Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”)
is pleased to report its third quarter results highlighted by
record Adjusted Funds Flow and Free Cash Flow, operational momentum
at Leismer and execution on its return of capital commitment
through share repurchases. Athabasca is uniquely positioned as a
low leveraged company generating significant Free Cash Flow through
its low-decline, oil weighted asset base.
Q3 2023 and Recent Corporate
Highlights
-
Production: ~36,200 boe/d (95% Liquids); ~31,700
bbl/d in Thermal Oil and ~4,500 boe/d in Light Oil.
- Record
Production at Leismer: 24,232 bbl/d during the quarter
following the ramp-up of Pad L8M with five sustaining well pairs.
The Company’s expansion project is on track for growth to 28,000
bbl/d in mid-2024 and with the increased operating scale the
Company forecasts ~$5/bbl margin improvement.
-
Record Cash Flow: Consolidated Operating Income of
$168 million and record Adjusted Funds Flow1 of $141 million. Cash
Flow was supported by strong heavy oil prices and an overall
operating netback of $50.84/bbl (including an Operating Netback of
$55.17/bbl at Leismer).
-
Capital Program: $33 million focused on advancing
the Leismer expansion project in Thermal Oil.
-
Record Free Cash Flow: $108 million of Free Cash
Flow underpinning return of capital commitments.
-
Return of Capital: $113 million in share buybacks
(33 million shares at an average price of $3.42 per share)
completed since April representing 57% of the Company’s annual
Normal Course Issuer Bid limit. Year to date Athabasca has reduced
its fully diluted share count by ~7%.
-
Light Oil Disposition: Closed the sale of ~3,000
boe/d of non-core Placid, Saxon and Simonette assets for $160
million in cash in September. The transaction was completed at
attractive valuation metrics (7.9x Net Operating Income).
-
Balance Sheet: $7 million of incremental debt
retirement with a Net Cash position of $155 million at quarter-end.
Strong Liquidity of $425 million, including cash of $337 million.
The Company also holds $2.8 billion in corporate tax pools.
Strategic Outlook
-
Compelling Value Proposition: Athabasca is focused
on driving shareholder value through strong multi-year cash flow
per share growth. The Company’s asset base provides a platform to
drive profitable liquids weighted growth supported by financial
resiliency to execute on return of capital initiatives. The Company
intends to release its 2024 guidance in December.
-
2023 Guidance: The Company is executing a ~$145
million capital program with activity focused on advancing the
expansion project at Leismer and operational readiness in Light
Oil. Corporate production is expected to average ~34,500 boe/d with
the ~3,000 boe/d non-core disposition being partially offset by
recent growth at Leismer. Athabasca’s portfolio of long-life assets
underpins a low corporate decline of ~5% annually.
-
Return of Capital Commitment: Athabasca is
committed to executing on its 2023 return of capital commitment
that will see a minimum of 75% of Excess Cash Flow (Adjusted Funds
Flow less Sustaining Capital) returned to shareholders through
share buybacks.
-
Capital Efficient Growth at Leismer: The Company
has seen a strong ramp-up of production with a facility expansion
underway. Athabasca has completed drilling the initial wells
required to 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 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 anticipated narrower WCS heavy differentials
following the start-up of the Trans Mountain pipeline expansion.
The Company expects to generate ~$1 billion in Free Cash Flow2
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 late 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
maintains excellent exposure to upside in commodity prices with 25%
of rolling 12-month production volumes hedged in accordance with
its debt agreements. The Company has hedged ~23,250 bbl/d in Q4
2023 with an average WTI collar of US$50 – US$111/bbl and ~9,000
bbl/d in Q1 2024 with an average WTI collar of US$50 – US$126/bbl.
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).
