Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or “the Company”)
is pleased to announce it has entered into transaction agreements
(“Transaction”) to create Duvernay Energy Corporation (“Duvernay
Energy”) with Cenovus Energy Inc. (“Cenovus”). Duvernay Energy will
be a standalone self-funded entity that will drive strong, high
netback cash flow and production growth and is expected to unlock
significant value. The transaction is aligned with Athabasca’s
strategy to maximize cash flow per share growth and return capital
to shareholders.
Transaction Overview
Athabasca and Cenovus will jointly contribute
assets into Duvernay Energy. Athabasca will own a 70% equity
interest in Duvernay Energy with Cenovus owning the remaining 30%
equity interest. Athabasca will manage Duvernay Energy through a
management and operating services agreement. Duvernay Energy’s
Board of Directors will include three members nominated by
Athabasca and one member nominated by Cenovus.
On inception, Duvernay Energy will have strong
Liquidity including seed capital of $40 million and a $50 million
new credit facility led by ATB Financial. Athabasca’s $22 million
seed capital contribution to Duvernay Energy will be within its
previous $175 million 2024 capital guidance ($135 million Thermal
Oil and $40 million Light Oil). Athabasca is also contributing ~$20
million in expenditures related to Q4 2023 drilling operations on a
100% working interest multi-well pad and long lead inventory for
future activity.
The Transaction will have an effective date of
January 1, 2024, is expected to close in the first quarter of 2024
and is subject to customary closing conditions and regulatory
approvals, including Competition Act approval. On closing the
Company will provide updated guidance for Duvernay Energy and
Athabasca.
Duvernay Energy Assets
Duvernay Energy will be positioned with
unparalleled pure-play exposure to the prolific Kaybob Duvernay
resource play. Duvernay Energy’s assets will be primarily located
in the volatile oil region.
In addition to the Company’s existing joint
venture assets, Duvernay Energy has exposure to ~46,000 acres of
100% working interest operated lands contiguous to its existing
Duvernay assets. This acreage includes new lands strategically
acquired by Athabasca through Crown land sales over the last 18
months and Cenovus’s contribution of Kaybob acreage. In total,
Duvernay Energy will have exposure to ~200,000 gross acres in the
liquids rich and oil windows with ~500 gross future well locations.
The assets are serviced by existing infrastructure including two
operated oil batteries with a gas pipeline network connected to
both the Pembina Gas Infrastructure KA facility and the Keyera
Simonette facility. Liquids are directly connected to the Pembina
Peace liquids system. Duvernay Energy will also own an 8.1% working
interest in the 7-4-63-16W5 gas facility.
Current production from Duvernay Energy is
~2,000 boe/d (~75% Liquids) with a defined and self-funded
development plan outlined in the section below.
Duvernay Energy Land Map
Duvernay Energy Development Plans
Duvernay Energy’s development plans will
leverage off significant de-risking activity on its acreage (74
horizontal wells) and on adjacent competitor activity. Duvernay
Energy will execute a self-funded development plan that will target
growth to ~25,000 boe/d (~75% Liquids) in the late 2020s with an
inventory to support a stable production profile thereafter for
approximately twenty years.
The Company has extended production history with
well results consistently supporting type curve expectations. At
Kaybob East and Two Creeks, IP365’s have averaged ~550 boe/d per
well (85% Liquids) on the last 12 wells. Latest well design will
include lateral lengths up to 4,500 meters that are expected to
yield stronger initial rates, larger reserves and improved capital
efficiencies. Individual well costs are estimated to be $10 – 14
million, depending on pad size, lateral length and proppant
loading.
The 2024 development program will include 12
gross wells (7.1 net wells) with a capital budget of ~$82 million.
The program is expected to be funded from the $40 million seed
capital contribution and cash flow from Duvernay Energy. The plan
is expected to drive strong production momentum with production
forecasted to average ~6,000 boe/d in 2025. 2024 activity consists
of:
-
100% working interest activity: A recently spudded
two-well pad at Kaybob East will be placed on production in Q2
2024. An additional two multi-well pads will spud mid-year and are
expected to be placed on-stream in early 2025.
-
30% working interest Joint Venture activity: A
three-well pad at Kaybob West is expected to spud in Q1 2024 and
will be placed on production in Q2 2024. An additional four-well
pad at Kaybob East is expected to spud in Q4 2024 and will be
placed on production in 2025.
Long-term development is expected to be funded
within cash flow and is flexible for a range of commodity prices.
The plan will be weighted to activity on Duvernay Energy’s 100%
working interest acreage and augmented by development within its
30% working interest joint venture acreage.
