Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”)
is pleased to report its third quarter results highlighting strong
free cash flow underpinned by operational momentum at all assets
and continued execution on its return of capital commitment through
share buybacks.
Corporate Consolidated Third Quarter
Highlights
-
Production: Average production of 38,909 boe/d
(98% Liquids), representing 8% growth year over year (16% on a per
share basis). Annual production remains on track with previously
increased 2024 guidance of 36,000 – 37,000 boe/d.
-
Cash Flow Growth: Adjusted Funds Flow of $164
million (cash flow from operating activities of $187 million) or
$0.30 per share, representing 25% growth on a per share basis year
over year. In 2024, the Company forecasts Adjusted Funds Flow of
~$555 million1, supported by increased operating scale and
constructive Canadian heavy oil pricing. Athabasca forecasts ~100%
growth in 2024 forecasted funds flow per share relative to 2022
when growth to 28,000 bbl/d at Leismer was sanctioned.
-
Differentiated Balance Sheet: Proactively
refinanced the Company’s senior secured second lien Notes with $200
million of senior unsecured notes at a 6.75% coupon with a 2029
maturity. Consolidated Net Cash position of $135 million with
Liquidity of $456 million, including $335 million in cash.
-
Resilient Producer: Competitively positioned with
Thermal Oil sustaining capital to hold production flat funded
within cash flow at ~US$50/bbl WTI1 and growth initiatives fully
funded within cash flow at ~US$60/bbl WTI1.
-
Robust Free Cash Flow: Capital flexibility and
balance sheet strength supports durable asset growth and return of
capital initiatives for shareholders, resulting in continued top
tier cash flow per share growth into the future. Athabasca expects
to generate in excess of $1 billion of Free Cash Flow at US$70/bbl
WTI1 after fully funding its growth program during the timeframe of
2024-27. The Company intends to release its 2025 capital budget in
December.
Return of Capital
-
Cumulative Return of Capital of ~$800 million.
Commencing in the Fall of 2021 a deliberate strategy prioritized
$385 million of debt reduction. Share buybacks commenced in 2023
and have totaled $415 million to date.
-
2024 Return of Capital Commitment: Athabasca
(Thermal Oil) is allocating 100% of Free Cash Flow to share
buybacks in 2024. Year to date the Company has completed $257
million in share buybacks and forecasts 2024 Free Cash Flow of
~$315 million1.
-
Focus on Per Share Metrics: A steadfast commitment
to return of capital has driven an ~104 million share reduction
(~16%) in the Company’s fully diluted share count since March 31,
2023.
Athabasca (Thermal Oil) Third Quarter
Highlights
-
Production: ~34,900 bbl/d supported by growth at
Leismer (record quarter at ~27,500 bbl/d) and stability at
Hangingstone (~7,400 bbl/d).
-
Cash Flow: Adjusted Funds Flow of $150 million
with an Operating Netback of $49.68/bbl.
-
Capital Program: $44 million of capital focused on
sustaining operations at Leismer and Hangingstone. 2024 capital
program forecast of ~$195 million including the commencement of
progressive growth to 40,000 bbl/d at Leismer. The Company is
currently drilling four new well pairs and six redrill
opportunities at Leismer with production expected in early 2025.
Two new well pairs at Hangingstone (1,400 meter laterals) will
begin steaming in late November with production expected in early
2025.
-
Free Cash Flow: $106 million of Free Cash Flow
supporting return of capital commitments.
Duvernay Energy Corporation (“DEC”)
Third Quarter Highlights
-
Production: ~4,100 boe/d (77% Liquids) supported
by production from two new pads placed on production in the spring.
Results continue to support management’s type curve expectations
with restricted IP180s/well averaging ~840 boe/d (82% Liquids) on
the 2-well 100% working interest (“WI”) pad and IP120s/well
averaging ~835 boe/d (85% Liquids) on the 3-well 30% WI pad.
-
Cash Flow: Adjusted Funds Flow of $14 million with
an Operating Netback of $44.20/boe.
-
Capital Program: $6 million focused on commencing
a 3-well 100% WI pad at 04-18-64-16W5 which spud in early
September. The first two wells have been cased with lateral lengths
averaging ~4,000 meters per well. The pad is expected to be
completed in 2025. The 2024 capital program forecast is ~$75
million, fully funded within cash flow and cash on hand in
DEC.