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 Cash
flow from operating activities in Q3 2023 was $135 million. 2
Pricing Assumptions: 2023 realized prices in Q1-Q3 and flat pricing
of US$85 WTI, US$21 Western Canadian Select “WCS” heavy
differential, C$3 AECO and 0.73 C$/US$ FX for Q4. 2024-25 flat
pricing of US$85 WTI, US$12.50 WCS heavy differential, C$5 AECO and
0.75 C$/US$ FX.
Business Environment
Oil prices advanced in the quarter with strong
world oil demand. The global supply picture was supported by
continued OPEC+ cuts and inventory drawdowns. Athabasca maintains a
constructive outlook on prices supported by years of industry
underinvestment, OPEC+ policy and demand trends.
Canadian WCS heavy differentials narrowed
significantly in the quarter with differentials averaging
~US$13/bbl, compared to ~US$20/bbl in the first half of 2023.
Athabasca believes the recent widening in differentials to
~US$21/bbl (Q4 strip pricing) is primarily a function of
seasonality with refinery downtime and anticipates tightening from
current levels in 2024 following the start-up of the Trans Mountain
pipeline expansion (590,000 bbl/d) and new global heavy oil
refining capacity.
Financial and Operational Highlights
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
($ Thousands, unless otherwise noted) |
2023 |
|
|
2022 |
|
|
2023 |
|
|
2022 |
|
CONSOLIDATED |
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
36,176 |
|
|
|
37,240 |
|
|
|
34,950 |
|
|
|
35,064 |
|
Petroleum, natural gas and midstream sales |
$ |
379,241 |
|
|
$ |
397,059 |
|
|
$ |
952,596 |
|
|
$ |
1,222,161 |
|
Operating Income (Loss)(1) |
$ |
168,410 |
|
|
$ |
140,081 |
|
|
$ |
320,063 |
|
|
$ |
459,976 |
|
Operating Income (Loss) Net of Realized Hedging(1)(2) |
$ |
164,643 |
|
|
$ |
110,021 |
|
|
$ |
289,645 |
|
|
$ |
316,564 |
|
Operating Netback ($/boe)(1) |
$ |
50.84 |
|
|
$ |
39.17 |
|
|
$ |
33.27 |
|
|
$ |
47.43 |
|
Operating Netback Net of Realized Hedging ($/boe)(1)(2) |
$ |
49.70 |
|
|
$ |
30.76 |
|
|
$ |
30.11 |
|
|
$ |
32.64 |
|
Capital expenditures |
$ |
33,286 |
|
|
$ |
52,300 |
|
|
$ |
101,080 |
|
|
$ |
134,420 |
|
THERMAL OIL DIVISION |
|
|
|
|
|
|
|
|
|
|
|
Bitumen production (bbl/d)(1) |
|
31,691 |
|
|
|
31,023 |
|
|
|
29,972 |
|
|
|
28,578 |
|
Petroleum, natural gas and midstream sales |
$ |
360,761 |
|
|
$ |
366,804 |
|
|
$ |
895,167 |
|
|
$ |
1,126,878 |
|
Operating Income (Loss)(1) |
$ |
155,415 |
|
|
$ |
117,916 |
|
|
$ |
278,533 |
|
|
$ |
369,820 |
|
Operating Netback ($/bbl)(1) |
$ |
53.59 |
|
|
$ |
39.25 |
|
|
$ |
33.72 |
|
|
$ |
46.66 |
|
Capital expenditures |
$ |
31,069 |
|
|
$ |
35,412 |
|
|
$ |
83,817 |
|
|
$ |
99,687 |
|
LIGHT OIL DIVISION |
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
4,485 |
|
|
|
6,217 |
|
|
|
4,978 |
|
|
|
6,486 |
|
Percentage Liquids (%)(1) |
55 |
% |
|
57 |
% |
|
56 |
% |
|
57 |
% |
Petroleum, natural gas and midstream sales |
$ |
24,508 |
|
|
$ |
39,990 |
|
|
$ |
78,403 |
|
|
$ |
138,923 |
|
Operating Income (Loss)(1) |
$ |
12,995 |
|
|
$ |
22,165 |
|
|
$ |
41,530 |
|
|
$ |
90,156 |
|
Operating Netback ($/boe)(1) |
$ |
31.50 |
|
|
$ |
38.76 |
|
|
$ |
30.56 |
|
|
$ |
50.92 |
|
Capital expenditures |
$ |
(1,153 |
) |
|
$ |
860 |
|
|
$ |
11,476 |
