Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”)
is pleased to report its audited 2023 year-end results and
reserves. Athabasca provides investors unique positioning to top
tier liquids weighted assets (Thermal Oil and Duvernay) with a
capital allocation framework aimed at maximizing cash flow per
share growth and returning capital to shareholders.
Year-end 2023 Corporate
Results
-
Production: Average production of 34,490 boe/d
(95% Liquids), achieving annual guidance of 34,500 boe/d, after
adjusting for the sale of non-core Light Oil assets.
-
Cash Flow: Adjusted Funds Flow of $295 million
& Cash Flow from Operating Activities of $306 million.
-
Capital Program: $140 million, below annual
guidance of $145 million, with $99 million invested at its
cornerstone Leismer asset focused on advancing the expansion
project with growth expected to 28,000 bbl/d by mid-year 2024.
-
Free Cash Flow: $155 million of Free Cash Flow
supporting return of capital commitments.
-
Financial Strength: Net Cash position of $131
million; Liquidity of $429 million ($343 million of cash).
Return of Capital Strategy
-
2023 Share Buybacks: $159 million of share
repurchases between April and December (44 million shares at an
average price of $3.58/share); returned 94% of Excess Cash Flow to
shareholders through share buyback program, well in excess of
Athabasca’s 75% commitment in 2023.
-
2024 Return of Capital Commitment:
Athabasca is planning to allocate of 100% of Free Cash Flow to
shareholders through continued share buybacks in 2024. Year to date
the Company has completed ~$24 million of share repurchases (5.4
million shares at an average price of $4.38/share). The Company
expects to fully execute its Normal Course Issuer Bid (“NCIB”)
approval of 57,967,098 common shares for the 12 month period ending
March 15, 2024. The Company plans to renew its NCIB with the
Toronto Stock Exchange for another 12 month period.
2023 Year-end Reserves
-
Differentiated Long-life Reserves: Athabasca holds
1.2 billion barrels of Proved Plus Probable reserves and ~1 billion
barrels of Contingent Resource (Best Estimate). This represents
$5.3 billion2 NPV10 of Proved Plus Probable reserves ($9.23 per
share), an increase of 14% from 2023, and includes $1.8 billion2 of
Proved Developed Producing reserves ($3.09 per share) and $3.1
billion2 of Total Proved reserves ($5.44 per share). Athabasca’s
Proved plus Probable reserve life is ~100 years.
-
Deep Inventory of Development Projects: Leismer
and Corner have regulatory approval for up to 80,000 bbl/d and
benefit from a pre-payout Crown royalty structure, with royalty
rates between 5 – 9%. The Company also has exposure to an estimated
500 gross Kaybob Duvernay locations through its subsidiary,
Duvernay Energy Corporation.
2024 Guidance
-
Thermal Oil: Athabasca’s Thermal Oil division
underpins the Company’s strong Free Cash Flow outlook, with an
unchanged $135 million capital budget and production guidance of
32,000 – 33,000 bbl/d. The facility expansion at Leismer is on
track to be commissioned during H1 2024 with production expected to
reach ~28,000 bbl/d mid‐year following the tie‐in of behind pipe
wells. Two 1,400 meter well pairs are planned to be drilled at
Hangingstone in H2 2024 with the objective of ensuring the project
continues to deliver meaningful cash flow to the Company.
-
Duvernay Energy Corporation: The 2024 capital
program of ~$82 million (gross) includes the drilling of 12 gross
(7.1 net) Duvernay wells. Capital will be funded through cash
balances and cash flow from operations. 2024 production guidance is
~3,000 boe/d (75% Liquids). Development plans are expected to drive
strong production momentum into 2025 with estimated production of
~6,000 boe/d.
-
Managing for Free Cash Flow: Excluding its 70%
equity interest in Duvernay Energy, Athabasca forecasts Adjusted
Funds Flow of ~$460 million in 2024 (US$80/bbl WTI & US$15/bbl
WCS heavy differential). Athabasca’s 2024 Free Cash Flow forecast
is ~$325 million. The Company expects to generate >$1 billion in
Free Cash Flow during the three-year timeframe of 2024-26. As a
result of its $2.8 billion in corporate tax pools, Athabasca is not
forecasted to pay cash taxes for approximately seven years.