Corporate Consolidated
Strategy
-
Value Creation: The Company’s Thermal Oil division
provides a differentiated liquids weighted growth platform
supported by financial resiliency to execute on return of capital
initiatives. Athabasca’s subsidiary company, Duvernay Energy
Corporation, is designed to enhance value for Athabasca’s
shareholders by providing a clear path for self-funded production
and cash flow growth in the Kaybob Duvernay resource play.
Athabasca (Thermal Oil) and Duvernay Energy have independent
strategies and capital allocation frameworks.
-
Consolidated Free Cash Flow Growth: Athabasca’s
capital allocation framework is designed to unlock shareholder
value by prioritizing multi‐year cash flow per share growth. In
2024, Athabasca forecasts Corporate Consolidated Adjusted Funds
Flow of ~$555 million or ~$1 per share, representing ~100% per
share growth over 2022 when the Company sanctioned growth to 28,000
bbl/d at Leismer. The Company’s outlook targets ~20% net Adjusted
Funds Flow per share compound annual growth rate during the
three-year time to 20272.
Athabasca (Thermal Oil)
Strategy
-
Large Resource Base: Athabasca’s top-tier assets
underpin a strong Free Cash Flow outlook with low sustaining
capital requirements. The long life, low decline asset base
includes ~1.2 billion barrels of Proved plus Probable reserves and
~1 billion barrels of Contingent Resource.
-
Strong Financial Position: Prudent balance sheet
management is a core tenet of Athabasca’s strategy. During the
quarter, Athabasca issued $200 million 6.75% senior unsecured notes
due in 2029 and redeemed US$157 million 9.75% senior secured second
lien notes due in 2026. The Company proactively refinanced its debt
on attractive terms and maintains strategic flexibility with a Net
Cash position.
-
Capital Efficient Leismer Expansions: As
previously announced, the Company has sanctioned expansion plans at
Leismer for growth to 40,000 bbl/d. This will be completed
utilizing a progressive build strategy that adds incremental
production in the coming years with the full capacity to be
achieved in 2028. The capital for this project is estimated at $300
million for a capital efficiency of ~$25,000/bbl/d. The Company can
maintain 40,000 bbl/d for approximately fifty years (Proved plus
Probable Reserves).
-
Sustaining Hangingstone: Steaming on two new
sustaining well pairs will occur later this year with first
production expected in early 2025. These wells will support base
production with the objective of ensuring Hangingstone continues to
deliver meaningful cash flow contributions to the Company and
maintaining competitive netbacks ($48.39/bbl Q3 2024 Operating
Netback).
-
Corner – Future Optionality: The Company’s Corner
asset is a large de-risked oil sands asset adjacent to Leismer with
351 million barrels of Proved plus Probable reserves and 520
million barrels Contingent Resource (Best Estimate Unrisked). There
are over 300 delineation wells and ~80% seismic coverage, with
reservoir qualities similar or better than Leismer. The asset has a
40,000 bbl/d regulatory approval for development with the existing
pipeline corridor passing through the Corner lease. The Company has
updated its development plans and is finalizing facility cost
estimates. Athabasca intends to explore external funding options
and does not plan to fund an expansion utilizing existing cash flow
or balance sheet resources.
-
Exposure to Improving Heavy Oil Pricing: With the
start-up of the Trans Mountain pipeline expansion (590,000 bbl/d)
in early May, spare pipeline capacity is driving tighter and less
volatile WCS heavy differentials. Regional liquids pricing
benchmarks have also been supported by a depreciating Canadian
currency relative to the United States. Every US$5/bbl WCS change
impacts Athabasca (Thermal Oil) Adjusted Funds Flow by ~$85 million
annually.
-
Significant Multi-Year Free Cash Flow: Inclusive
of the progressive growth at Leismer, Athabasca (Thermal Oil)
expects to generate in excess of $1 billion of Free Cash Flow at
US$70 WTI1 during the timeframe of 2024-27. Free Cash Flow will
continue to support the Company’s return of capital
initiatives.
-
Thermal Oil Royalty Advantage: Athabasca has
significant unrecovered capital balances on its Thermal Oil Assets
that ensure a low Crown royalty framework (~6%1). Leismer is
forecasted to remain pre-payout until late 20271 and Hangingstone
is forecasted to remain pre-payout beyond 20301.