|
|
$ |
10,068 |
|
CASH FLOW AND FUNDS FLOW |
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities |
$ |
134,879 |
|
|
$ |
117,853 |
|
|
$ |
202,330 |
|
|
$ |
246,250 |
|
per share - basic |
$ |
0.23 |
|
|
$ |
0.20 |
|
|
$ |
0.34 |
|
|
$ |
0.44 |
|
Adjusted Funds Flow(1) |
$ |
141,138 |
|
|
$ |
102,370 |
|
|
$ |
213,406 |
|
|
$ |
261,930 |
|
per share - basic |
$ |
0.24 |
|
|
$ |
0.17 |
|
|
$ |
0.36 |
|
|
$ |
0.47 |
|
Free Cash Flow (1) |
$ |
107,852 |
|
|
$ |
50,070 |
|
|
$ |
112,326 |
|
|
$ |
127,510 |
|
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) and comprehensive income (loss) |
$ |
(79,212 |
) |
|
$ |
155,097 |
|
|
$ |
(78,726 |
) |
|
$ |
82,617 |
|
per share - basic |
$ |
(0.14 |
) |
|
$ |
0.27 |
|
|
$ |
(0.13 |
) |
|
$ |
0.15 |
|
per share - diluted(3) |
$ |
(0.14 |
) |
|
$ |
0.22 |
|
|
$ |
(0.13 |
) |
|
$ |
0.14 |
|
COMMON SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
581,917,255 |
|
|
|
585,058,807 |
|
|
|
586,906,810 |
|
|
|
561,823,801 |
|
Weighted average shares outstanding - diluted |
|
581,917,255 |
|
|
|
620,563,273 |
|
|
|
586,906,810 |
|
|
|
580,580,442 |
|
|
September 30, |
|
December 31, |
As at ($ Thousands) |
2023 |
|
2022 |
LIQUIDITY AND BALANCE SHEET |
|
|
|
|
|
Cash and cash equivalents |
$ |
337,125 |
|
$ |
197,525 |
Available credit facilities(4) |
$ |
87,838 |
|
$ |
87,838 |
Face value of term debt(5) |
$ |
212,264 |
|
$ |
237,231 |
(1) Refer to the “Advisories and Other Guidance”
section within this News Release for additional information on
Non-GAAP Financial Measures and production disclosure.(2) Includes
realized commodity risk management loss of $3.8 million and $30.4
million for the three and nine months ended September 30, 2023
(three and nine months ended September 30, 2022 – loss of $30.1
million and $143.4 million).(3) In the calculation of dilutive
earnings per share for the three months ended September 30, 2022,
earnings were reduced by $16.4 million to account for the impact to
net income had the outstanding warrants and PSUs 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 September 30, 2023 was US$157 million (December
31, 2022 – US$175 million) translated into Canadian dollars at the
September 30, 2023 exchange rate of US$1.00 = C$1.3520 (December
31, 2022 – C$1.3544).
Operations Update
Thermal Oil
Bitumen production for the third quarter of 2023
averaged 31,691 bbl/d. The Thermal Oil division generated Operating
Income of $155 million (Operating Netbacks - $55/bbl at Leismer and
$48/bbl at Hangingstone) during the period with capital
expenditures of $31 million, primarily related to well completions
and progressing the facility expansion at Leismer.
Leismer
Leismer produced a record 24,232 bbl/d during
the quarter following the ramp-up of Pad L8M (five sustaining well
pairs). In August, the fifth new well pair on Pad L8M was placed on
production supporting current production levels of ~24,000 bbl/d
with a steam oil ratio (“SOR”) of ~3x.
During the quarter, the final four well pairs at
Pad L8S and four infill wells on Pad L7 were completed and
facilities construction is ongoing. These additional new wells are
expected to start steaming at the end of Q4 and they will support
production in 2024 and beyond.
