Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”)
is pleased to report its second quarter results highlighted by
continued operational momentum at Leismer, strong Free Cash Flow
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.
Q2 2023 and Recent Corporate
Highlights
-
Production: ~34,000 boe/d (93% Liquids) consisting
of ~29,000 bbl/d in Thermal Oil and ~5,000 boe/d in Light Oil. The
Light Oil facilities were temporarily shut-in during May in
response to the Alberta wildfires. No damage was sustained and
production was fully restored in June. The Company is maintaining
annual guidance of 34,500 – 36,000 boe/d, underpinned by production
ramp up at Leismer throughout the remainder of 2023.
-
Cash Flow: Consolidated Operating Income of $95
million and Adjusted Funds Flow1 of $82 million. Cash Flow was
supported by structurally stronger Western Canadian Select heavy
differentials averaging US$15/bbl in Q2 (US$25/bbl Q1 2023).
-
Capital Program: $41 million focused on advancing
the Leismer expansion project in Thermal Oil. Capital guidance for
the year remains at $145 million.
-
Free Cash Flow: $40 million of Free Cash Flow
supporting return of capital commitments.
-
Executing Return of Capital Commitment: $61
million in share buybacks (20 million shares at an average price of
$3.04 per share) completed since April representing 34% of the
Company’s annual Normal Course Issuer Bid limit.
-
Balance Sheet Strength: Net Debt of $62 million
with Liquidity of $220 million, including Cash of $132 million. The
Company maintains a low level of outstanding debt.
-
Leismer Update: Pad L8M commenced steaming in Q1
with four of the five well pairs placed on production in early June
and the fifth expected to be on production in August. The asset is
currently producing ~24,000 bbl/d, significantly ahead of prior
production guidance. Drilling operations have recently been
completed on four infill wells on Pad L7 and four well pairs on Pad
L8S. These additional wells will support the expansion project that
will drive growth to ~28,000 bbl/d by mid-2024. With the increased
operating scale, the Company forecasts ~$5/bbl margin improvement
at Leismer in 2024.
Strategic Update and Corporate
Guidance
-
Production Guidance. Overall production is
expected to grow annually by 5 – 7% through the Company’s current
capital initiatives. 2023 guidance remains unchanged at 34,500 –
36,000 boe/d (93% Liquids). Athabasca’s portfolio of long-life
assets underpin a low corporate decline of ~5% annually.
-
Capital Guidance Intact: The Company remains
committed to executing a ~$145 million capital program this year
($120 million Thermal and $25 million Light Oil) with activity
focused on advancing the expansion project at Leismer and
operational readiness in Light Oil.
-
Return of Capital Commitment: Athabasca is
committed to allocating a minimum of 75% of Excess Cash Flow
(Adjusted Funds Flow less Sustaining Capital) in 2023 to
shareholders through share buybacks. Additional Excess Cash Flow
allocation will be commodity price dependent and could include
additional share repurchases dependent on valuation, further debt
reduction or high return growth projects.
-
Capital Efficient Growth at Leismer: Leismer
production is currently ~24,000 bbl/d and the Company has
successfully accelerated the on production dates for well pairs on
Pad L8M. A facility expansion and additional drilling will support
sustainable growth to ~28,000 bbl/d by mid-2024 at a competitive
capital efficiency of ~$14,000/bbl/d. This project is on-track with
previous guidance, will not impact the return of capital strategy
and is expected to bolster future Free Cash Flow generation through
enhanced margins.
-
Managing for Free Cash Flow: Athabasca is
positioned for continued margin growth in 2024 with the Leismer
expansion and expected narrower WCS heavy differentials following
the expected start-up of the Trans Mountain Pipeline Expansion. 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 2027 and Hangingstone well
into the 2030s (US$85 WTI, US$12.50 WCS differential). This results
in maximum cash flow at current commodity prices and creates a
significant advantage over the majority of industry oil sands
projects.
-
Excellent Exposure to Commodity Upside: Athabasca
has excellent exposure to upside in commodity prices with 25% of
forecasted 2023 production volumes hedged through collars,
providing upside to ~US$98.50 WTI. Every $5/bbl WTI change impacts
annual cash flow by ~$50 million (unhedged) and every US$5/bbl WCS
differential change impacts annual cash flow by ~$80 million
(unhedged).