Strategic Rationale
Transaction Accelerates Value in
Standalone Self-Funded Duvernay Energy. The new entity
will accelerate value capture for Athabasca’s shareholders by
providing a clear path for accretive production and cash flow
growth without sacrificing Athabasca’s ability to fund capital in
its Thermal Oil division or Athabasca’s return of capital strategy.
The Transaction consolidates Athabasca’s and Cenovus’s 100% working
interest operated assets, providing flexibility and efficiencies of
scale for impactful development, along with Athabasca’s existing
30% working interest Duvernay joint venture assets that are
governed by a strong joint development agreement. Production and
cash flow growth will quickly exceed the volumes associated with
the Montney non-core disposition completed in September
2023.
During 2024, Duvernay Energy is forecasting
capital expenditures of $82 million, funded by cash flow from the
entity and seed capital of $40 million from Athabasca ($22 million)
and Cenovus ($18 million). Duvernay Energy will also benefit from
~$20 million in expenditures related to Athabasca’s Q4 2023
drilling operations on a 100% working interest multi-well pad and
long lead inventory for future activity.
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, Net Cash,
Liquidity) and production disclosure.
1 Pricing Assumptions: 2024 US$80 WTI, US$15 Western Canadian
Select “WCS” heavy differential, C$3 AECO, and $0.75 C$/US$ FX.
2025-26 US$85 WTI, US$12.50 WCS heavy differential, C$3 AECO, and
$0.75 C$/US$ FX.
Athabasca Thermal Oil Budget
Maintained: Athabasca’s Thermal Oil division underpins the
Company’s strong free cash flow outlook, with an unchanged $135
million capital budget. At Leismer, production is expected to
increase to ~28,000 bbl/d by mid-year through a facility expansion
project and the ramp-up of eight behind pipe wells that recently
commenced steaming operations. This production level can be held
with modest sustaining capital (~$6/bbl) for many years into the
future. At Hangingstone, sustaining drilling will support base
production in 2025 and beyond with the objective of ensuring the
asset continues to deliver meaningful cash flow contributions.
Athabasca Managing for Strong Free Cash
Flow: Pro forma the Transaction, Athabasca forecasts
Adjusted Funds Flow of ~$460 million in 2024 (US$80/bbl WTI &
US$15/bbl WCS heavy differential)1, excluding its 70% equity
interest in Duvernay Energy. The capital forecast is $135 million
for Thermal Oil, a $40 million reduction in capital spending that
previously included Duvernay development. The Transaction does not
reduce Athabasca’s 2024 Free Cash Flow forecast which is maintained
at ~$325 million. The Company’s low sustaining capital requirements
are fully funded within cash flow to US$55/bbl WTI. During the
timeframe of 2024 – 2026, Athabasca forecasts >$1 billion in
Free Cash Flow1, representing over 50% of its current equity market
capitalization. Athabasca anticipates tightening of the WCS heavy
differentials from current levels as the Trans Mountain Expansion
pipeline (590,000 bbl/d) commences operations in 2024. Every $5/bbl
WTI change impacts Adjusted Funds Flow by ~$55 million annually and
every $5/bbl WCS change impacts Adjusted Funds Flow by ~$85 million
annually.
Return of Capital Commitments
Intact: Athabasca maintains its 2024 return of capital
commitments outlined in its budget release on December 6, 2023. The
Company intends to allocate 100% of Free Cash Flow to shareholders
through share buybacks. The Company anticipates completing its
current Normal Course Issuer Bid on March 15, 2024 with the
intention to renew the program thereafter with the Toronto Stock
Exchange for another 12-month period.
Financial Strength Remains: The
Company estimates 2023 year-end Liquidity of ~$455 million,
including cash of ~$370 million. The principal balance on the
Company’s senior secured second lien notes is US$157 million with
an estimated year-end Net Cash position of ~$155 million. The
Company has ~$2.8 billion in tax pools, including ~$2.3 billion of
immediately deductible non‐capital losses and exploration pools.
The Company does not anticipate paying cash taxes until 2030
($85/bbl WTI & $12.50/bbl WCS differential flat long-term
pricing).
Differentiated Assets: Duvernay
Energy’s funded growth profile complements the Company’s Thermal
assets by producing a diluent quality liquid product and creating a
natural hedge for diluent sourcing. The Thermal Oil division’s
strong margins and Free Cash Flow are supported by a pre-payout
Crown royalty structure, with royalty rates between 5 – 9%
anticipated to last into 20271. Leismer has regulatory approved
capacity of 40,000 bbl/d. Athabasca also has a fully de-risked
asset at Corner which also has regulatory approval for 40,000 bbl/d
with reservoir quality equivalent or better than Leismer.