The facility expansion project continues to
progress 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. The project is being completed at a competitive capital
efficiency of ~$14,000/bbl/d and is expected to enhance margins in
2024 by ~$5/bbl through increased operating scale. The Company
maintains future optionality for additional expansion projects that
could support Leismer growth to its regulatory approved capacity of
40,000 bbl/d.
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 late 2027 (US$85 WTI, US$12.50 WCS differential).
Hangingstone
Production during the quarter averaged 7,459
bbl/d. Non-condensable gas co-injection continues to assist in
pressure support, reduced energy usage and an improved SOR
averaging ~3.6x year to date. Activity at Hangingstone was focused
on initial work for the Pad AA extension in anticipation of
drilling sustaining well pairs in 2024 to maintain base
production.
Light Oil
Production for the third quarter of 2023
averaged 4,485 boe/d (55% Liquids). The Light Oil division
generated Operating Income of $13 million (Operating Netback -
$32/boe) during the period. Activity was focused on operational
readiness in advance of the upcoming drilling season.
In mid-September, Athabasca closed its sale of
non-core Light Oil assets at Placid, Saxon and Simonette which
included ~3,000 boe/d (45% liquids). The Company’s Light Oil
division now consists exclusively of the Duvernay in the Greater
Kaybob area with ~155,000 gross acres across Kaybob West, Kaybob
North, Kaybob East and Two Creeks with ~500 future well
locations.
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
area continues to be active with industry drilling programs
underway.
About Athabasca Oil
Corporation
Athabasca Oil Corporation is a Canadian energy
company with a focused strategy on the development of thermal and
light oil assets. Situated in Alberta’s Western Canadian
Sedimentary Basin, the Company has amassed a significant land base
of extensive, high-quality resources. Athabasca’s common shares
trade on the TSX under the symbol “ATH”. For more information,
visit www.atha.com.
For more information, please contact:
Matthew Taylor |
Robert Broen |
Chief Financial Officer |
President and CEO |
1-403-817-9104 |
1-403-817-9190 |
mtaylor@atha.com |
rbroen@atha.com |
Reader Advisory:This News Release contains
forward-looking information that involves various risks,
uncertainties and other factors. All information other than
statements of historical fact is forward-looking information. The
use of any of the words “anticipate”, “plan”, “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; improved margins at Leismer; timing
of Leismer’s pre-payout royalty status; Adjusted Funds Flow and
Free Cash Flow in 2023 to 2025; type well economic metrics;
forecasted daily production and the composition of production; 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 Revised Annual
Information Form (“AIF”) dated May 11, 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 500 gross total Duvernay drilling locations
referenced include: 5 proved undeveloped locations and 77 probable
undeveloped locations for a total of 82 booked locations with the
balance being unbooked locations. Proved undeveloped locations and
probable undeveloped locations are booked and derived from the
Company's most recent independent reserves evaluation as prepared
by McDaniel as of December 31, 2022 and account for drilling
locations that have associated proved and/or probable reserves, as
applicable. Unbooked locations are internal management estimates.
Unbooked locations do not have attributed reserves or resources
(including contingent or prospective). Unbooked locations have been
identified by management as an estimation of Athabasca’s multi-year
drilling activities expected to occur over the next two decades
based on evaluation of applicable geologic, seismic, engineering,
production and reserves information. There is no certainty that the
Company will drill all unbooked drilling locations and if drilled
there is no certainty that such locations will result in additional
oil and gas reserves, resources or production. The drilling
locations on which the Company will actually drill wells, including
the number and timing thereof is ultimately dependent upon the
availability of funding, commodity prices, provincial fiscal and
royalty policies, costs, actual drilling results, additional
reservoir information that is obtained and other factors.
