Athabasca Oil Corporation (TSX: ATH) (“Athabasca” or the “Company”)
is pleased to report its 2021 third quarter results. Record
financial results during the quarter, including $57 million of Free
Cash Flow, demonstrate the quality of Athabasca’s asset base and
unique positioning in the current oil price environment.
Q3 Highlights
- Production:
~34,250 boe/d including ~26,700 bbl/d in Thermal Oil and ~7,500
boe/d in Light Oil.
- Record Operating
Income: $121 million ($36/boe) driven by strong oil prices
and 90% Liquids weighting. Record Operating Netback of $36/bbl in
Thermal Oil.
- Capital
Expenditures: $16 million focused on high-value Leismer
projects to sustain production.
- Record
Funds Flow: Adjusted Funds Flow of $72 million ($0.14 per
share) and Free Cash Flow of $57 million.
Recent Operational
Highlights
- Leismer: Current
production of ~19,000 bbl/d has been supported by the tie-in of the
L6 infills and an additional well pair on Pad L7. Pad L8 commenced
steaming in October, with first oil expected in early 2022. The
five well pairs are anticipated to ramp-up to >5,000 bbl/d in
mid-2022.
- Hangingstone:
Expanded NCG co-injection has supported field pressure management
with current production of ~9,000 bbl/d. Optimization projects have
yielded a significantly lower cost structure driving a $33/bbl
Operating Netback in Q3.
- Light Oil: Focused
on free cash flow generation with continued strong Operating
Netback of $37/boe.
- Carbon
Capture (CCUS): Continuing to advance a scoping study with
Entropy Inc. to determine feasibility of a carbon capture at
Leismer with ongoing evaluation of local storage and carbon
trunkline options.
2021 Guidance and Outlook (Strip Pricing
October 4)1
- Production:
increased annual guidance to ~34,250 boe/d (previously 32,000 –
34,000 boe/d).
- Capital: an
unchanged ~$100 million annual capital program primarily directed
towards Leismer.
- Financial:
Adjusted EBITDA ~$255 million; ~$190 million Adjusted Funds Flow;
~$90 million Free Cash Flow.
- Balance Sheet:
Resilient and refinanced balance sheet with no term debt maturities
until Q4 2026 and strong liquidity of ~$265 million, including
~$195 million cash (2021e year-end).
- Compelling Leverage
Metrics: Net Debt to Adjusted EBITDA of ~0.8x (2021e
year-end). The Company anticipates being in a net cash position in
2023.
- 2022 Budget:
Anticipated to be released in December. Activity will be focused on
sustaining base production and maximizing free cash flow
generation.
“Athabasca has taken deliberate steps to
reposition the portfolio over the past number of years,” said
Robert Broen, President and CEO. “The quarterly results and outlook
validate the Company’s enviable position in the current
environment. The recent balance sheet refinancing provides us
significant strategic flexibility. We remain steadfast in our
capital allocation priorities and have a clear path to net zero
leverage in 2023. Reduced cash flow volatility, consistent
operational execution and a best-in-class balance sheet is expected
to unlock significant shareholder value through this period and
beyond.”
Strategic Outlook
-
Managing for Strong Free Cash Flow: Athabasca
intends to maximize free cash flow while maintaining its production
base. The Company forecasts >$600 million in Free Cash Flow
(US$70 WTI & US$12.50 WCS differentials) during the 3-year
timeframe of 2022 – 2024.
-
Clear Debt Reduction Targets: The Company will
direct at least 75% of future free cash flow towards achieving a
total outstanding term debt reduction of US$175 million (50%
reduction) while maintaining a strong liquidity position. The
Company is targeting to achieve this target and to be in a net cash
position in 2023. Debt reduction utilizing free cash flow,
permitted under the new term note, will commence semi-annually with
the first repayment in May 2022 (for the period Q4 2021 – Q1
2022).
-
Maintain Annual Corporate Production: The
portfolio of long reserve life assets under-pins a low corporate
decline rate of ~10%. Athabasca requires low sustaining capital of
~$125 million annually to maintain production. The Company retains
a large portfolio of future investment opportunities.
Business Environment
Commodity prices continue to strengthen as the
world has emerged from the COVID-19 pandemic and the recovery in
oil demand continues to outpace the growth in supply. Global oil
demand is set to exceed pre-pandemic levels in 2022 and inventories
are below the 5-year average. The OPEC+ supply agreement is
expected to keep the market in a deficit and guidance for higher
capacity will be needed in coming years given growing
under-investment (Goldman Sachs Commodity Research).
In Alberta, physical markets and regional
benchmark prices (e.g. Western Canadian Select “WCS” heavy oil)
have improved with higher WTI prices. Athabasca expects current WCS
differentials to remain stable with muted industry growth and
improving basin egress, including the recently completed Enbridge
Line 3 replacement. There is strong demand for heavy oil from US
Gulf Coast refineries as they face structural declines in global
heavy oil supply (Venezuela and Mexico). Athabasca believes
conditions have emerged for WCS heavy oil to be among the most
valuable global crude benchmarks.