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 Debt,
Liquidity) and production disclosure.1Cash flow from
operating activities in Q2 2023 was $47 million. 2 Pricing
Assumptions: 2023 realized prices in H1 and flat pricing of US$80
WTI, US$15 Western Canadian Select “WCS” heavy differential, C$3
AECO, and $0.75 C$/US$ FX for H2. 2024-25 flat pricing of US$85
WTI, US$12.50 WCS heavy differential, C$5 AECO, and $0.75 C$/US$
FX.
Financial and Operational Highlights
|
Three months
endedJune 30, |
|
Six months
endedJune 30, |
($ Thousands, unless otherwise noted) |
2023 |
|
|
2022 |
|
|
2023 |
|
|
2022 |
|
CONSOLIDATED |
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
33,971 |
|
|
|
33,247 |
|
|
|
34,325 |
|
|
|
33,958 |
|
Petroleum, natural gas and midstream sales |
$ |
282,614 |
|
|
$ |
435,678 |
|
|
$ |
573,355 |
|
|
$ |
825,102 |
|
Operating Income (Loss)(1) |
$ |
95,118 |
|
|
$ |
169,255 |
|
|
$ |
151,653 |
|
|
$ |
319,895 |
|
Operating Income (Loss) Net of Realized Hedging(1)(2) |
$ |
90,522 |
|
|
$ |
103,549 |
|
|
$ |
125,002 |
|
|
$ |
206,543 |
|
Operating Netback ($/boe)(1) |
$ |
32.23 |
|
|
$ |
57.51 |
|
|
$ |
24.05 |
|
|
$ |
52.26 |
|
Operating Netback Net of Realized Hedging ($/boe)(1)(2) |
$ |
30.67 |
|
|
$ |
35.18 |
|
|
$ |
19.82 |
|
|
$ |
33.74 |
|
Capital expenditures |
$ |
41,432 |
|
|
$ |
51,191 |
|
|
$ |
67,794 |
|
|
$ |
82,120 |
|
THERMAL OIL DIVISION |
|
|
|
|
|
|
|
|
|
|
|
Bitumen production (bbl/d) (1) |
|
29,016 |
|
|
|
26,768 |
|
|
|
29,097 |
|
|
|
27,335 |
|
Petroleum, natural gas and midstream sales |
$ |
265,304 |
|
|
$ |
399,793 |
|
|
$ |
534,406 |
|
|
$ |
760,074 |
|
Operating Income (Loss)(1) |
$ |
81,621 |
|
|
$ |
131,067 |
|
|
$ |
123,118 |
|
|
$ |
251,904 |
|
Operating Netback ($/bbl)(1) |
$ |
32.64 |
|
|
$ |
55.68 |
|
|
$ |
22.97 |
|
|
$ |
51.17 |
|
Capital expenditures |
$ |
29,912 |
|
|
$ |
43,093 |
|
|
$ |
52,748 |
|
|
$ |
64,275 |
|
LIGHT OIL DIVISION |
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
4,955 |
|
|
|
6,479 |
|
|
|
5,228 |
|
|
|
6,623 |
|
Percentage Liquids (%)(1) |
55 |
% |
|
58 |
% |
|
56 |
% |
|
57 |
% |
Petroleum, natural gas and midstream sales |
$ |
24,006 |
|
|
$ |
53,825 |
|
|
$ |
53,895 |
|
|
$ |
98,933 |
|
Operating Income (Loss)(1) |
$ |
13,497 |
|
|
$ |
38,188 |
|
|
$ |
28,535 |
|
|
$ |
67,991 |
|
Operating Netback ($/boe)(1) |
$ |
29.92 |
|
|
$ |
64.77 |
|
|
$ |
30.16 |
|
|
$ |
56.72 |
|
Capital expenditures |
$ |
10,753 |
|
|
$ |
1,221 |
|
|
$ |
12,629 |
|
|
$ |
9,208 |
|
CASH FLOW AND FUNDS FLOW |
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities |
$ |
46,914 |
|
|
$ |
68,535 |
|
|
$ |
67,451 |
|
|
$ |
128,397 |
|
per share - basic |
$ |
0.08 |
|
|
$ |
0.12 |
|
|
$ |
0.11 |
|
|
$ |
0.23 |
|
Adjusted Funds Flow(1) |
$ |
81,664 |
|
|
$ |
84,799 |
|
|
$ |
72,268 |
|
|
$ |
159,560 |
|
per share - basic |
$ |
0.14 |
|
|
$ |
0.15 |
|
|
$ |
0.12 |
|
|
$ |
0.29 |
|
Free Cash Flow (1) |
$ |
40,232 |
|
|
$ |
33,608 |
|
|
$ |
4,474 |
|
|
$ |
77,440 |
|
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) |
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) and comprehensive income (loss) |
$ |
57,121 |
|
|
$ |
47,121 |
|
|
$ |
486 |
|
|
$ |
(72,480 |
) |
per share - basic |
$ |
0.10 |
|
|
$ |
0.08 |
|
|
$ |
0.00 |
|
|
$ |
(0.13 |
) |
per share - diluted(3) |
$ |
0.07 |
|
|
$ |
0.08 |
|
|
$ |
0.00 |
|
|
$ |
(0.13 |
) |
COMMON SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
