Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”)
is pleased to report its first quarter results showcasing
operational momentum at its cornerstone Leismer asset, continued
debt reduction and execution on its return of capital commitment
through inaugural share repurchases. Athabasca is uniquely
positioned as a low leveraged company generating significant Free
Cash Flow through its low-decline, oil weighted asset base.
Q1 2023 and Recent Corporate
Highlights
-
Production: 34,683 boe/d (93% Liquids) consisting
of 29,179 bbl/d in Thermal Oil and 5,504 boe/d in Light Oil. The
Company is maintaining annual guidance of 34,500 – 36,000 boe/d as
Leismer production ramps up throughout the remainder of 2023.
-
Capital Program: $26 million focused on Leismer’s
expansion project in Thermal Oil. Capital guidance for the year
remains at $145 million ($120 million Thermal Oil and $25 million
Light Oil).
-
Leismer: Steaming commenced on five new well
pairs, with production expected to ramp up to an exit rate of
24,000 bbl/d. An expansion project is underway, driving growth to
28,000 bbl/d by mid-2024, within existing capital guidance at a
competitive capital efficiency of $14,000/bbl/d. This project is
expected to drive margin expansion of ~$5/bbl at Leismer through
increased operating scale.
-
Operating Income: Operating Income of $57 million
consisting of $42 million ($14.52/bbl) from Thermal Oil and $15
million ($30.35/boe) from Light Oil. Netbacks in the Thermal Oil
division were impacted by wide Western Canadian Select (“WCS”)
heavy differentials following short-term headwinds, including the
Keystone pipeline leak in December 2022. WCS differentials have
tightened significantly to ~US$15 currently compared with US$24.77
in the first quarter. Athabasca expects differentials to improve
further into 2024 with the start-up of the Trans Mountain pipeline
expansion.
-
Cash Flow: Cash Flow from Operating Activities of
$21 million and Adjusted Funds Flow of ($9) million were impacted
by $44 million of non-recurring financial adjustments. Deferred
hedging premiums incurred as part of the Fall 2021 debt refinancing
transaction have now fully expired. Additionally, as part of its
efforts to maximize shareholder returns the Company elected to cash
settle a portion of its share based compensation, reducing dilution
in advance of the share buyback program which commenced in April.
The Company’s Thermal Oil assets are estimated to remain in a
pre-payout Crown royalty structure until the end of 2027 and
Athabasca is forecasting ~$1 Billion in Free Cash Flow1 generation
over a three year timeframe of 2023-25.
-
Balance Sheet: Opportunistically redeemed $18
million (US$13 million) in Term Debt and achieved the lowest level
of total debt in corporate history of $219 million (US$162
million). Liquidity of $261 million, including cash of $173
million.
-
Return of Capital through Share Repurchases: The
share buyback program commenced in April and to date the Company
has repurchased for cancellation 6.2 million common shares for
total consideration of $20 million.
-
Resolution of Legacy Tax Appeal: Subsequent to the
quarter, Athabasca has successfully appealed a 2012 tax
reassessment and anticipates the return of a $12.6 million deposit
in the near term. Athabasca has $3.1 Billion of corporate tax pools
and does not forecast paying taxes for approximately seven
years.
Strategic Update and Corporate
Guidance
-
Return of Capital Commitment: Athabasca is
committed to allocating a minimum of 75% of Excess Cash Flow
(Adjusted Funds Flow less Sustaining Capital) in 2023 to
shareholders through share buybacks. The buyback program commenced
in April and to date the Company has repurchased for cancellation
6.2 million common shares for total consideration of $20 million.
Additional Excess Cash Flow allocation will be commodity price
dependent and could include additional share repurchases dependent
on valuation, further debt reduction or high return growth
projects.
-
Capital Guidance: The Company is executing a ~$145
million capital program this year ($120 million Thermal and $25
million Light Oil) with activity focused on advancing the expansion
project at Leismer.
-
Production Guidance. Overall production is
expected to grow by 5 – 7% through expansion plans at Leismer and
modest investment in the Light Oil assets. 2023 Guidance remains
unchanged at 34,500 – 36,000 boe/d (93% Liquids). The portfolio of
long life assets underpin a low corporate decline of ~5%
annually.