-
Exposure to Improving Alberta Heavy Oil Pricing:
Athabasca anticipates tightening of the WCS heavy differentials
from current levels as the Trans Mountain Expansion pipeline
(590,000 bbl/d) commences operations in Q2 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.
-
Environmental, Social and Governance “ESG”
Disclosure: The Company will release its annual ESG update
in May of 2024. In 2023, the Company maintained a strong safety
record with a 0.31 Total Recordable Injury Frequency and no
reportable hydrocarbon spills.
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, 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.2 Net present value of
future net revenue before tax at a 10% discount rate (NPV 10 before
tax) for 2024 is based on an average of McDaniel, Sproule and GLJ
pricing as at January 1, 2024.
Thermal Oil – Operations
Update
Bitumen production for Q4 2023 and 2023 averaged
31,059 bbl/d and 30,246 bbl/d, respectively. The Thermal Oil
division generated Operating Income of $92.2 million ($30.78/bbl)
and $370.7 million ($32.93/bbl) during these periods. Capital
expenditures for Q4 2023 and 2023 were $29.3 million and $113.1
million, respectively.
Leismer
Bitumen production for Q4 2023 and 2023 averaged
23,764 bbl/d (up 9% year over year) and 22,497 bbl/d (up 12% year
over year), respectively. Current production is in excess of 24,000
bbl/d (February 2024). The asset realized continued improvement in
the Steam Oil Ratio (“SOR”) from expansion of the non-condensable
gas co-injection and production additions from new wells resulting
in an annual average SOR of 3.1 for 2023.
In 2023, five additional new well pairs at Pad
L8 were brought on production mid-year. These well pairs have a
combined production rate of ~5,000 bbl/d and are expected to
maintain a stable production profile for approximately five years.
The Company also completed drilling the final four well pairs at
Pad L8S with steaming currently underway and recently placed four
infill wells on production at Pad L7.
The facility expansion is on track to be
commissioned in H1 and production is expected to reach ~28,000
bbl/d mid-year once all new wells are on production.
Leismer has a significant unrecovered capital
balance of $1.4 billion which ensures a low Crown royalty framework
as the asset is forecasted to remain pre-payout until 20271.
Hangingstone
Bitumen production for Q4 2023 and 2023 averaged
7,295 bbl/d and 7,749 bbl/d, respectively. Non-condensable gas
co-injection has aided in pressure support and reduced energy
usage. Hangingstone’s steam oil ratio averaged 3.6 for 2023.
Two ~1,400 meter well pairs will spud in Q3
2024. Modern well design with extended reach laterals is expected
to drive competitive project capital efficiencies of ~$15,000/bbl/d
and will leverage off available infrastructure capacity. These
sustaining well pairs will support base production in 2025 and
beyond with the objective of ensuring Hangingstone continues to
deliver meaningful cash flow contributions to the Company.
Duvernay Energy Corporation – Operations
Update
Production from Athabasca’s Light Oil Division
averaged 2,068 boe/d (71% Liquids) and 4,244 boe/d (58% Liquids) in
Q4 2023 and 2023, respectively. These assets generated Operating
Income of $4.8 million ($25.02/boe) and $46.3 million ($29.89/boe)
during these periods. Capital expenditures were $9.4 million and
$20.9 million in Q4 2023 and 2023, respectively.
In September 2023, Athabasca closed the sale of
~3,000 boe/d of non-core Placid, Saxon and Simonette assets for
$160 million (before closing adjustments). In December, the Company
announced the creation of Duvernay Energy Corporation. Duvernay
Energy is a privately held subsidiary of Athabasca, combining
Athabasca and Cenovus assets. Athabasca owns 70% equity interest
with Cenovus owning the remaining 30% equity interest. Duvernay
Energy is managed by Athabasca through a management and operating
services agreement.
Duvernay Energy owns ~46,000 acres of 100%
working interest operated lands contiguous to its existing Duvernay
joint venture assets. In total, Duvernay Energy has exposure to
~200,000 gross contiguous acres in the liquids rich and oil windows
with a management estimate of ~500 gross future well locations.
Duvernay’s initial capitalization includes ~$40 million cash and a
$50 million undrawn credit facility. The plan is to allocate 100%
of Adjusted Funds Flow from Duvernay Energy to drive near-term
growth potential.
