US$85 WTI, US$12.50 WCS heavy differential, C$5 AECO, and $0.75
C$/US$ FX.
Asset Strategy
Athabasca has a unique liquids-weighted asset
portfolio. The production base is underpinned by low decline, long
reserve life assets in the oil sands and complemented by a deep
inventory of short-cycle time, high returning assets in Light Oil.
The asset base has exposure to Canada’s most active resource plays
(Montney, Duvernay, Oil Sands) with decades of development
potential.
Leismer has over 700 million barrels of Proved
plus Probable Reserves and is the Company’s cornerstone thermal oil
asset. Current production is ~21,600 bbl/d with a steam oil ratio
(“SOR”) of ~2.9x (November 2022). Production from five additional
Pad L8 wells drilled in 2022 will commence in Q2 2023 and ramp up
to a plateau rate of ~6,000 bbl/d. Leismer is expected to exit 2023
with production of ~24,000 bbl/d. A facility debottleneck project
has been sanctioned and will support sustainable growth up to
~28,000 bbl/d in 2024. This production level can be held with
modest sustaining capital (~$6/bbl) for many years into the future.
Capital scope in 2023 includes an oil processing facility upgrade,
along with drilling four additional sustaining well pairs at Pad L8
and four infill wells at Pad L7. The Company is able to leverage
existing excess steam capacity and has been proactive in acquiring
long lead equipment to ensure successful delivery of the program at
a competitive capital efficiency of ~$14,000/bbl/d for the
debottleneck project. This project is expected to enhance margins
through increased operating scale. The Company has also partnered
with Entropy Inc. with plans to sanction the first phase of the CCS
project in 2023, utilizing capital and proprietary technology
provided by Entropy.
At Hangingstone, the Company is preparing for
future sustaining well pairs in 2024 and beyond.
At Placid in the Light Oil division, Athabasca
will commence drilling a multi-well Montney pad in Q1 2023 with
completions and tie-in to follow in the summer. The Montney program
is designed to offset natural production declines and maintain
strong operating margins. The Company believes its Kaybob Duvernay
assets have also demonstrated sustained top-tier results. The Light
Oil land position has no near-term expiries and is ready for future
development with over 850 Montney and Duvernay locations.
Return of Capital Strategy
Athabasca has transitioned a significant portion
of its enterprise value to shareholders through its debt reduction
priority in 2022. The Company has retired ~C$227 million (US$174.8
million) of its term debt representing a ~50% reduction in
outstanding principal. The Company has now achieved its debt target
and has also retained the strategic option to further reduce debt
at an attractive price in May 2023 by utilizing the Free Cash Flow
sweep feature within its indenture. The Company expects to be in a
net cash position in Q1 2023.
Athabasca’s capital allocation framework
balances material near-term return of capital initiatives for
shareholders, with a strong multi-year growth trajectory of cash
flow per share. The Company sees tremendous intrinsic value not
reflected in the current share price and is planning to allocate a
minimum of 75% of Excess Cash Flow (Adjusted Funds Flow less
Sustaining Capital) to shareholders. Athabasca intends to apply to
the TSX for a Normal Course Issuer Bid program that provides the
ability to purchase up to 10% of the Company’s float per annum,
starting in April. Additional Excess Cash Flow allocation will be
commodity price dependent and could include additional share
buybacks dependent on valuation, further debt reduction or high
return growth projects.
Balance Sheet and Risk Management Update
The Company has a constructive outlook on oil
prices given years of industry underinvestment. The Company
believes the recent wider WCS differentials is transitory as the US
administration tapers Strategic Petroleum Reserve releases and
refinery maintenance season concludes.
Athabasca maintains an exceptionally strong
balance sheet that affords it protection against commodity price
volatility while maintaining significant exposure to higher prices.
The Company recently increased its Unsecured Letter of Credit
Facility with ATB Financial markets to $60 million (up from $50
million) and the facility is supported by a performance security
guaranteed from Export Development Canada. The Company has current
Liquidity of ~$288 million inclusive of ~$200 million cash and ~$88
million of credit facility availability.
Athabasca has a minimal 2023 hedge program in
place with 13,750 bbl/d of WTI collars for Q1 2023 at a floor of
~US$52 and a ceiling of ~US$115 and 21 mmcf/d of its Thermal Oil
gas input costs hedged at ~C$5 AECO for the full year. Going
forward, the Company expects to maintain hedges on ~25% of its
production base, in accordance with current debt agreements. These
hedges, combined with our strong Liquidity, will be executed to
provide downside protection for a minimal capital program while
providing maximum exposure to a strong oil price environment.