Non-GAAP and Other Financial Measures,
and Production Disclosure
The "Adjusted Funds Flow", “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. “Net Cash” and “Liquidity” are
supplementary financial measures. 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 supplementary financial measures 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
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Cash flow from operating activities |
$ |
134,879 |
|
|
$ |
117,853 |
|
|
$ |
202,330 |
|
|
$ |
246,250 |
|
Changes in non-cash working capital |
|
5,898 |
|
|
|
(16,320 |
) |
|
|
22,498 |
|
|
|
14,386 |
|
Settlement of provisions |
|
361 |
|
|
|
837 |
|
|
|
1,155 |
|
|
|
1,294 |
|
Long-term deposit |
|
— |
|
|
|
— |
|
|
|
(12,577 |
) |
|
|
— |
|
ADJUSTED FUNDS FLOW |
|
141,138 |
|
|
|
102,370 |
|
|
|
213,406 |
|
|
|
261,930 |
|
Capital expenditures |
|
(33,286 |
) |
|
|
(52,300 |
) |
|
|
(101,080 |
) |
|
|
(134,420 |
) |
FREE CASH FLOW |
$ |
107,852 |
|
|
$ |
50,070 |
|
|
$ |
112,326 |
|
|
$ |
127,510 |
|
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
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Petroleum and natural gas sales |
$ |
24,508 |
|
|
$ |
39,990 |
|
|
$ |
78,403 |
|
|
$ |
138,923 |
|
Royalties |
|
(3,510 |
) |
|
|
(7,428 |
) |
|
|
(10,403 |
) |
|
|
(18,907 |
) |
Operating expenses |
|
(5,964 |
) |
|
|
(8,176 |
) |
|
|
(19,988 |
) |
|
|
(22,898 |
) |
Transportation and marketing |
|
(2,039 |
) |
|
|
(2,221 |
) |
|
|
(6,482 |
) |
|
|
(6,962 |
) |
LIGHT OIL OPERATING INCOME |
$ |
12,995 |
|
|
$ |
22,165 |
|
|
$ |
41,530 |
|
|
$ |
90,156 |
|
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
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Heavy oil (blended bitumen) and midstream sales |
$ |
360,761 |
|
|
$ |
366,804 |
|
|
$ |
895,167 |
|
|
$ |
1,126,878 |
|
Cost of diluent |
|
(117,418 |
) |
|
|
(138,244 |
) |
|
|
(380,781 |
) |
|
|
(419,840 |
) |
Total bitumen and midstream sales |
|
243,343 |
|
|
|
228,560 |
|
|
|
514,386 |
|
|
|
707,038 |
|
Royalties |
|
(27,613 |
) |
|
|
(31,471 |
) |
|
|
(45,170 |
) |
|
|
(119,878 |
) |
Operating expenses |
|
(40,093 |
) |
|
|
(56,027 |
) |
|
|
(127,467 |
) |
|
|
(152,965 |
) |
Cash transportation and marketing(1) |
|
(20,222 |
) |
|
|
(23,146 |
) |
|
|
(63,216 |
) |
|
|
(64,375 |
) |
THERMAL OIL OPERATING INCOME |
$ |
155,415 |
|
|
$ |
117,916 |
|
|
$ |
278,533 |
|
|
$ |
369,820 |
|
(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, 2023 (three and nine months ended
September 30, 2022 - $0.6 million and $1.7 million).
Consolidated Operating Income and Consolidated
Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Consolidated Operating
Income including or excluding realized hedging in this News Release
are calculated by adding or subtracting realized gains (losses) on
commodity risk management contracts (as applicable), royalties, the
cost of diluent blending, operating expenses and cash
transportation & marketing expenses from petroleum, natural gas
and midstream sales which is the most directly comparable GAAP
measure. The Consolidated Operating Netbacks including or excluding
realized hedging per boe are non-GAAP ratios calculated by dividing
Consolidated Operating Income including or excluding hedging by the
total sales volumes and are presented on a per boe basis. The
Consolidated Operating Income and Consolidated Operating Netbacks
including or excluding realized hedging measures allow management
and others to evaluate the production results from the Company’s
Light Oil and Thermal Oil assets combined together including the
impact of realized commodity risk management gains or losses (as
applicable).