592,223,832 |
|
|
|
568,728,441 |
|
|
|
589,442,937 |
|
|
|
550,013,742 |
|
Weighted average shares outstanding - diluted |
|
616,789,101 |
|
|
|
585,934,027 |
|
|
|
600,470,217 |
|
|
|
550,013,742 |
|
|
June 30, |
|
December 31, |
|
As at ($ Thousands) |
2023 |
|
2022 |
|
LIQUIDITY AND BALANCE SHEET |
|
|
|
|
|
|
Cash and cash equivalents |
$ |
132,491 |
|
$ |
197,525 |
|
Available credit facilities(4) |
$ |
87,838 |
|
$ |
87,838 |
|
Face value of term debt(5) |
$ |
214,267 |
|
$ |
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 $4.6 million
and $26.7 million for the three and six months ended June 30, 2023
(three and six months ended June 30, 2022 – loss of $65.7 million
and $113.4 million). |
(3) |
In the calculation of dilutive earnings per share for the three
months ended June 30, 2023, 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 June 30, 2023 was US$162 million
(December 31, 2022 – US$175 million) translated into Canadian
dollars at the June 30, 2023 exchange rate of US$1.00 = C$1.3240
(December 31, 2022 – C$1.3544). |
Operations Update
Thermal Oil
Bitumen production for the second quarter of
2023 averaged 29,016 bbl/d. The Thermal Oil division generated
Operating Income of $82 million ($33.79/bbl at Leismer and
$29.20/bbl at Hangingstone) during the period with capital
expenditures of $30 million, primarily related to drilling
operations and progressing the facility expansion at Leismer.
Leismer
At Leismer, four new well pairs at Pad L8M were
placed on production in early June supporting production of ~24,000
bbl/d with a current steam oil ratio (“SOR”) of less than 3x. The
fifth new well pair on Pad L8M is scheduled to be placed on
production in early August. The five well pairs are expected to
ramp-up to ~6,000 bbl/d over six months and maintain a stable
production profile for approximately five years. During the
quarter, drilling commenced on the final four well pairs at Pad L8S
and four infill wells on Pad L7. These wells have been rig released
ahead of schedule and surface facilities are expected be completed
this fall. Preliminary drilling results confirm consistent high
quality sands. These additional new wells are expected to 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 Company is
able to leverage existing excess steam capacity and has been
proactive in acquiring long lead equipment. The project is budgeted
at a competitive capital efficiency of ~$14,000/bbl/d and is
expected to enhance margins by ~$5/bbl from current levels through
increased operating scale. 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 2027 (US$85 WTI, US$12.50 WCS differential).
Hangingstone
At Hangingstone, initial work on the Pad AA
extension has begun in anticipation of drilling two future
sustaining well pairs in 2024 to maintain base production.
Non-condensable gas co-injection continues to aid in pressure
support and reduced energy usage. Hangingstone’s SOR averaged 3.6x
in the first half of 2023. Cost initiatives completed since 2020
and the lower SOR supported a $29.20/bbl Operating Netback during
the quarter.
Light Oil
Production for the second quarter of 2023
averaged 4,955 boe/d (55% Liquids). The Light Oil division
generated Operating Income of $14 million ($29.92/boe) during the
period with capital expenditures of $11 million. Activity was
focused on operational readiness in advance of the upcoming
drilling season.