-
Capital Efficient Growth at Leismer: Leismer is
expected to exit 2023 with production of ~24,000 bbl/d. A facility
expansion and additional drilling will support sustainable growth
to ~28,000 bbl/d by mid-2024 at a competitive capital efficiency of
~$14,000/bbl/d. This project is on-track with previous guidance,
will not impact the return of capital strategy and is expected to
bolster future Free Cash Flow generation through enhanced
margins.
-
Managing for Free Cash Flow: Athabasca is
positioned for continued margin growth in 2024 with the Leismer
expansion and expected narrower WCS heavy differentials following
the expected start-up of the Trans Mountain Pipeline Expansion
project in 2024. The Company expects to generate ~$1 Billion in
Free Cash Flow1 during the three-year timeframe of 2023-25.
-
Thermal Oil Differentiation: Strong margins and
Free Cash Flow are supported by a Thermal Oil pre-payout Crown
royalty structure, with royalty rates between 5 – 9%. Leismer is
estimated to remain pre-payout until the end of 2027 and
Hangingstone well into the 2030s (US$85 WTI, US$12.50 WCS
differential). This results in maximum cash flow at current
commodity prices and creates a significant advantage over the
majority of industry oil sands projects.
-
Excellent Exposure to Commodity Upside: Athabasca
has excellent exposure to upside in commodity prices with 25% of
forecasted 2023 production volumes hedged through collars,
providing upside to ~US$106 WTI. Every $5/bbl WTI change impacts
annual cash flow by ~$50 million (unhedged) and every US$5/bbl WCS
differential change impacts annual cash flow by ~$80 million
(unhedged).
Alberta Wildfire Update
-
Minimal Impact: The Company’s Light Oil operations
were temporarily affected by the Alberta wildfires. As a
precautionary measure Athabasca shut-in two of its facilities last
weekend which are currently resuming operations with no damage to
well sites or infrastructure. The Company estimates ~300 boe/d of
current downtime and anticipates minimal impact to its annual
corporate production guidance. There has been no impact to the
Company’s Thermal Oil operations.
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 Cash Flow,
Sustaining Capital,
Liquidity) and production disclosure. 1 Pricing
Assumptions: 2023 realized prices in Q1 and flat pricing of US$80
WTI, US$15 Western Canadian Select “WCS” heavy differential, C$3
AECO, and $0.74 C$/US$ FX for Q2-Q4. 2024-25 flat pricing of US$85
WTI, US$12.50 WCS heavy differential, C$5 AECO, and $0.75 C$/US$
FX.
Financial and Operational Highlights
|
|
Three months
endedMarch 31, |
($ Thousands, unless otherwise noted) |
|
2023 |
|
|
2022 |
|
CONSOLIDATED |
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
|
34,683 |
|
|
|
34,679 |
|
Petroleum, natural gas and midstream sales |
|
$ |
290,741 |
|
|
$ |
389,424 |
|
Operating Income (Loss)(1) |
|
$ |
56,535 |
|
|
$ |
150,640 |
|
Operating Income (Loss) Net of Realized Hedging(1)(2) |
|
$ |
34,480 |
|
|
$ |
102,994 |
|
Operating Netback ($/boe)(1) |
|
$ |
16.85 |
|
|
$ |
47.40 |
|
Operating Netback Net of Realized Hedging ($/boe)(1)(2) |
|
$ |
10.27 |
|
|
$ |
32.41 |
|
Capital expenditures |
|
$ |
26,362 |
|
|
$ |
30,929 |
|
Free Cash Flow(1) |
|
$ |
(35,758 |
) |
|
$ |
43,832 |
|
THERMAL OIL DIVISION |
|
|
|
|
|
|
Bitumen production (bbl/d)(1) |
|
|
29,179 |
|
|
|
27,909 |
|
Petroleum, natural gas and midstream sales |
|
$ |
269,102 |
|
|
$ |
360,281 |
|
Operating Income (Loss)(1) |
|
$ |
41,497 |
|
|
$ |
120,837 |
|
Operating Netback ($/bbl)(1) |
|
$ |
14.52 |
|
|
$ |
47.04 |
|
Capital expenditures |
|
$ |
22,836 |
|
|
$ |
21,182 |
|
LIGHT OIL DIVISION |
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
|
5,504 |
|
|
|
6,770 |
|
Percentage Liquids (%)(1) |
|
57 |
% |
|
57 |
% |