Duvernay Energy recently rig released a two well
pad (100% working interest) at 03-18-64-17W5 with an average
horizontal length of ~4,150 meters per well. Completion operations
are planned for Q1 2024 with on-stream timing at the end of Q2
2024. A three well pad (30% working interest) is currently drilling
with completions and tie-in to follow in Q2 2024.
Duvernay Energy’s assets are positioned in the
prolific Kaybob Duvernay resource play, primarily in the volatile
oil window, and are serviced by extensive operated infrastructure.
Current production is ~2,000 boe/d (~75% Liquids). Assuming a
constructive commodity price outlook, Duvernay Energy has
self-funded growth potential to ~25,000 boe/d (75% Liquids) by the
late 2020’s.
Financial and Operational Highlights
|
|
Three months endedDecember
31, |
|
Year endedDecember 31, |
|
($ Thousands, unless otherwise noted) |
2023 |
|
|
2022 |
|
|
2023 |
|
|
2022 |
|
|
CONSOLIDATED |
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
33,127 |
|
|
|
35,850 |
|
|
|
34,490 |
|
|
|
35,262 |
|
|
Petroleum, natural gas and midstream sales |
$ |
315,929 |
|
|
$ |
282,524 |
|
|
$ |
1,268,525 |
|
|
$ |
1,504,685 |
|
|
Operating Income (Loss)(1) |
$ |
96,960 |
|
|
$ |
70,319 |
|
|
$ |
417,023 |
|
|
$ |
530,295 |
|
|
Operating Income (Loss) Net of Realized Hedging(1)(2) |
$ |
91,443 |
|
|
$ |
62,131 |
|
|
$ |
381,088 |
|
|
$ |
378,695 |
|
|
Operating Netback ($/boe)(1) |
$ |
30.44 |
|
|
$ |
23.17 |
|
|
$ |
32.57 |
|
|
$ |
41.65 |
|
|
Operating Netback Net of Realized Hedging ($/boe)(1)(2) |
$ |
28.71 |
|
|
$ |
20.47 |
|
|
$ |
29.76 |
|
|
$ |
29.74 |
|
|
Capital expenditures |
$ |
38,752 |
|
|
$ |
13,029 |
|
|
$ |
139,832 |
|
|
$ |
147,449 |
|
|
THERMAL OIL DIVISION |
|
|
|
|
|
|
|
|
Bitumen production (bbl/d)(1) |
|
31,059 |
|
|
|
30,210 |
|
|
|
30,246 |
|
|
|
28,989 |
|
|
Petroleum, natural gas and midstream sales |
$ |
309,078 |
|
|
$ |
255,749 |
|
|
$ |
1,204,245 |
|
|
$ |
1,382,627 |
|
|
Operating Income (Loss)(1) |
$ |
92,199 |
|
|
$ |
50,691 |
|
|
$ |
370,732 |
|
|
$ |
420,511 |
|
|
Operating Netback ($/bbl)(1) |
$ |
30.78 |
|
|
$ |
20.15 |
|
|
$ |
32.93 |
|
|
$ |
40.26 |
|
|
Capital expenditures |
$ |
29,260 |
|
|
$ |
10,895 |
|
|
$ |
113,077 |
|
|
$ |
110,582 |
|
|
LIGHT OIL DIVISION |
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
2,068 |
|
|
|
5,640 |
|
|
|
4,244 |
|
|
|
6,273 |
|
|
Percentage Liquids (%)(1) |
71 |
% |
|
56 |
% |
|
58 |
% |
|
57 |
% |
|
Petroleum, natural gas and midstream sales |
$ |
12,659 |
|
|
$ |
36,356 |
|
|
$ |
91,062 |
|
|
$ |
175,279 |
|
|
Operating Income (Loss)(1) |
$ |
4,761 |
|
|
$ |
19,628 |
|
|
$ |
46,291 |
|
|
$ |
109,784 |
|
|
Operating Netback ($/boe)(1) |
$ |
25.02 |
|
|
$ |
37.83 |
|
|
$ |
29.89 |
|
|
$ |
47.95 |
|
|
Capital expenditures |
$ |
9,381 |
|
|
$ |
1,594 |
|
|
$ |
20,857 |
|
|
$ |
11,662 |
|
|
CASH FLOW AND FUNDS FLOW |
|
|
|
|
|
|
|
|
Cash flow from operating activities |
$ |
103,196 |
|
|
$ |
69,368 |
|
|
$ |
305,526 |
|
|
$ |
315,618 |
|
|
per share - basic |