-
Tax Free Horizon Advantage: Athabasca (Thermal
Oil) has $2.4 billion of valuable tax pools and does not forecast
paying cash taxes this decade.
Duvernay Energy Strategy
-
Accelerating Value: DEC is an operated, private
subsidiary of Athabasca (owned 70% by Athabasca and 30% by Cenovus
Energy). DEC accelerates value realization for Athabasca’s
shareholders by providing a clear path for self-funded production
and cash flow growth without compromising Athabasca’s capacity to
fund its Thermal Oil assets or its return of capital strategy.
-
Kaybob Duvernay Focused: Exposure to ~200,000
gross acres in the liquids rich and oil windows with ~500 gross
future well locations, including ~46,000 gross acres with 100%
working interest.
-
Self-Funded Growth: Current activity is being
funded within cash flow and cash on hand. The 2024 program includes
drilling and completions of a two-well 100% WI pad and a three-well
30% WI pad along with the spudding an additional multi-well pad in
September 2024. The Company has self-funded growth potential to in
excess of ~20,000 boe/d (75% Liquids) by the late 2020s1.
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, Sustaining Capital, Net
Cash, Liquidity) and production disclosure.
1 Pricing Assumptions: realized prices January –
October and flat pricing of US$70 WTI, US$12.50 WCS heavy
differential, C$2 AECO, and 0.73 C$/US$ FX for the balance of 2024.
2025-27 US$70 WTI, US$12.50 WCS heavy differential, C$3.00 AECO,
and 0.75 C$/US$ FX.2 The Company’s illustrative multi-year outlook
assumes a 10% annual share buyback program at an implied share
price of 4.5x EV/Debt Adjusted Cash flow in 2025 and beyond.
Financial and Operational Highlights
|
Three months ended September
30, |
|
Nine months ended September
30, |
|
($ Thousands, unless otherwise noted) |
2024 |
|
|
2023 |
|
|
2024 |
|
|
2023 |
|
|
CORPORATE CONSOLIDATED(1) |
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(2) |
|
38,909 |
|
|
|
36,176 |
|
|
|
36,675 |
|
|
|
34,950 |
|
|
Petroleum, natural gas and midstream sales |
$ |
376,781 |
|
|
$ |
379,241 |
|
|
$ |
1,089,635 |
|
|
$ |
952,596 |
|
|
Operating Income(2) |
$ |
180,184 |
|
|
$ |
168,410 |
|
|
$ |
465,070 |
|
|
$ |
320,063 |
|
|
Operating Income Net of Realized Hedging(2)(3) |
$ |
175,755 |
|
|
$ |
164,643 |
|
|
$ |
460,511 |
|
|
$ |
289,645 |
|
|
Operating Netback ($/boe)(2) |
$ |
49.12 |
|
|
$ |
50.84 |
|
|
$ |
46.36 |
|
|
$ |
33.27 |
|
|
Operating Netback Net of Realized Hedging ($/boe)(2)(3) |
$ |
47.91 |
|
|
$ |
49.70 |
|
|
$ |
45.91 |
|
|
$ |
30.11 |
|
|
Capital expenditures |
$ |
50,634 |
|
|
$ |
33,286 |
|
|
$ |
175,098 |
|
|
$ |
101,080 |
|
|
Cash flow from operating activities |
$ |
187,143 |
|
|
$ |
134,879 |
|
|
$ |
398,864 |
|
|
$ |
202,330 |
|
|
per share - basic |
$ |
0.35 |
|
|
$ |
0.23 |
|
|
$ |
0.72 |
|
|
$ |
0.34 |
|
|
Adjusted Funds Flow(2) |
$ |
163,680 |
|
|
$ |
141,138 |
|
|
$ |
417,198 |
|
|
$ |
213,406 |
|
|
per share - basic |
$ |
0.30 |
|
|
$ |
0.24 |
|
|
$ |
0.75 |
|
|
$ |
0.36 |
|
|
ATHABASCA (THERMAL OIL) |
|
|
|
|
|
|
|
|
Bitumen production (bbl/d)(2) |
|
34,853 |
|
|
|
31,691 |
|
|
|
33,390 |
|
|
|
29,972 |
|
|
Petroleum, natural gas and midstream sales |
$ |
372,634 |
|
|
$ |
360,761 |
|
|
$ |
1,072,954 |
|
|
$ |
895,167 |
|
|
Operating Income(2) |
$ |
163,694 |
|
|
$ |
155,415 |
|
|
$ |