Petroleum, natural gas and midstream sales |
|
$ |
29,889 |
|
|
$ |
45,108 |
|
Operating Income (Loss)(1) |
|
$ |
15,038 |
|
|
$ |
29,803 |
|
Operating Netback ($/boe)(1) |
|
$ |
30.35 |
|
|
$ |
48.92 |
|
Capital expenditures |
|
$ |
1,876 |
|
|
$ |
7,987 |
|
CASH FLOW AND FUNDS FLOW |
|
|
|
|
|
|
Cash flow from operating activities |
|
$ |
20,537 |
|
|
$ |
59,862 |
|
per share - basic |
|
$ |
0.04 |
|
|
$ |
0.11 |
|
Adjusted Funds Flow(1) |
|
$ |
(9,396 |
) |
|
$ |
74,761 |
|
per share - basic |
|
$ |
(0.02 |
) |
|
$ |
0.14 |
|
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) |
|
|
|
|
|
|
Net income (loss) and comprehensive income (loss) |
|
$ |
(56,635 |
) |
|
$ |
(119,601 |
) |
per share - basic |
|
$ |
(0.10 |
) |
|
$ |
(0.23 |
) |
per share - diluted |
|
$ |
(0.10 |
) |
|
$ |
(0.23 |
) |
COMMON SHARES OUTSTANDING |
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
|
586,631,143 |
|
|
|
531,091,102 |
|
Weighted average shares outstanding - diluted |
|
|
586,631,143 |
|
|
|
531,091,102 |
|
|
|
March 31, |
|
December 31, |
|
As at ($ Thousands) |
|
2023 |
|
2022 |
|
LIQUIDITY AND BALANCE SHEET |
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
173,280 |
|
$ |
197,525 |
|
Available credit facilities(3) |
|
$ |
87,838 |
|
$ |
87,838 |
|
Face value of term debt(4) |
|
$ |
219,009 |
|
$ |
237,231 |
|
(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 $22.1 million for the three
months ended March 31, 2023 (three months ended March 31, 2022 loss
of $47.6 million).(3) Includes available credit under Athabasca's
Credit Facility and Unsecured Letter of Credit Facility.(4) The
face value of the term debt at March 31, 2023 was US$162 million
(December 31, 2022 – US$175 million) translated into Canadian
dollars at the March 31, 2023 exchange rate of US$1.00 = C$1.3533
(December 31, 2022 – C$1.3544).
Operations Update
Thermal Oil
Bitumen production for the first quarter of 2023
averaged 29,179 bbl/d. The Thermal Oil division generated Operating
Income of $41.5 million ($14.52/bbl) during the period with capital
expenditures of $22.8 million, primarily related to sustaining
operations at Leismer.
Leismer
In the first quarter of 2023, the Company
drilled two observation wells at L8 South and a disposal well.
Steam circulation is underway on the five additional new well pairs
at Pad L8 with first production expected mid-year. Leismer is
expected to exit 2023 with production of ~24,000 bbl/d with
contribution of ~6,000 bbl/d of stable production from the new well
pairs.
A facility expansion project has been sanctioned
and will support sustainable growth up to ~28,000 bbl/d by
mid-2024. This production level can be held with modest sustaining
capital (~$6/bbl) for many years into the future. Capital scope in
2023 includes the expansion project along with drilling four
additional sustaining well pairs at Pad L8 and four infill wells at
Pad L7. The Company anticipates a drilling rig to commence
operations in June. The Company is able to leverage existing excess
steam capacity and has been proactive in acquiring long lead
equipment. The project is budgeted at a competitive capital
efficiency of ~$14,000/bbl/d and is expected to enhance margins by
~$5/bbl from current levels through increased operating scale.
Leismer has a significant unrecovered capital
balance of ~$1.4 billion (2022 year-end) which ensures a low Crown
royalty framework as the asset is estimated to remain pre-payout
until the end of 2027 (US$85 WTI, US$12.50 WCS differential).
Hangingstone
Non-condensable gas co-injection has aided in
pressure support and reduced energy usage. Hangingstone’s steam oil
ratio averaged 3.6x year to date. The Company is preparing for
operational readiness to drill sustaining well pairs in 2024 and
beyond to maintain production levels.