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 |
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Robert Broen |
Chief Financial Officer |
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President and CEO |
1-403-817-9104 |
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1-403-817-9190 |
mtaylor@atha.com |
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rbroen@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: the Company’s 2022 and 2023 capital, production and
financial guidance, 2023-25 Free Cash Flow outlook, financial
metrics for Thermal Oil sustaining projects, return of capital
strategy and other matters.
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
funds flow, and free cash flow outlook; 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 McDaniel &
Associates Consultants Ltd. (“McDaniel”) evaluating Athabasca’s
Proved Reserves, Probable Reserves and Contingent Resources as at
December 31, 2021 (which is respectively referred to herein as the
"McDaniel Report”).
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 March 2, 2022 and Management’s Discussion and
Analysis dated November 2, 2022, available on SEDAR at
www.sedar.com, including, but not limited to: weakness in the oil
and gas industry; exploration, development and production risks;
prices, markets and marketing; market conditions; continued impact
of the COVID-19 pandemic; ability to finance capital requirements;
climate change and carbon pricing risk; regulatory environment and
changes in applicable law; gathering and processing facilities,
pipeline systems and rail; statutes and regulations regarding the
environment; political uncertainty; state of capital markets;
anticipated benefits of acquisitions and dispositions; abandonment
and reclamation costs; changing demand for oil and natural gas
products; royalty regimes; foreign exchange rates and interest
rates; reserves; hedging; operational dependence; operating costs;
project risks; financial assurances; diluent supply; third party
credit risk; indigenous claims; reliance on key personnel and
operators; income tax; cybersecurity; advanced technologies;
hydraulic fracturing; liability management; seasonality and weather
conditions; unexpected events; internal controls; insurance;
litigation; natural gas overlying bitumen resources; competition;
chain of title and expiration of licenses and leases; breaches of
confidentiality; new industry related activities or new
geographical areas; and risks related to our debt and
securities.
Also included in this News Release are estimates
of Athabasca's 2022 and 2023 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.
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 850 drilling locations referenced herein
includes 700 Duvernay locations and 150 Montney locations. The 700
Duvernay (Greater Kaybob) drilling locations 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 (Greater Placid) locations
include: 39 proved undeveloped locations and 59 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 December 31, 2021 and account for drilling
locations that have associated proved and/or probable reserves, as
applicable. Unbooked locations are internal management estimates.
Unbooked locations do not have attributed reserves or resources
(including contingent or prospective). Unbooked locations have been
identified by management as an estimation of Athabasca’s multi-year
drilling activities expected to occur over the next two decades
based on evaluation of applicable geologic, seismic, engineering,
production and reserves information. There is no certainty that the
Company will drill all unbooked drilling locations and if drilled
there is no certainty that such locations will result in additional
oil and gas reserves, resources or production. The drilling
locations on which the Company will actually drill wells, including
the number and timing thereof is ultimately dependent upon the
availability of funding, commodity prices, provincial fiscal and
royalty policies, costs, actual drilling results, additional
reservoir information that is obtained and other factors.
Non-GAAP and Other Financial Measures,
and Production Disclosure
The “Adjusted Funds Flow”, “Free Cash Flow”,
“Excess Free Cash Flow” and “Sustaining Capital” 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
financial 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.
Net Debt/Cash and
Liquidity are supplementary financial measures.
Adjusted Funds Flow and Free Cash Flow are
non-GAAP financial measures and are not intended to represent cash
flow from operating activities, net earnings or other measures of
financial performance calculated in accordance with IFRS. The
Adjusted Funds Flow and Free Cash Flow measures allow 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 is calculated by adjusting for changes in
non‐cash working capital and settlement of provisions from cash
flow from operating activities. The Free Cash Flow measure is
calculated by subtracting Capital Expenditures from Adjusted Funds
Flow.
The Excess Free Cash Flow and Sustaining Capital
measures allow management and others to evaluate the Company’s
ability to return capital to Shareholders. Sustaining Capital is
managements assumption of the required capital to maintain the
Company’s production base. The Excess Free Cash Flow measure is
calculated by Adjusted Funds Flow less Sustaining Capital.
Net Debt/Cash is defined as the face value of
term debt, plus accounts payable and accrued liabilities, plus
current portion of provisions and other liabilities less current
assets and excluding risk management contracts.
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes
details
This News Release makes reference to Athabasca's
forecasted total average daily production between 34,500 - 36,000
boe/d for 2023. Athabasca expects that approximately 84% of that
production will be comprised of bitumen, 7% shale gas, 4% tight
oil, 3% condensate natural gas liquids and 2% other natural gas
liquids.
Liquids is defined as bitumen, tight oil, light
crude oil, medium crude oil and natural gas liquids.
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