425,837 |
|
|
$ |
278,533 |
|
|
Operating Netback ($/bbl)(2) |
$ |
49.68 |
|
|
$ |
53.59 |
|
|
$ |
46.64 |
|
|
$ |
33.72 |
|
|
Capital expenditures |
$ |
44,431 |
|
|
$ |
34,439 |
|
|
$ |
120,634 |
|
|
$ |
89,604 |
|
|
Adjusted Funds Flow(2) |
$ |
150,088 |
|
|
|
|
$ |
383,214 |
|
|
|
|
Free Cash Flow(2) |
$ |
105,657 |
|
|
|
|
$ |
262,580 |
|
|
|
|
DUVERNAY ENERGY(1) |
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(2) |
|
4,056 |
|
|
|
4,485 |
|
|
|
3,285 |
|
|
|
4,978 |
|
|
Percentage Liquids (%)(2) |
77 |
% |
|
55 |
% |
|
77 |
% |
|
56 |
% |
|
Petroleum, natural gas and midstream sales |
$ |
24,728 |
|
|
$ |
24,508 |
|
|
$ |
63,015 |
|
|
$ |
78,403 |
|
|
Operating Income(2) |
$ |
16,490 |
|
|
$ |
12,995 |
|
|
$ |
39,233 |
|
|
$ |
41,530 |
|
|
Operating Netback ($/boe)(2) |
$ |
44.20 |
|
|
$ |
31.50 |
|
|
$ |
43.59 |
|
|
$ |
30.56 |
|
|
Capital expenditures |
$ |
6,203 |
|
|
$ |
(1,153 |
) |
|
$ |
54,464 |
|
|
$ |
11,476 |
|
|
Adjusted Funds Flow(2) |
$ |
13,592 |
|
|
|
|
$ |
33,984 |
|
|
|
|
Free Cash Flow(2) |
$ |
7,389 |
|
|
|
|
$ |
(20,480 |
) |
|
|
|
NET INCOME AND COMPREHENSIVE INCOME |
|
|
|
|
|
|
|
|
Net income and comprehensive income(4) |
$ |
68,722 |
|
|
$ |
(79,212 |
) |
|
$ |
203,407 |
|
|
$ |
(78,726 |
) |
|
per share - basic(4) |
$ |
0.13 |
|
|
$ |
(0.14 |
) |
|
$ |
0.37 |
|
|
$ |
(0.13 |
) |
|
per share - diluted(4) |
$ |
0.12 |
|
|
$ |
(0.14 |
) |
|
$ |
0.36 |
|
|
$ |
(0.13 |
) |
|
COMMON SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
540,884,257 |
|
|
|
581,917,255 |
|
|
|
555,035,218 |
|
|
|
586,906,810 |
|
|
Weighted average shares outstanding - diluted |
|
550,712,443 |
|
|
|
581,917,255 |
|
|
|
559,203,568 |
|
|
|
586,906,810 |
|
|
|
|
|
September 30 |
|
December 31 |
|
As at ($ Thousands) |
|
|
2024 |
|
2023 |
|
LIQUIDITY AND BALANCE SHEET |
|
|
|
|
|
|
Cash and cash equivalents |
|
|
$ |
334,851 |
|
$ |
343,309 |
|
Available credit facilities(5) |
|
|
$ |
121,316 |
|
$ |
85,488 |
|
Face value of term debt(6) |
|
|
$ |
200,000 |
|
$ |
207,648 |
|
(1) Corporate Consolidated and Duvernay Energy
reflect gross production and financial metrics before taking into
consideration Athabasca's 70% equity interest in Duvernay
Energy.(2) Refer to the “Reader Advisory” section within this News
Release for additional information on Non-GAAP Financial Measures
and production disclosure.(3) Includes realized commodity risk
management loss of $4.4 million and $4.6 million for the three and
nine months ended September 30, 2024 (three and nine months ended
September 30, 2023 – loss of $3.8 million and $30.4 million).(4)
Net income (loss) and comprehensive income (loss) per share amounts
are based on net income (loss) and comprehensive income (loss)
attributable to shareholders of the Parent Company. In the
calculation of diluted net income (loss) per share for the three
months ended September 30, 2024 net income (loss) was reduced by
$2.6 million to account for the impact to net income (loss) had the
outstanding warrants been converted to equity. (5) Includes
available credit under Athabasca's and Duvernay Energy's Credit
Facilities and Athabasca's Unsecured Letter of Credit Facility.(6)
The face value of the term debt at December 31, 2023 was US$157.0
million translated into Canadian dollars at the December 31, 2023
exchange rate of US$1.00 = C$1.3226.