Light Oil
Production for the first quarter of 2023
averaged 5,504 boe/d (57% Liquids). The Light Oil division
generated Operating Income of $15.0 million ($30.35/boe) during the
period with capital expenditures of $1.9 million.
Three Duvernay wells at Two Creeks were
completed early in 2022 with IP180’s averaging ~500 boe/d (94%
Liquids). In the oil window at Kaybob East and Two Creeks the
Company has extended production history from 27 wells de-risking an
inventory of 290 gross future locations. The wells have
consistently supported the Company’s type curve expectations with
IP365’s averaging ~550 boe/d per well, ~85% Liquids (latest 12
wells since 2020), demonstrating the significant potential of the
asset.
The Light Oil land position has no near‐term
expiries and is ready for future development with ~850 gross
Montney and Duvernay locations.
Light Oil operations were temporarily affected
by the Alberta wildfires. As a precautionary measure Athabasca
shut-in two of its facilities last weekend which are currently
resuming operations with no damage to well sites or infrastructure.
The Company estimates ~300 boe/d of current downtime and
anticipates minimal impact to its annual corporate production
guidance.
Business Environment &
Outlook
Global oil benchmarks have been supported by
improving demand and structural supply deficits. The war in Ukraine
has amplified the emphasis on energy security and sanctions
continue to alter energy flows across the globe. Athabasca
maintains a constructive outlook on oil prices supported by years
of industry underinvestment and demand trends moving higher led by
China emerging from COVID restrictions.
Canadian WCS heavy differentials temporarily
widened through the latter half of 2022 and early in 2023 as a
result of unprecedented US Strategic Petroleum Reserve (“SPR”)
heavy barrel releases, TC Energy’s Keystone pipeline leak in
December 2022, the war in Ukraine impacting global heavy crude oil
flows and significant unplanned US refinery outages. Pricing has
significantly improved as these transitory headwinds have eased.
Differentials are currently trading at ~US$15 compared with an
average of US$24.77 in the first quarter of 2023. The supply-demand
outlook for heavy barrels is expected to be supported by additional
OPEC+ production cuts, the start-up of the Trans Mountain pipeline
expansion (590,000 bbl/d) and the start-up of new global heavy oil
refining capacity. These factors are expected to strengthen WCS
prices into the back half of 2023 and 2024.
ESG Annual Report
Athabasca is proud to publish its third ESG
report, aligning to leading ESG standards and frameworks including
Global Reporting Initiative (“GRI”), Sustainability Accounting
Standards Board (“SASB”) and Task Force for Climate Disclosure
(“TCFD”) guidelines. The report is available on the Company’s
website (https://www.atha.com/esg.html) and SEDAR
(https://www.sedar.com).
The Company is on track to achieve its stated
target of a 30% reduction in emissions intensity by 2025. Athabasca
has also partnered with Entropy Inc. to implement carbon capture
and storage (“CCS”) at Leismer, using Entropy’s proprietary CCS
technology. This project is expected to be sanctioned once
government fiscal and regulatory policy for CCS projects are fully
in place.
The Company’s safety culture is deeply embedded
and total recordable injury frequency (TRIF) averaged 0.08 in 2022,
well below our target of 0.5 and building on our excellent safety
record. The ESG strategy and performance is reviewed, considered
and fully integrated at the Board level.
Annual General MeetingAthabasca
will be hosting a virtual Annual General Meeting (“Meeting”) on
Thursday, May 11, 2023 at 9:00 am (MT). Ms. Marnie Smith will stand
for election as a new independent director. Ms. Smith is a Managing
Director at Russell Reynolds Associates, a global organizational
consulting firm, where she leads the Western Canadian team and
Canadian energy platform. Prior thereto, she served as a Senior
Client Partner with Korn Ferry and as Managing Director & Head
of Canadian Energy at Macquarie Group. Mr. Thomas Ebbern is
retiring from the Board after approximately five years of service
and valuable contributions as a member of the Compensation &
Governance and Audit Committees. The Board would like to thank Mr.