In the Duvernay oil window at Kaybob East and
Two Creeks the Company has extended production history from 27
wells de-risking an inventory of 290 gross future locations. The
wells have consistently supported the Company’s type curve
expectations with IP365’s averaging ~550 boe/d per well, ~85%
Liquids (latest 12 wells since 2020), demonstrating the significant
potential of the asset.
The Light Oil land position has no near‐term
expiries and is ready for future development with ~850 gross
Montney and Duvernay locations.
Light Oil operations were temporarily affected
by the Alberta wildfires in the second quarter of 2023. As a
precautionary measure Athabasca shut-in its facilities temporarily
for a portion of May. No damage was sustained to well sites or
infrastructure and production was fully restored in June.
Business Environment &
Outlook
Global oil benchmarks have weakened year over
year as global recession concerns weighed on commodities. However,
the war in Ukraine has amplified the emphasis on energy security
and sanctions continue to alter energy flows across the globe.
Athabasca maintains a constructive outlook on oil prices supported
by years of industry underinvestment, OPEC+ cuts and demand trends
moving higher.
Canadian WCS heavy differentials narrowed
significantly in the second quarter with differentials improving to
US$15.08/bbl, compared to US$24.77/bbl in the first quarter of
2023. The supply-demand outlook for heavy barrels is expected to be
supported by the continued OPEC+ production cuts, the start-up of
the Trans Mountain Expansion pipeline (590,000 bbl/d) and the
start-up of new global heavy oil refining capacity, specifically
Pemex’s Dos Bocas 340,000 bbl/d refinery. These factors are
expected to improve the strength of WCS prices into the second half
of 2023 and 2024.
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; 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 700 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. The 290 gross Duvernay drilling
locations at Kaybob East and Two Creeks referenced include: 5
proved undeveloped locations and 59 probable undeveloped locations
for a total of 64 booked locations with the balance being unbooked
locations. The 150 gross Montney drilling locations referenced
include: 48 proved undeveloped locations and 50 probable
undeveloped locations for a total of 98 booked locations with the
balance being unbooked locations. Proved undeveloped locations and
probable undeveloped locations are booked and derived from the
Company's most recent independent reserves evaluation as prepared
by McDaniel as of December 31, 2022 and account for drilling
locations that have associated proved and/or probable reserves, as
applicable. Unbooked locations are internal management estimates.
Unbooked locations do not have attributed reserves or resources
(including contingent or prospective). Unbooked locations have been
identified by management as an estimation of Athabasca’s multi-year
drilling activities expected to occur over the next two decades
based on evaluation of applicable geologic, seismic, engineering,
production and reserves information. There is no certainty that the
Company will drill all unbooked drilling locations and if drilled
there is no certainty that such locations will result in additional
oil and gas reserves, resources or production. The drilling
locations on which the Company will actually drill wells, including
the number and timing thereof is ultimately dependent upon the
availability of funding, commodity prices, provincial fiscal and
royalty policies, costs, actual drilling results, additional
reservoir information that is obtained and other factors.