Operations Update
Athabasca (Thermal Oil)
Production for the third quarter of 2024
averaged 34,853 bbl/d. The Thermal Oil division generated Operating
Income of $164 million (Operating Netbacks - $50.05/bbl at the
Leismer and $48.39/bbl at Hangingstone) during the period with
capital expenditures of $44 million, primarily related to drilling
and completions, and progressing future growth initiatives at
Leismer.
Leismer
Leismer produced a record 27,485 bbl/d during
the quarter following the completion of the facility expansion. The
Company is continuing with progressive growth to increase Leismer
production to 40,000 bbl/d (regulatory approved capacity) over the
next three years. These capital projects are flexible and highly
economic (~$25,000/bbl/d capital efficiency) and will maximize
value creation when executed alongside the Company’s return of
capital initiatives. Activity over the next three years will
include drilling ~20 well pairs (sustaining and growth wells),
expanding steam capacity to ~130,000 bbl/d and adding oil
processing capacity at the central processing facility. The project
will benefit from installing opportunistically pre-purchased steam
generators which reduce the timelines and costs for the
project.
Activity in H2 2024 includes drilling four
sustaining well pairs at Pad L10 and six extended redrills on Pad
L1, with production expected in early 2025.
Hangingstone
Production during the quarter averaged 7,368
bbl/d. Non-condensable gas co-injection continues to assist in
pressure support, reduced energy usage and an improved SOR
averaging ~3.4x year to date. During the quarter the Company rig
released two ~1,400 meter well pairs with first steam planned for
later this year and production in early 2025. Well design with
extended reach laterals is expected to drive project capital
efficiencies of ~$15,000/bbl/d and will leverage off available
plant and infrastructure capacity. These sustaining well pairs will
support base production with the objective of ensuring Hangingstone
continues to deliver meaningful cash flow contributions to the
Company and maintaining competitive netbacks.
Duvernay Energy
Production for the third quarter of 2024
averaged 4,056 boe/d (77% Liquids). Duvernay Energy generated
Operating Income of $16 million (Operating Netback - $44.20/boe)
during the period.
Duvernay Energy brought its two-well 100%
working interest pad at 03-18-64-17W5 on production in late April.
The pad generated an average restricted 180-day rate of ~840 boe/d
per well (82% liquids). A three well pad (30% working interest) at
02-03-65-20W5 was brought on production in late May, with an
approximate 120-day rate of ~835 boe/d per well (85% liquids). Both
pads are performing in-line with management’s expectations and are
exhibiting strong extended results with high liquids content. The
Company spud a three-well 100% working interest pad at 4-18-64-16W5
in September. Two wells have been cased on this pad with average
laterals of ~4,000 meters per well. The operated pad of wells is
expected to be completed in 2025.