Ebbern for his longstanding commitment to the Company and its
shareholders. Shareholders and guests can listen to the Meeting via
live webcast with details available at:
https://www.atha.com/investors/presentation-events.html
About Athabasca Oil
CorporationAthabasca 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”, “project”, “continue”, “maintain”,
“estimate”, “expect”, “will”, “target”, “forecast”, “could”,
“intend”, “potential”, “guidance”, “outlook” and similar
expressions suggesting future outcome 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. In particular, this News Release
contains forward-looking information pertaining to, but not limited
to, the following: our strategic plans; future debt levels and
repayment plans; the allocation of future capital; timing and
quantum for shareholder returns including share buybacks; the terms
of our NCIB program; our drilling plans in Leismer; Leismer ramp-up
to expected production rates; timing of Leismer’s pre-payout
royalty status; applicability of tax pools and the timing of tax
payments; expected operating results at Hangingstone; Adjusted
Funds Flow and Free Cash Flow in 2023 to 2025; type well economic
metrics; forecasted daily production and the composition of
production; our plans to release an ESG update; the achievement of
a 30% reduction in emissions intensity by 2025; the timing and
implementation of our CCS project; our outlook in respect of the
Corporation’s business environment, including in respect of the
Trans Mountain pipeline expansion and new global heavy oil refining
capacity; and other matters.
In addition, information and statements in this
News Release relating to "Reserves" and “Resources” are deemed to
be forward-looking information, as they involve the implied
assessment, based on certain estimates and assumptions, that the
reserves and resources 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
and Resources 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 Annual Information
Form (“AIF”) dated March 1, 2023 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; climate change
and carbon pricing risk; statutes and regulations regarding the
environment; regulatory environment and changes in applicable law;
gathering and processing facilities, pipeline systems and rail;
reputation and public perception of the oil and gas sector;
environment, social and governance goals; political uncertainty;
state of capital markets; ability to finance capital requirements;
access to capital and insurance; abandonment and reclamation costs;
continued impact of the COVID-19 pandemic; changing demand for oil
and natural gas products; anticipated benefits of acquisitions and
dispositions; royalty regimes; foreign exchange rates and interest
rates; reserves; hedging; operational dependence; operating costs;
project risks; supply chain disruption; labour supply, 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; limitations of 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,
including level of indebtedness, restrictions in our debt
instruments, additional indebtedness and issuance of additional
securities. Readers are cautioned that the foregoing list of
factors is not exhaustive. Unpredictable or unknown factors not
discussed in this News Release could also have adverse effects on
forward-looking statements. Although the Company believes that the
expectations conveyed by the forward-looking information are
reasonable based on information available to it on the date such
forward-looking information are made, no assurances can be given as
to future results, levels of activity and achievements. All
subsequent forward-looking information, whether written or oral,
attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by these cautionary
statements.
Also included in this News Release are estimates
of Athabasca's 2023 and 2023-25 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 outlook and
forward-looking information 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 outlook and/or
forward-looking information, 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 herein
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 700 gross 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. The 150 gross Montney drilling
locations referenced include: 48 proved undeveloped locations and
50 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, 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", “Adjusted Funds Flow
per Share”, “Free Cash Flow”, "Light Oil Operating Income", "Light
Oil Operating Netback", "Thermal Oil Operating Income", "Thermal
Oil Operating Netback", “Consolidated Operating Income",
"Consolidated Operating Netback", "Consolidated Operating Income
Net of Realized Hedging", "Consolidated Operating Netback Net of
Realized Hedging", “Cash Transportation & Marketing Expenses”,
“Excess 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 or ratios. 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 measure. The Leismer and
Hangingstone operating results are a supplementary financial
measure that when aggregated, combine to the Thermal Oil segment
results and the Greater Placid and Greater Kaybob operating results
are a supplementary financial measure that when aggregated, combine
to the Light Oil segment results.