$ |
0.18 |
|
|
$ |
0.12 |
|
|
$ |
0.52 |
|
|
$ |
0.56 |
|
|
Adjusted Funds Flow(1) |
$ |
81,830 |
|
|
$ |
46,074 |
|
|
$ |
295,236 |
|
|
$ |
308,004 |
|
|
per share - basic |
$ |
0.14 |
|
|
$ |
0.08 |
|
|
$ |
0.51 |
|
|
$ |
0.54 |
|
|
Free Cash Flow(1) |
$ |
43,078 |
|
|
$ |
33,045 |
|
|
$ |
155,404 |
|
|
$ |
160,555 |
|
|
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) |
|
|
|
|
|
|
|
|
Net income (loss) and comprehensive income (loss) |
$ |
27,506 |
|
|
$ |
489,654 |
|
|
$ |
(51,220 |
|
) |
$ |
572,271 |
|
|
per share - basic |
$ |
0.05 |
|
|
$ |
0.83 |
|
|
$ |
(0.09 |
|
) |
$ |
1.01 |
|
|
per share - diluted(3) |
$ |
0.03 |
|
|
$ |
0.81 |
|
|
$ |
(0.09 |
|
) |
$ |
0.98 |
|
|
COMMON SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
574,412,564 |
|
|
|
586,468,394 |
|
|
|
583,757,575 |
|
|
|
568,035,589 |
|
|
Weighted average shares outstanding - diluted |
|
588,498,448 |
|
|
|
604,911,603 |
|
|
|
583,757,575 |
|
|
|
586,913,328 |
|
|
|
|
|
December 31, |
|
December 31, |
|
|
As at ($ Thousands) |
|
|
2023 |
|
2022 |
|
|
LIQUIDITY AND BALANCE SHEET |
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
$ |
343,309 |
|
$ |
197,525 |
|
|
Available credit facilities(4) |
|
|
$ |
85,488 |
|
$ |
87,838 |
|
|
Face value of term debt(5) |
|
|
$ |
207,648 |
|
$ |
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 $5.5 million and $35.9 million
for the three months and year ended December 31, 2023 (the three
months and year ended December 31, 2022 – loss of $8.2 million and
$151.6 million).(3) In the calculation of diluted earnings per
share for the three months ended December 31, 2023 earnings were
reduced by $11.3 million to account for the impact to net income
had the outstanding warrants been converted to equity. (4) Includes
available credit under Athabasca's Credit Facility and Unsecured
Letter of Credit Facility.(5) The face value of the term debt at
December 31, 2023 was US$157 million (December 31, 2022 – US$175
million) translated into Canadian dollars at the December 31, 2023
exchange rate of US$1.00 = C$1.3226 (December 31, 2022 –
C$1.3544).
Differentiated Long-life
Reserves
Athabasca’s independent reserves evaluator,
McDaniel & Associates Consultants Ltd. (“McDaniel”), prepared
the year-end reserves evaluation effective December 31, 2023.
The Company’s Proved plus Probable (“2P”)
reserves base is 1.2 billion boe, with Leismer/Corner underpinning
an additional ~1 billion barrels of low risk, top tier, long
reserve life contingent resources (best estimate). Light Oil
reserves saw a decrease with the disposition of Placid and Saxon
assets in 2023. The Light Oil reserve report includes 113 future
booked development locations relative to a deep inventory of ~500
gross estimated development locations. Overall reserve value (NPV
10 before tax) of 2P reserves increased 14% year over year,
including an increase of 26% from Athabasca’s Thermal Oil assets.
Athabasca’s Proved plus Probable reserve life index is
approximately 100 years.