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 and
capital efficiencies; production growth to expected production
rates and estimated sustaining capital amounts; timing of Leismer’s
and Hangingstone’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 and
2025 to 2027; type well economic metrics; number of drilling
locations; forecasted daily production and the composition of
production; our outlook in respect of the Company’s business
environment, including in respect of the Trans Mountain pipeline
expansion and heavy oil pricing; 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 including deceptive marketing provisions;
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 "Corporate Consolidated Adjusted Funds
Flow", “Corporate Consolidated Adjusted Funds Flow per Share”,
"Athabasca (Thermal Oil) Adjusted Funds Flow", "Duvernay Energy
Adjusted Funds Flow", “Corporate Consolidated Free Cash Flow”,
"Athabasca (Thermal Oil) Free Cash Flow", "Duvernay Energy Free
Cash Flow", “Corporate Consolidated Operating Income", "Corporate
Consolidated Operating Income Net of Realized Hedging", "Athabasca
(Thermal Oil) Operating Income", "Duvernay Energy Operating
Income", "Corporate Consolidated Operating Netback", "Corporate
Consolidated Operating Netback Net of Realized Hedging", "Athabasca
(Thermal Oil) Operating Netback", "Duvernay Energy Operating
Netback" and “Cash Transportation and Marketing Expense” 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. Sustaining Capital, Net Cash and
Liquidity are supplementary financial measures. The
Leismer and Hangingstone operating results are supplementary
financial measures that when aggregated, combine to the Athabasca
(Thermal 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 endedSeptember 30,
2024 |
|
Three months endedSeptember 30,
2023 |
|
($ Thousands) |
Athabasca (Thermal Oil) |
|
Duvernay
Energy(1) |
|
Corporate
Consolidated(1) |
|
Corporate Consolidated |
|
Cash flow from operating activities |
$ |
169,950 |
|
$ |
17,193 |
|
$ |
187,143 |
|
$ |
134,879 |
|
Changes in non-cash working capital |
|
(20,201 |
) |
|
(3,401 |
) |
|
(23,602 |
) |
|
5,898 |
|
Settlement of provisions |
|
339 |
|
|
(200 |
) |
|
139 |
|
|
361 |
|
ADJUSTED FUNDS FLOW |
|
150,088 |
|
|
13,592 |
|
|
163,680 |
|
|
141,138 |
|
Capital expenditures |
|
(44,431 |
) |
|
(6,203 |
) |
|
(50,634 |
) |
|
(33,286 |
) |
FREE CASH FLOW |
$ |
105,657 |
|
$ |
7,389 |
|
$ |
113,046 |
|
$ |
107,852 |
|
(1) Duvernay Energy and Corporate Consolidated
reflect gross financial metrics before taking into consideration
Athabasca's 70% equity interest in Duvernay Energy.
|
Nine months endedSeptember 30,
2024 |
|
Nine months endedSeptember 30,
2023 |
|
($ Thousands) |
Athabasca (Thermal Oil) |
|
Duvernay
Energy(1) |
|
Corporate
Consolidated(1) |
|
Corporate Consolidated |
|
Cash flow from operating activities |
$ |
367,018 |
|
$ |
31,846 |
|
$ |
398,864 |
|
$ |
202,330 |
|
Changes in non-cash working capital |
|
14,560 |
|
|
2,134 |
|
|
16,694 |
|
|
22,498 |
|
Settlement of provisions |
|
1,636 |
|
|
4 |
|
|
1,640 |
|
|
1,155 |
|
Long-term deposit |
|
— |
|
|
— |
|
|
— |
|
|
(12,577 |
) |
ADJUSTED FUNDS FLOW |
|
383,214 |
|
|
33,984 |
|
|
417,198 |
|
|
213,406 |
|
Capital expenditures |
|
(120,634 |
) |
|
(54,464 |
) |
|
(175,098 |
) |
|
(101,080 |
) |
FREE CASH FLOW |
$ |
262,580 |
|
$ |
(20,480 |
) |
$ |
242,100 |
|
$ |
112,326 |
|
(1) Duvernay Energy and Corporate Consolidated
reflect gross financial metrics before taking into consideration
Athabasca's 70% equity interest in Duvernay Energy.
Duvernay Energy Operating Income and Operating
Netback
The non-GAAP measure Duvernay Energy Operating
Income in this News Release is calculated by subtracting the
Duvernay Energy royalties, operating expenses and transportation
& marketing expenses from petroleum and natural gas sales which
is the most directly comparable GAAP measure. The Duvernay Energy
Operating Netback per boe is a non-GAAP financial ratio calculated
by dividing the Duvernay Energy Operating Income by the Duvernay
Energy production. The Duvernay Energy Operating Income and the
Duvernay Energy Operating Netback measures allow management and
others to evaluate the production results from the Company’s
Duvernay Energy assets.