Non-GAAP and Other Financial Measures,
and Production Disclosure
The "Adjusted Funds Flow", “Adjusted Funds Flow
per Share”, “Free Cash Flow”, "Light Oil Operating Income", "Light
Oil Operating Netback", "Thermal Oil Operating Income", "Thermal
Oil Operating Netback", “Consolidated Operating Income",
"Consolidated Operating Netback", "Consolidated Operating Income
Net of Realized Hedging", "Consolidated Operating Netback Net of
Realized Hedging", “Cash Transportation & Marketing Expenses”,
“Excess Cash Flow” and “Sustaining Capital” financial measures
contained in this News Release do not have standardized meanings
which are prescribed by IFRS and they are considered to be non-GAAP
financial measures or ratios. These measures may not be comparable
to similar measures presented by other issuers and should not be
considered in isolation with measures that are prepared in
accordance with IFRS. “Net Debt” 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
endedJune 30, |
|
Six months
endedJune 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Cash flow from operating activities |
$ |
46,914 |
|
$ |
68,535 |
|
$ |
67,451 |
|
$ |
128,397 |
|
Changes in non-cash working capital |
|
34,630 |
|
|
16,353 |
|
|
16,600 |
|
|
30,706 |
|
Settlement of provisions |
|
120 |
|
|
(89 |
) |
|
794 |
|
|
457 |
|
Long-term deposit |
|
- |
|
|
- |
|
|
(12,577 |
) |
|
- |
|
ADJUSTED FUNDS FLOW |
|
81,664 |
|
|
84,799 |
|
|
72,268 |
|
|
159,560 |
|
Capital expenditures |
|
(41,432 |
) |
|
(51,191 |
) |
|
(67,794 |
) |
|
(82,120 |
) |
FREE CASH FLOW |
$ |
40,232 |
|
$ |
33,608 |
|
$ |
4,474 |
|
$ |
77,440 |
|
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
endedJune 30, |
|
Six months
endedJune 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Petroleum and natural gas sales |
$ |
24,006 |
|
$ |
53,825 |
|
$ |
53,895 |
|
$ |
98,933 |
|
Royalties |
|
(1,337 |
) |
|
(5,610 |
) |
|
(6,893 |
) |
|
(11,479 |
) |
Operating expenses |
|
(7,095 |
) |
|
(7,743 |
) |
|
(14,024 |
) |
|
(14,722 |
) |
Transportation and marketing |
|
(2,077 |
) |
|
(2,284 |
) |
|
(4,443 |
) |
|
(4,741 |
) |
LIGHT OIL OPERATING INCOME |
$ |
13,497 |
|
$ |
38,188 |
|
$ |
28,535 |
|
$ |
67,991 |
|
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
endedJune 30, |
|
Six months
endedJune 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Heavy oil (blended bitumen) and midstream sales |
$ |
265,304 |
|
$ |
399,793 |
|
$ |
534,406 |
|
$ |
760,074 |
|
Cost of diluent |
|
(114,430 |
) |
|
(141,685 |
) |
|
(263,363 |
) |
|
(281,596 |
) |
Total bitumen and midstream sales |
|
150,874 |
|
|
258,108 |
|
|
271,043 |
|
|
478,478 |
|
Royalties |
|
(10,944 |
) |
|
(55,911 |
) |
|
(17,557 |
) |
|
(88,407 |
) |
Operating expenses |
|
(39,605 |
) |
|
(51,442 |
) |
|
(87,374 |
) |
|
(96,938 |
) |
Cash transportation and marketing(1) |
|
(18,704 |
) |
|
(19,688 |
) |
|
(42,994 |
) |
|
(41,229 |
) |
THERMAL OIL OPERATING INCOME |
$ |
81,621 |
|
$ |
131,067 |
|
$ |
123,118 |
|
$ |
251,904 |
|
(1) Cash transportation and
marketing excludes non-cash costs of $0.6 million and $1.1 million
for the three and six months ended June 30, 2023 (three and six
months ended June 30, 2022 - $0.6 million and $1.1 million).
Consolidated Operating Income and Consolidated
Operating Income Net of Realized Hedging and Operating Netbacks
The non-GAAP measures of Consolidated Operating
Income including or excluding realized hedging in this News Release
are calculated by adding or subtracting realized gains (losses) on
commodity risk management contracts (as applicable), royalties, the
cost of diluent blending, operating expenses and cash
transportation & marketing expenses from petroleum, natural gas
and midstream sales which is the most directly comparable GAAP
measure. The Consolidated Operating Netbacks including or excluding
realized hedging per boe are non-GAAP ratios calculated by dividing
Consolidated Operating Income including or excluding hedging by the
total sales volumes and are presented on a per boe basis. The
Consolidated Operating Income and Consolidated Operating Netbacks
including or excluding realized hedging measures allow management
and others to evaluate the production results from the Company’s
Light Oil and Thermal Oil assets combined together including the
impact of realized commodity risk management gains or losses (as
applicable).