Adjusted Funds Flow, Adjusted Funds Flow Per
Share and Free Cash Flow
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 per share is a non-GAAP financial ratio
calculated as Adjusted Funds Flow divided by the applicable number
of weighted average shares outstanding. Adjusted Funds Flow and
Free Cash Flow are calculated as follows:
|
|
Three months endedMarch 31, |
|
($ Thousands) |
|
2023 |
|
2022 |
|
Cash flow from operating activities |
|
$ |
20,537 |
|
$ |
59,862 |
|
Changes in non-cash working capital |
|
|
(18,030 |
) |
|
14,353 |
|
Settlement of provisions |
|
|
674 |
|
|
546 |
|
Long-term deposit |
|
|
(12,577 |
) |
|
— |
|
ADJUSTED FUNDS FLOW |
|
|
(9,396 |
) |
|
74,761 |
|
Capital expenditures |
|
|
(26,362 |
) |
|
(30,929 |
) |
FREE CASH FLOW |
|
$ |
(35,758 |
) |
$ |
43,832 |
|
Light Oil Operating Income and Operating
Netback
The non-GAAP measure Light Oil Operating Income
in this News Release is calculated by subtracting the Light Oil
Segments royalties, operating expenses and transportation &
marketing expenses from petroleum and natural gas sales which is
the most directly comparable GAAP measure. The Light Oil Operating
Netback per boe is a non-GAAP financial ratio calculated by
dividing the Light Oil Operating Income by the Light Oil
production. The Light Oil Operating Income and the Light Oil
Operating Netback measures allow management and others to evaluate
the production results from the Company’s Light Oil assets.
The Light Oil Operating Income is calculated
using the Light Oil Segments GAAP results, as follows:
|
|
Three months endedMarch 31, |
|
($ Thousands) |
|
2023 |
|
2022 |
|
Petroleum and natural gas sales |
|
$ |
29,889 |
|
$ |
45,108 |
|
Royalties |
|
|
(5,556 |
) |
|
(5,869 |
) |
Operating expenses |
|
|
(6,929 |
) |
|
(6,979 |
) |
Transportation and marketing |
|
|
(2,366 |
) |
|
(2,457 |
) |
LIGHT OIL OPERATING INCOME |
|
$ |
15,038 |
|
$ |
29,803 |
|
Thermal Oil Operating Income and Operating Netback
The non-GAAP measure Thermal Oil Operating
Income in this News Release is calculated by subtracting the
Thermal Oil segments cost of diluent blending, royalties, operating
expenses and cash transportation & marketing expenses from
heavy oil (blended bitumen) and midstream sales which is the most
directly comparable GAAP measure. The Thermal Oil Operating Netback
per boe is a non-GAAP financial ratio calculated by dividing the
respective projects Operating Income by its respective bitumen
sales volumes. The Thermal Oil Operating Income and the Thermal Oil
Operating Netback measures allow management and others to evaluate
the production results from the Company’s Thermal Oil assets. The
Thermal Oil Operating Income is calculated using the Thermal Oil
Segments GAAP results, as follows:
|
|
Three months endedMarch 31, |
|
($ Thousands, unless otherwise noted) |
|
2023 |
|
2022 |
|
Heavy oil (blended bitumen) and midstream sales |
|
$ |
269,102 |
|
$ |
360,281 |
|
Cost of diluent |
|
|
(148,933 |
) |
|
(139,911 |
) |
Total bitumen and midstream sales |
|
|
120,169 |
|
|
220,370 |
|
Royalties |
|
|
(6,613 |
) |
|
(32,496 |
) |
Operating expenses - non-energy |
|
|
(22,940 |
) |
|
(20,315 |
) |
Operating expenses - energy |
|
|
(24,829 |
) |
|
(25,181 |
) |
Transportation and marketing(1) |
|
|
(24,290 |
) |
|
(21,541 |
) |
THERMAL OIL OPERATING INCOME (LOSS) |
|
$ |
41,497 |
|
$ |
120,837 |
|
(1) Cash transportation and marketing
excludes non-cash costs of $0.6 million for the three months ended
March 31, 2023 (three months ended March 31, 2022 - $0.6
million).
Consolidated Operating Income and Consolidated
Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Consolidated Operating
Income including or excluding realized hedging in this News Release
are calculated by adding or subtracting realized gains (losses) on
commodity risk management contracts (as applicable), royalties, the
cost of diluent blending, operating expenses and cash
transportation & marketing expenses from petroleum, natural gas
and midstream sales which is the most directly comparable GAAP
measure. The Consolidated Operating Netbacks including or excluding
realized hedging per boe are non-GAAP ratios calculated by dividing
Consolidated Operating Income including or excluding hedging by the
total sales volumes and are presented on a per boe basis. The
Consolidated Operating Income and Consolidated Operating Netbacks
including or excluding realized hedging measures allow management
and others to evaluate the production results from the Company’s
Light Oil and Thermal Oil assets combined together including the
impact of realized commodity risk management gains or losses (as
applicable).