The Duvernay Energy Operating Income is
calculated using the Duvernay Energy Segments GAAP results, as
follows:
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands, unless otherwise noted) |
2024 |
|
2023 |
|
2024 |
|
2023 |
|
Petroleum and natural gas sales |
$ |
24,728 |
|
$ |
24,508 |
|
$ |
63,015 |
|
$ |
78,403 |
|
Royalties |
|
(2,470 |
) |
|
(3,510 |
) |
|
(8,282 |
) |
|
(10,403 |
) |
Operating expenses |
|
(4,684 |
) |
|
(5,964 |
) |
|
(12,387 |
) |
|
(19,988 |
) |
Transportation and marketing |
|
(1,084 |
) |
|
(2,039 |
) |
|
(3,113 |
) |
|
(6,482 |
) |
DUVERNAY ENERGY OPERATING INCOME |
$ |
16,490 |
|
$ |
12,995 |
|
$ |
39,233 |
|
$ |
41,530 |
|
Athabasca (Thermal Oil) Operating Income and Operating
Netback
The non-GAAP measure Athabasca (Thermal Oil)
Operating Income in this News Release is calculated by subtracting
the Athabasca (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
Athabasca (Thermal Oil) Operating Netback per bbl is a non-GAAP
financial ratio calculated by dividing the respective projects
Operating Income by its respective bitumen sales volumes. The
Athabasca (Thermal Oil) Operating Income and the Athabasca (Thermal
Oil) Operating Netback measures allow management and others to
evaluate the production results from the Athabasca (Thermal Oil)
assets. The Athabasca (Thermal Oil) Operating Income is calculated
using the Athabasca (Thermal Oil) Segments GAAP results, as
follows:
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands) |
2024 |
|
2023 |
|
2024 |
|
2023 |
|
Heavy oil (blended bitumen) and midstream sales |
$ |
372,634 |
|
$ |
360,761 |
|
$ |
1,072,954 |
|
$ |
895,167 |
|
Cost of diluent |
|
(129,965 |
) |
|
(117,418 |
) |
|
(411,991 |
) |
|
(380,781 |
) |
Total bitumen and midstream sales |
|
242,669 |
|
|
243,343 |
|
|
660,963 |
|
|
514,386 |
|
Royalties |
|
(22,291 |
) |
|
(27,613 |
) |
|
(62,651 |
) |
|
(45,170 |
) |
Operating expenses - non-energy |
|
(24,903 |
) |
|
(19,521 |
) |
|
(72,445 |
) |
|
(63,349 |
) |
Operating expenses - energy |
|
(9,994 |
) |
|
(20,572 |
) |
|
(38,187 |
) |
|
(64,118 |
) |
Transportation and marketing(1) |
|
(21,787 |
) |
|
(20,222 |
) |
|
(61,843 |
) |
|
(63,216 |
) |
ATHABASCA (THERMAL OIL) OPERATING INCOME |
$ |
163,694 |
|
$ |
155,415 |
|
$ |
425,837 |
|
$ |
278,533 |
|
(1) Transportation and marketing excludes
non-cash costs of $0.6 million and $1.7 million for the three and
nine months ended September 30, 2024 (three and nine months ended
September 30, 2023 - $0.6 million and $1.7 million).
Corporate Consolidated Operating Income and
Corporate Consolidated Operating Income Net of Realized Hedging and
Operating Netbacks
The non-GAAP measures of Corporate Consolidated
Operating Income including or excluding realized hedging in this
News Release are calculated by adding or subtracting realized gains
(losses) on commodity risk management contracts (as applicable),
royalties, the cost of diluent blending, operating expenses and
cash transportation & marketing expenses from petroleum,
natural gas and midstream sales which is the most directly
comparable GAAP measure. The Corporate Consolidated Operating
Netbacks including or excluding realized hedging per boe are
non-GAAP ratios calculated by dividing Corporate Consolidated
Operating Income including or excluding hedging by the total sales
volumes and are presented on a per boe basis. The Corporate
Consolidated Operating Income and Corporate Consolidated Operating
Netbacks including or excluding realized hedging measures allow
management and others to evaluate the production results from the
Company’s Duvernay Energy and Athabasca (Thermal Oil) assets
combined together including the impact of realized commodity risk
management gains or losses (as applicable).