|
Three months
endedJune 30, |
|
Six months
endedJune 30, |
|
($ Thousands) |
2023 |
|
2022 |
|
2023 |
|
2022 |
|
Petroleum, natural gas and midstream sales(1) |
$ |
289,310 |
|
$ |
453,618 |
|
$ |
588,301 |
|
$ |
859,007 |
|
Royalties |
|
(12,281 |
) |
|
(61,521 |
) |
|
(24,450 |
) |
|
(99,886 |
) |
Cost of diluent(1) |
|
(114,430 |
) |
|
(141,685 |
) |
|
(263,363 |
) |
|
(281,596 |
) |
Operating expenses |
|
(46,700 |
) |
|
(59,185 |
) |
|
(101,398 |
) |
|
(111,660 |
) |
Cash transportation and marketing(2) |
|
(20,781 |
) |
|
(21,972 |
) |
|
(47,437 |
) |
|
(45,970 |
) |
Operating Income |
|
95,118 |
|
|
169,255 |
|
|
151,653 |
|
|
319,895 |
|
Realized gain (loss) on commodity risk management contracts |
|
(4,596 |
) |
|
(66,706 |
) |
|
(26,651 |
) |
|
(113,352 |
) |
OPERATING INCOME NET OF REALIZED HEDGING |
$ |
90,522 |
|
$ |
103,549 |
|
$ |
125,002 |
|
$ |
206,543 |
|
(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 $1.1 million for the
three and six months ended June 30, 2023 (three and six months
ended June 30, 2022 - $0.6 million and $1.1 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 Debt
Net Debt 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,
and excluding risk management contracts.
Liquidity
Liquidity is defined as cash and cash equivalents plus available credit capacity.
Production volumes details
|
Three months
endedJune 30, |
|
Six months
endedJune 30, |
Production |
2023 |
|
2022 |
|
2023 |
|
2022 |
Greater Placid: |
|
|
|
|
|
|
|
|
Condensate NGLs |
bbl/d |
720 |
|
1,002 |
|
767 |
|
1,051 |
Other NGLs |
bbl/d |
350 |
|
384 |
|
376 |
|
410 |
Natural gas(1) |
mcf/d |
9,563 |
|
11,337 |
|
9,650 |
|
11,750 |
Total Greater Placid |
boe/d |
2,664 |
|
3,275 |
|
2,752 |
|
3,419 |
|
|
|
|
|
|
|
|
|
Greater Kaybob: |
|
|
|
|
|
|
|
|
Oil(2) |
bbl/d |
1,412 |
|
2,019 |
|
1,493 |
|
1,995 |
Other NGLs |
bbl/d |
249 |
|
353 |
|
284 |
|
338 |
Natural gas(1) |
mcf/d |
3,782 |
|
4,988 |
|
4,198 |
|
5,224 |
Total Greater Kaybob |
boe/d |
2,291 |
|
3,204 |
|
2,476 |
|
3,204 |
|
|
|
|
|
|
|
|
|
Light Oil: |
|
|
|
|
|
|
|
|
Oil(2) |
bbl/d |
1,412 |
|
2,019 |
|
1,493 |
|
1,995 |
Condensate NGLs |
bbl/d |
720 |
|
1,002 |
|
767 |
|
1,051 |
Oil and condensate NGLs |
bbl/d |
2,132 |
|
3,021 |
|
2,260 |
|
3,046 |
Other NGLs |
bbl/d |
599 |
|
737 |
|
660 |
|
748 |
Natural gas(1) |
mcf/d |
13,345 |
|
16,325 |
|
13,848 |
|
16,974 |
Total Light Oil division |
boe/d |
4,955 |
|
6,479 |
|
5,228 |
|
6,623 |
Total Thermal Oil division bitumen |
bbl/d |
29,016 |
|
26,768 |
|
29,097 |
|
27,335 |
Total Company production |
boe/d |
33,971 |
|
33,247 |
|
34,325 |
|
33,958 |
(1) Comprised of 99% or greater
of shale gas, with the remaining being conventional natural gas.
(2) Comprised of 99% or greater of tight oil, with
the remaining being light and medium crude oil
This News Release also makes reference to
Athabasca's forecasted total average daily production of 34,500 –
36,000 boe/d for 2023. Athabasca expects that ~86% of that
production will be comprised of bitumen, ~6% shale gas, ~4% tight
oil, ~2% condensate natural gas liquids and ~2% other natural gas
liquids.
This News Release makes reference to Athabasca's
latest 12 wells at Kaybob East and Two Creeks have seen average
productivity of ~550 boe/d IP365s (85% Liquids), which is comprised
of ~80% tight oil, ~15% shale gas and ~5% NGLs.
Liquids is defined as bitumen, light crude oil,
medium crude oil and natural gas liquids.
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