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Petroleum, natural gas and midstream sales(1) |
$ |
385,269 |
|
|
$ |
406,794 |
|
|
$ |
973,570 |
|
|
$ |
1,265,801 |
|
Royalties |
|
(31,123 |
) |
|
|
(38,899 |
) |
|
|
(55,573 |
) |
|
|
(138,785 |
) |
Cost of diluent(1) |
|
(117,418 |
) |
|
|
(138,244 |
) |
|
|
(380,781 |
) |
|
|
(419,840 |
) |
Operating expenses |
|
(46,057 |
) |
|
|
(64,203 |
) |
|
|
(147,455 |
) |
|
|
(175,863 |
) |
Cash transportation and marketing(2) |
|
(22,261 |
) |
|
|
(25,367 |
) |
|
|
(69,698 |
) |
|
|
(71,337 |
) |
Operating Income |
|
168,410 |
|
|
|
140,081 |
|
|
|
320,063 |
|
|
|
459,976 |
|
Realized gain (loss) on commodity risk management contracts |
|
(3,767 |
) |
|
|
(30,060 |
) |
|
|
(30,418 |
) |
|
|
(143,412 |
) |
OPERATING INCOME NET OF REALIZED HEDGING |
$ |
164,643 |
|
|
$ |
110,021 |
|
|
$ |
289,645 |
|
|
$ |
316,564 |
|
(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 and $1.7 million for the three and
nine months ended September 30, 2023 (three and nine months ended
September 30, 2022 - $0.6 million and $1.7 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 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
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
Production |
2023 |
|
2022 |
|
2023 |
|
2022 |
Greater Placid: |
|
|
|
|
|
|
|
|
Condensate NGLs |
bbl/d |
581 |
|
908 |
|
705 |
|
1,003 |
Other NGLs |
bbl/d |
281 |
|
464 |
|
344 |
|
428 |
Natural gas(1) |
mcf/d |
7,654 |
|
10,855 |
|
8,977 |
|
11,449 |
Total Greater Placid |
boe/d |
2,138 |
|
3,181 |
|
2,545 |
|
3,339 |
|
|
|
|
|
|
|
|
|
Greater Kaybob: |
|
|
|
|
|
|
|
|
Oil(2) |
bbl/d |
1,398 |
|
1,849 |
|
1,461 |
|
1,946 |
Other NGLs |
bbl/d |
247 |
|
335 |
|
271 |
|
337 |
Natural gas(1) |
mcf/d |
4,215 |
|
5,111 |
|
4,204 |
|
5,186 |
Total Greater Kaybob |
boe/d |
2,347 |
|
3,036 |
|
2,433 |
|
3,147 |
|
|
|
|
|
|
|
|
|
Light Oil: |
|
|
|
|
|
|
|
|
Oil(2) |
bbl/d |
1,398 |
|
1,849 |
|
1,461 |
|
1,946 |
Condensate NGLs |
bbl/d |
581 |
|
908 |
|
705 |
|
1,003 |
Oil and condensate NGLs |
bbl/d |
1,979 |
|
2,757 |
|
2,166 |
|
2,949 |
Other NGLs |
bbl/d |
528 |
|
799 |
|
615 |
|
765 |
Natural gas(1) |
mcf/d |
11,869 |
|
15,966 |
|
13,181 |
|
16,635 |
Total Light Oil division |
boe/d |
4,485 |
|
6,217 |
|
4,978 |
|
6,486 |
Total Thermal Oil division bitumen |
bbl/d |
31,691 |
|
31,023 |
|
29,972 |
|
28,578 |
Total Company production |
boe/d |
36,176 |
|
37,240 |
|
34,950 |
|
35,064 |
(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
boe/d for 2023. Athabasca expects that ~88% of that production will
be comprised of bitumen, ~5% shale gas, ~4% tight oil, ~2%
condensate natural gas liquids and ~1% other natural gas
liquids.
This News Release makes reference to Athabasca's
latest 12 wells at Kaybob East and Two Creeks that 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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