For additional information regarding Athabasca’s
reserves and resources estimates, please see “Independent Reserve
and Resource Evaluations” in the Company’s 2023 Annual Information
Form which is available on the Company’s website or on SEDAR
www.sedarplus.ca.
|
|
Light Oil |
Thermal Oil |
Corporate |
|
|
|
2022 |
|
2023 |
|
2022 |
|
2023 |
|
2022 |
|
2023 |
| Reserves
(mmboe) |
|
|
|
|
|
|
|
Proved Developed Producing |
|
12 |
|
4 |
|
66 |
|
77 |
|
78 |
|
82 |
|
Total Proved |
|
29 |
|
11 |
|
403 |
|
404 |
|
433 |
|
415 |
|
Proved Plus Probable |
|
70 |
|
27 |
|
1,220 |
|
1,216 |
|
1,290 |
|
1,243 |
|
|
|
|
|
|
|
|
| NPV10 BT
($million)1 |
|
|
|
|
|
|
|
Proved Developed Producing |
$ |
191 |
$ |
58 |
$ |
1,201 |
$ |
1,713 |
$ |
1,393 |
$ |
1,771 |
|
Total Proved |
$ |
317 |
$ |
142 |
$ |
2,384 |
$ |
2,969 |
$ |
2,702 |
$ |
3,111 |
|
Proved Plus Probable |
$ |
642 |
$ |
269 |
$ |
3,985 |
$ |
5,011 |
$ |
4,627 |
$ |
5,280 |
|
|
|
|
|
|
|
1) Net present value of future net revenue before tax and at a
10% discount rate (NPV 10 before tax) for 2023 is based on an
average of McDaniel, Sproule and GLJ pricing as at January 1,
2024.
2) Numbers in the table may not add precisely
due to rounding.
About Athabasca Oil
Corporation
Athabasca Oil Corporation is a Canadian energy
company with a focused strategy on the development of thermal and
light oil assets. Situated in Alberta’s Western Canadian
Sedimentary Basin, the Company has amassed a significant land base
of extensive, high quality resources. Athabasca’s light oil assets
are held in a private subsidiary (Duvernay Energy Corporation) in
which Athabasca owns a 70% equity interest. 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”, “may”,
“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; 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 2024 to
2026; type well economic metrics; forecasted daily production and
the composition of production; the reclassification of reserves
from Proved Undeveloped to Proved Developed Producing; our plans to
release an ESG update; 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, 2023 (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 February 29, 2024 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; 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;
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; 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 and
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; water use restrictions and/or limited access to
water; relationship with Duvernay Energy Corporation; management
estimates and assumptions; third-party claims; conflicts of
interest; inflation and cost management; credit ratings; growth
management; impact of pandemics; ability of investors resident in
the United States to enforce civil remedies in Canada; and risks
related to our debt and securities. 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 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 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, 2023. 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, 2023 and based on
average pricing of McDaniel, Sproule and GLJ as of January 1,
2024.
The 500 gross Duvernay drilling locations
referenced include: 37 proved undeveloped locations and 76 probable
undeveloped locations for a total of 113 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, 2023 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 endedDecember
31, |
|
Year endedDecember 31, |
|
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
|
Cash flow from operating activities |
$ |
103,196 |
|
$ |
69,368 |
|
$ |
305,526 |
|
$ |
315,618 |
|
|
Changes in non-cash working capital |
|
(21,973 |
) |
|
(23,356 |
) |
|
525 |
|
|
(8,970 |
) |
|
Settlement of provisions |
|
607 |
|
|
62 |
|
|
1,762 |
|
|
1,356 |
|
|
Long-term deposit |
|
— |
|
|
— |
|
|
(12,577 |
) |
|
— |
|
|
ADJUSTED FUNDS FLOW |
|
81,830 |
|
|
46,074 |
|
|
295,236 |
|
|
308,004 |
|
|
Capital expenditures |
|
(38,752 |
) |
|
(13,029 |
) |
|
(139,832 |
) |
|
(147,449 |
) |
|
FREE CASH FLOW |
$ |
43,078 |
|
$ |
33,045 |
|
$ |
155,404 |
|
$ |
160,555 |
|
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