Athabasca Executive Update
In conjunction with the Transaction, Athabasca
is pleased to announce the appointment of Mr. Bruce Beynon as Vice
President Light Oil, with primary responsibility for the
development of the assets within Duvernay Energy. Mr. Beynon is a
professional geologist with over 30 years of oil and gas industry
experience. Mr. Beynon is currently the President of Tiburon
Exploration Corp., a private consulting company. Prior thereto, Mr.
Beynon was Executive Vice President, Exploration and Corporate
Development at Baytex Energy Corporation. Prior to the merger
between Baytex and Raging River Exploration, Mr. Beynon held
several positions with Raging River including President. Mr. Mike
Wojcichowsky will assume the role of Vice President, Drilling
Completions Services and Light Oil Operations.
Mr. Robert Broen, President and CEO of Athabasca
Oil Corporation, will also assume the role of Chairman, President
and CEO of Duvernay Energy. The Board of Duvernay Energy will
consist of Mr. Rob Broen, Mr. Matt Taylor, Chief Financial Officer
of Athabasca, Mr. Cam Danyluk, General Counsel and Vice President
Corporate Development Athabasca, and Mr. Jeff Lawson, Senior
Vice-President Corporate Development, Cenovus.
Conference Call
Athabasca will be hosting a conference call for
the investment community to discuss the Transaction on Tuesday,
December 19, 2023 at 4:30 pm (MT).
To participate through the online webcast:
https://edge.media-server.com/mmc/p/6wqn4ts7
To participate through a dial-in conference
call:
https://register.vevent.com/register/BI6d50c66745394c03aa5095a2fd470d92
An archived recording of the call will be made
available on Athabasca’s website at:
https://www.atha.com/investors/presentation-events.html
Advisors
ATB Capital Markets is acting as financial
advisor for Athabasca in connection with the Transaction. ATB
Financial will lead Duvernay Energy’s new $50 million credit
facility. Norton Rose Fullbright Canada LLP is acting as legal
advisor for Athabasca.
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 |
Robert
Broen |
Chief Financial Officer |
President and CEO |
1-403-817-9104 |
1-403-817-9190 |
mtaylor@atha.com |
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 2024 capital expenditures, production and
financial guidance, Free Cash Flow outlook, financial metrics,
timing for development projects in Thermal Oil and Light Oil
Divisions, return of capital strategy, royalty rates, timing for
future cash taxes, 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, 2022 (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 Revised Annual
Information Form (“AIF”) dated May 11, 2023 and Management’s
Discussion and Analysis dated October 31, 2023, available on SEDAR
at www.sedarplus.ca, 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 2024 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
Initial Production Rates: The 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
December 31, 2022. There are numerous uncertainties inherent in
estimating quantities of bitumen, light crude oil and medium crude
oil, tight oil, conventional natural gas, shale gas and natural gas
liquids reserves and the future cash flows attributed to such
reserves. The reserve and associated cash flow information set
forth above are estimates only. In general, estimates of
economically recoverable reserves and the future net cash flows
therefrom are based upon a number of variable factors and
assumptions, such as historical production from the properties,
production rates, ultimate reserve recovery, timing and amount of
capital expenditures, marketability of oil and natural gas, royalty
rates, the assumed effects of regulation by governmental agencies
and future operating costs, all of which may vary materially. For
those reasons, estimates of the economically recoverable reserves
attributable to any particular group of properties, classification
of such reserves based on risk of recovery and estimates of future
net revenues associated with reserves prepared by different
engineers, or by the same engineers at different times, may vary.
The Company's actual production, revenues, taxes and development
and operating expenditures with respect to its reserves will vary
from estimates thereof and such variations could be material.
Reserves figures described herein have been rounded to the nearest
MMbbl or MMboe. For additional information regarding the
consolidated reserves and information concerning the resources of
the Company as evaluated by McDaniel in the McDaniel Report, please
refer to the Company’s AIF.
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 December 31, 2022 and based on
average pricing of McDaniel, Sproule and GLJ as of January 1,
2023.
The 500 gross total Duvernay drilling locations
referenced include: 5 proved undeveloped locations and 77 probable
undeveloped locations for a total of 82 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, 2022 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”, 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. Liquidity is a
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.
Liquidity is defined as cash and cash
equivalents plus available credit capacity.
A photo accompanying this announcement is available at
https://www.globenewswire.com/NewsRoom/AttachmentNg/df0b2141-7be0-46b3-9e24-30b71e684834
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