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands) |
2024 |
|
2023 |
|
2024 |
|
2023 |
|
Petroleum, natural gas and midstream sales(1) |
$ |
397,362 |
|
$ |
385,269 |
|
$ |
1,135,969 |
|
$ |
973,570 |
|
Royalties |
|
(24,761 |
) |
|
(31,123 |
) |
|
(70,933 |
) |
|
(55,573 |
) |
Cost of diluent(1) |
|
(129,965 |
) |
|
(117,418 |
) |
|
(411,991 |
) |
|
(380,781 |
) |
Operating expenses |
|
(39,581 |
) |
|
(46,057 |
) |
|
(123,019 |
) |
|
(147,455 |
) |
Transportation and marketing(2) |
|
(22,871 |
) |
|
(22,261 |
) |
|
(64,956 |
) |
|
(69,698 |
) |
Operating Income |
|
180,184 |
|
|
168,410 |
|
|
465,070 |
|
|
320,063 |
|
Realized loss on commodity risk mgmt. contracts |
|
(4,429 |
) |
|
(3,767 |
) |
|
(4,559 |
) |
|
(30,418 |
) |
OPERATING INCOME NET OF REALIZED HEDGING |
$ |
175,755 |
|
$ |
164,643 |
|
$ |
460,511 |
|
$ |
289,645 |
|
(1) Non-GAAP measure includes intercompany NGLs
(i.e. condensate) sold by the Duvernay Energy segment to the
Athabasca (Thermal Oil) segment for use as diluent that is
eliminated on consolidation.(2) Transportation and marketing
excludes non-cash costs of $0.6 million and $1.7 million for the
three and nine months ended September 30, 2024 (three and nine
months ended September 30, 2023 - $0.6 million and $1.7
million).
Cash Transportation and Marketing Expense
The Cash Transportation and Marketing Expense
financial measures contained in this News Release are calculated by
subtracting the non-cash transportation and marketing expense as
reported in the Consolidated Statement of Cash Flows from the
transportation and marketing expense as reported in the
Consolidated Statement of Income (Loss) and are considered to be
non-GAAP financial measures.
Sustaining Capital
Sustaining Capital is managements' assumption of the required
capital to maintain the Company’s production base.
Net Cash
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 plus income tax payable
less current assets, excluding risk management contracts.
Liquidity
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
Production |
2024 |
|
2023 |
|
2024 |
|
2023 |
Duvernay Energy: |
|
|
|
|
|
|
|
|
|
|
|
Oil(1) |
bbl/d |
2,688 |
|
|
1,398 |
|
|
2,235 |
|
|
1,461 |
Condensate NGLs |
bbl/d |
— |
|
|
581 |
|
|
— |
|
|
705 |
Oil and condensate NGLs |
bbl/d |
2,688 |
|
|
1,979 |
|
|
2,235 |
|
|
2,166 |
Other NGLs |
bbl/d |
447 |
|
|
528 |
|
|
298 |
|
|
615 |
Natural gas(2) |
mcf/d |
5,526 |
|
|
11,869 |
|
|
4,511 |
|
|
13,181 |
Total Duvernay Energy |
boe/d |
4,056 |
|
|
4,485 |
|
|
3,285 |
|
|
4,978 |
Total Thermal Oil bitumen |
bbl/d |
34,853 |
|
|
31,691 |
|
|
33,390 |
|
|
29,972 |
Total Company production |
boe/d |
38,909 |
|
|
36,176 |
|
|
36,675 |
|
|
34,950 |
(1) Comprised of 99% or greater of tight oil,
with the remaining being light and medium crude oil.(2) Comprised
of 99% or greater of shale gas, with the remaining being
conventional natural gas.
This News Release also makes reference to
Athabasca's forecasted average daily Thermal Oil production of
33,000 - 34,000 bbl/d for 2024. Athabasca expects that 100% of that
production will be comprised of bitumen. Duvernay Energy’s
forecasted total average daily production of ~3,000 boe/d for 2024
is expected to be comprised of approximately 67% tight oil, 23%
shale gas and 10% NGLs.
Liquids is defined as bitumen, light crude oil,
medium crude oil and natural gas liquids.
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, Sustaining Capital, Net
Cash, Liquidity) and production disclosure.
1 Pricing Assumptions: realized prices January –
October and flat pricing of US$70 WTI, US$12.50 WCS heavy
differential, C$2 AECO, and 0.73 C$/US$ FX for the balance of 2024.
2025-27 US$70 WTI, US$12.50 WCS heavy differential, C$3.00 AECO,
and 0.75 C$/US$ FX.2 The Company’s illustrative multi-year outlook
assumes a 10% annual share buyback program at an implied share
price of 4.5x EV/Debt Adjusted Cash flow in 2025 and beyond.
Athabasca Oil (TSX:ATH)
Gráfica de Acción Histórica
De Oct 2024 a Nov 2024
Athabasca Oil (TSX:ATH)
Gráfica de Acción Histórica
De Nov 2023 a Nov 2024