endedDecember 31, |
|
Year endedDecember 31, |
|
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
|
Petroleum and natural gas sales |
$ |
12,659 |
|
$ |
36,356 |
|
$ |
91,062 |
|
$ |
175,279 |
|
|
Royalties |
|
(2,180 |
) |
|
(6,701 |
) |
|
(12,583 |
) |
|
(25,608 |
) |
|
Operating expenses |
|
(5,009 |
) |
|
(7,791 |
) |
|
(24,997 |
) |
|
(30,689 |
) |
|
Transportation and marketing |
|
(709 |
) |
|
(2,236 |
) |
|
(7,191 |
) |
|
(9,198 |
) |
|
LIGHT OIL OPERATING INCOME |
$ |
4,761 |
|
$ |
19,628 |
|
$ |
46,291 |
|
$ |
109,784 |
|
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 endedDecember
31, |
|
Year endedDecember 31, |
|
|
($ Thousands, unless otherwise noted) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
|
Heavy oil (blended bitumen) and midstream sales |
$ |
309,078 |
|
$ |
255,749 |
|
$ |
1,204,245 |
|
$ |
1,382,627 |
|
|
Cost of diluent |
|
(137,438 |
) |
|
(128,713 |
) |
|
(518,219 |
) |
|
(548,553 |
) |
|
Total bitumen and midstream sales |
|
171,640 |
|
|
127,036 |
|
|
686,026 |
|
|
834,074 |
|
|
Royalties |
|
(15,695 |
) |
|
(13,256 |
) |
|
(60,865 |
) |
|
(133,134 |
) |
|
Operating expenses - non-energy |
|
(23,767 |
) |
|
(17,062 |
) |
|
(87,116 |
) |
|
(81,319 |
) |
|
Operating expenses - energy |
|
(17,651 |
) |
|
(25,914 |
) |
|
(81,769 |
) |
|
(114,622 |
) |
|
Transportation and marketing(1) |
|
(22,328 |
) |
|
(20,113 |
) |
|
(85,544 |
) |
|
(84,488 |
) |
|
THERMAL OIL OPERATING INCOME |
$ |
92,199 |
|
$ |
50,691 |
|
$ |
370,732 |
|
$ |
420,511 |
|
(1) Cash transportation and marketing
excludes non-cash costs of $0.6 million and $2.2 million for the
three months and year ended December 31, 2023 (three months and
year ended December 31, 2022 - $0.6 million and $2.2 million).
Consolidated Operating Income and Consolidated
Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Consolidated Operating
Income including or excluding realized hedging in this News Release
are calculated by adding or subtracting realized gains (losses) on
commodity risk management contracts (as applicable), royalties, the
cost of diluent blending, operating expenses and cash
transportation & marketing expenses from petroleum, natural gas
and midstream sales which is the most directly comparable GAAP
measure. The Consolidated Operating Netbacks including or excluding
realized hedging per boe are non-GAAP ratios calculated by dividing
Consolidated Operating Income including or excluding hedging by the
total sales volumes and are presented on a per boe basis. The
Consolidated Operating Income and Consolidated Operating Netbacks
including or excluding realized hedging measures allow management
and others to evaluate the production results from the Company’s
Light Oil and Thermal Oil assets combined together including the
impact of realized commodity risk management gains or losses (as
applicable).
|
|
Three months endedDecember
31, |
|
Year endedDecember 31, |
|
|
($ Thousands, unless otherwise noted) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
|
Petroleum, natural gas and midstream sales(1) |
$ |
321,737 |
|
$ |
292,105 |
|
$ |
1,295,307 |
|
$ |
1,557,906 |
|
|
Royalties |
|
(17,875 |
) |
|
(19,957 |
) |
|
(73,448 |
) |
|
(158,742 |
) |
|
Cost of diluent(1) |
|
(137,438 |
) |
|
(128,713 |
) |
|
(518,219 |
) |
|
(548,553 |
) |
|
Operating expenses |
|
(46,427 |
) |
|
(50,767 |
) |
|
(193,882 |
) |
|
(226,630 |
) |
|
Transportation and marketing(2) |
|
(23,037 |
) |
|
(22,349 |
) |
|
(92,735 |
) |
|
(93,686 |
) |
|
Operating Income (Loss) |
|
96,960 |
|
|
70,319 |
|
|
417,023 |
|
|
530,295 |
|
|
Realized gain (loss) on commodity risk management contracts |
|
(5,517 |
) |
|
(8,188 |
) |
|
(35,935 |
) |
|
(151,600 |
) |
|
OPERATING INCOME NET OF REALIZED HEDGING |
$ |
91,443 |
|
$ |
62,131 |
|
$ |
381,088 |
|
$ |
378,695 |
|
(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) Cash transportation and marketing
excludes non-cash costs of $0.6 million and $2.2 million for the
three months and year ended December 31, 2023 (the three months and
year ended December 31, 2022 - $0.6 million and $2.2 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.