|
|
Three months endedMarch 31, |
|
($ Thousands, unless otherwise noted) |
|
2023 |
|
2022 |
|
Petroleum, natural gas and midstream sales(1) |
|
$ |
298,991 |
|
$ |
405,389 |
|
Royalties |
|
|
(12,169 |
) |
|
(38,365 |
) |
Cost of diluent(1) |
|
|
(148,933 |
) |
|
(139,911 |
) |
Operating expenses |
|
|
(54,698 |
) |
|
(52,475 |
) |
Transportation and marketing(2) |
|
|
(26,656 |
) |
|
(23,998 |
) |
Operating Income (Loss) |
|
|
56,535 |
|
|
150,640 |
|
Realized gain (loss) on commodity risk management contracts |
|
|
(22,055 |
) |
|
(47,646 |
) |
OPERATING INCOME (LOSS) NET OF REALIZED HEDGING |
|
$ |
34,480 |
|
$ |
102,994 |
|
(1) Non-GAAP measure includes intercompany
NGLs (i.e. condensate) sold by the Light Oil segment to the Thermal
Oil segment for use as diluent that is eliminated on
consolidation. (2) Transportation and marketing excludes
non-cash costs of $0.6 million for the three months ended March 31,
2023 (three months ended March 31, 2022 - $0.6 million).
Cash Transportation & Marketing Expenses
The Cash Transportation & Marketing Expense
financial measure contained in this News Release is calculated by
subtracting the non-cash Transportation & Marketing Expense as
reported in the Consolidated Statement of Cash Flows from the
Transportation & Marketing Expense as reported in the
Consolidated Statement of Income (Loss) and is considered to be a
non-GAAP financial measure.
Excess Cash Flow and Sustaining Capital
The Excess 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 Cash Flow measure is
calculated by Adjusted Funds Flow less Sustaining Capital.
Liquidity
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
|
|
|
Three months endedMarch 31, |
Production |
|
|
2023 |
|
2022 |
Greater Placid: |
|
|
|
|
|
Condensate NGLs |
|
bbl/d |
|
814 |
|
|
1,100 |
Other NGLs |
|
bbl/d |
|
403 |
|
|
436 |
Natural gas(1) |
|
mcf/d |
|
9,738 |
|
|
12,168 |
Total Greater Placid |
|
boe/d |
|
2,840 |
|
|
3,565 |
|
|
|
|
|
|
Greater Kaybob: |
|
|
|
|
|
Oil(2) |
|
bbl/d |
|
1,576 |
|
|
1,971 |
Other NGLs |
|
bbl/d |
|
318 |
|
|
324 |
Natural gas(1) |
|
mcf/d |
|
4,620 |
|
|
5,463 |
Total Greater Kaybob |
|
boe/d |
|
2,664 |
|
|
3,205 |
|
|
|
|
|
|
Light Oil: |
|
|
|
|
|
Oil(2) |
|
bbl/d |
|
1,576 |
|
|
1,971 |
Condensate NGLs |
|
bbl/d |
|
814 |
|
|
1,100 |
Oil and condensate NGLs |
|
bbl/d |
|
2,390 |
|
|
3,071 |
Other NGLs |
|
bbl/d |
|
721 |
|
|
760 |
Natural gas(1) |
|
mcf/d |
|
14,358 |
|
|
17,631 |
Total Light Oil division |
|
boe/d |
|
5,504 |
|
|
6,770 |
Total Thermal Oil division bitumen |
|
bbl/d |
|
29,179 |
|
|
27,909 |
Total Company production |
|
boe/d |
|
34,683 |
|
|
34,679 |
(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 34,500 –
36,000 boe/d for 2023. Athabasca expects that ~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.
This News Release makes reference to Athabasca's
three well results in Two Creeks that have seen average
productivity of ~500 boe/d IP180s (94% Liquids), which is comprised
of ~92% tight oil, ~6% shale gas and ~2% NGLs. Additionally, the
latest 12 wells at Two Creeks have seen average productivity of
~550 boe/d IP365s (85% Liquids), which is comprised of ~80% tight
oil, ~15% shale gas and ~5% NGLs.
Liquids is defined as bitumen, light crude oil,
medium crude oil and natural gas liquids.
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