Net Cash / Net Debt
Net 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,
excluding risk management contracts and warrant liability.
Liquidity
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
|
|
|
Three months endedDecember
31, |
|
Year endedDecember 31, |
|
|
Production |
|
2023 |
|
2022 |
|
2023 |
|
2022 |
|
|
Greater Placid: |
|
|
|
|
|
|
|
|
|
|
Condensate NGLs |
bbl/d |
|
— |
|
|
843 |
|
|
528 |
|
|
962 |
|
|
Other NGLs |
bbl/d |
|
— |
|
|
360 |
|
|
256 |
|
|
411 |
|
|
Natural gas(1) |
mcf/d |
|
— |
|
|
10,259 |
|
|
6,720 |
|
|
11,149 |
|
|
Total Greater Placid |
boe/d |
|
— |
|
|
2,913 |
|
|
1,904 |
|
|
3,232 |
|
|
|
|
|
|
|
|
|
|
|
|
| Greater Kaybob: |
|
|
|
|
|
|
|
|
|
|
Oil(2) |
bbl/d |
|
1,208 |
|
|
1,707 |
|
|
1,396 |
|
|
1,886 |
|
|
Other NGLs |
bbl/d |
|
258 |
|
|
266 |
|
|
269 |
|
|
319 |
|
|
Natural gas(1) |
mcf/d |
|
3,612 |
|
|
4,526 |
|
|
4,049 |
|
|
5,020 |
|
|
Total Greater Kaybob |
boe/d |
|
2,068 |
|
|
2,727 |
|
|
2,340 |
|
|
3,041 |
|
|
|
|
|
|
|
|
|
|
|
|
| Light Oil: |
|
|
|
|
|
|
|
|
|
|
Oil(2) |
bbl/d |
|
1,208 |
|
|
1,707 |
|
|
1,396 |
|
|
1,886 |
|
|
Condensate NGLs |
bbl/d |
|
— |
|
|
843 |
|
|
528 |
|
|
962 |
|
| Oil
and condensate NGLs |
bbl/d |
|
1,208 |
|
|
2,550 |
|
|
1,924 |
|
|
2,848 |
|
| Other NGLs |
bbl/d |
|
258 |
|
|
626 |
|
|
525 |
|
|
730 |
|
|
Natural gas(1) |
mcf/d |
|
3,612 |
|
|
14,785 |
|
|
10,769 |
|
|
16,169 |
|
|
Total Light Oil division |
boe/d |
|
2,068 |
|
|
5,640 |
|
|
4,244 |
|
|
6,273 |
|
|
Total Thermal Oil division bitumen |
bbl/d |
|
31,059 |
|
|
30,210 |
|
|
30,246 |
|
|
28,989 |
|
|
Total Company production |
boe/d |
|
33,127 |
|
|
35,850 |
|
|
34,490 |
|
|
35,262 |
|
(1) Comprised of 99% or greater of shale gas,
with the remaining being conventional natural gas.
(2) Comprised of 98% or greater of tight oil, with the
remaining being light and medium crude oil.
This News Release also makes reference to
Athabasca's forecasted average daily Thermal Oil production of
32,000 - 33,000 bbl/d for 2024. Athabasca expects that 100% of that
production will be comprised of bitumen. Duvernay Energy’s
forecasted average daily production of ~3,000 boe/d for 2024 is
expected to be comprised of approximately 66% tight oil, 24% shale
gas and 10% NGLs.
Liquids is defined as bitumen, light crude oil,
medium crude oil and natural gas liquids.
Reserve Life Index is calculated as year-end reserves divided by
Q4 2023 production.
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, 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.2 Net present value of
future net revenue before tax at a 10% discount rate (NPV 10 before
tax) for 2024 is based on an average of McDaniel, Sproule and GLJ
pricing as at January 1, 2024.
Athabasca Oil (TSX:ATH)
Historical Stock Chart
From Nov 2024 to Dec 2024
Athabasca Oil (TSX:ATH)
Historical Stock Chart
From Dec 2023 to Dec 2024