Balance Sheet and Risk Management
Update
On October 22, 2021, Athabasca announced the
closing of US$350 million of 5-year Senior Secured Notes (“New
Notes”) and a $110 million reserve based credit facility. The
refinanced capital structure provides certainty to shareholders of
the Company’s ability to utilize free cash flow to further reduce
debt and enhance long-term resiliency.
The Company estimates 2021 year-end liquidity of
~$265 million (including ~$195 million of cash) with a 2021 Net
Debt to Adjusted EBITDA of 0.8x (US$67.50 WTI & US$12.50 WCS
differentials). The New Notes provide Athabasca the ability to
further reduce debt in the near-term by utilizing at least 75% of
free cash flow semi-annually to retire notes at 105% of face value.
The Company is targeting to be in a net cash position in 2023.
Athabasca has commenced its 2022 hedging
programing which includes 13,500 bbl/d of fixed WCS swaps at an
average price of ~US$54 (implied WTI of ~US$66.50 assuming a
US$12.50 WCS differential). These swaps fully protect the
sustaining capital program down to ~US$50 WTI. Additional hedges
are anticipated to include collars and puts to strategically
balance downside protection while maintaining upside exposure to
the current price environment.
Financial and Operational Highlights
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
|
($ Thousands, unless otherwise noted) |
2021 |
|
2020 |
|
2021 |
|
2020 |
|
CONSOLIDATED |
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
34,255 |
|
|
32,061 |
|
|
34,439 |
|
|
31,896 |
|
Operating Income (Loss)(1) |
$ |
120,581 |
|
$ |
50,171 |
|
$ |
279,705 |
|
$ |
11,574 |
|
Operating Income (Loss) Net of Realized Hedging(1)(2) |
$ |
92,742 |
|
$ |
42,812 |
|
$ |
212,929 |
|
$ |
50,076 |
|
Operating Netback ($/boe)(1) |
$ |
36.02 |
|
$ |
17.19 |
|
$ |
29.54 |
|
$ |
1.29 |
|
Operating Netback Net of Realized Hedging ($/boe)(1)(2) |
$ |
27.70 |
|
$ |
14.67 |
|
$ |
22.49 |
|
$ |
5.61 |
|
Capital expenditures |
$ |
15,608 |
|
$ |
12,381 |
|
$ |
73,790 |
|
$ |
94,438 |
|
Capital Expenditures Net of Capital-Carry(1) |
$ |
15,608 |
|
$ |
12,381 |
|
$ |
73,790 |
|
$ |
71,698 |
|
Free Cash Flow(1) |
$ |
56,625 |
|
$ |
2,236 |
|
$ |
67,632 |
|
$ |
(101,178 |
|
THERMAL OIL DIVISION |
|
|
|
|
|
|
|
|
|
|
|
|
Bitumen production (bbl/d) |
|
26,729 |
|
|
20,231 |
|
|
26,374 |
|
|
22,043 |
|
Operating Income (Loss)(1) |
$ |
94,796 |
|
$ |
26,844 |
|
$ |
204,532 |
|
$ |
(30,886 |
) |
Operating Netback ($/bbl)(1) |
$ |
35.71 |
|
$ |
14.66 |
|
$ |
28.16 |
|
$ |
(4.98 |
) |
Capital expenditures |
$ |
15,228 |
|
$ |
10,454 |
|
$ |
69,630 |
|
$ |
32,872 |
|
LIGHT OIL DIVISION |
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas production (boe/d)(1) |
|
7,526 |
|
|
11,830 |
|
|
8,065 |
|
|
9,853 |
|
Percentage Liquids (%)(1) |
55% |
|
62% |
|
56% |
|
61% |
|
Operating Income (Loss)(1) |
$ |
25,785 |
|
$ |
23,327 |
|
$ |
75,173 |
|
$ |
42,460 |
|
Operating Netback ($/boe)(1) |
$ |
37.25 |
|
$ |
21.43 |
|
$ |
34.15 |
|
$ |
15.73 |
|
Capital expenditures |
$ |
128 |
|
$ |
1,917 |
|
$ |
1,640 |
|
$ |
61,534 |
|
Capital Expenditures Net of Capital-Carry(1) |
$ |
128 |
|
$ |
1,917 |
|
$ |
1,640 |
|
$ |
38,794 |
|
CASH FLOW AND FUNDS FLOW |
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operating activities |
$ |
75,743 |
|
$ |
(4,782 |
) |
$ |
113,064 |
|
$ |
(38,989 |
) |
per share - basic |
$ |
0.14 |
|
$ |
(0.01 |
) |
$ |
0.21 |
|
$ |
(0.07 |
) |
Adjusted Funds Flow(1) |
$ |
72,233 |
|
$ |
14,617 |
|
$ |
141,422 |
|
$ |
(29,480 |
) |
per share - basic |
$ |
0.14 |
|
$ |
0.03 |
|
$ |
0.27 |
|
$ |
(0.06 |
) |
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) and comprehensive income (loss) |
$ |
104,951 |
|
$ |
(18,818 |
) |
$ |
73,535 |
|
$ |
(600,634 |
) |
per share - basic |
$ |
0.20 |
|
$ |
(0.04 |
) |
$ |
0.14 |
|
$ |
(1.14 |
) |
per share - diluted |
$ |
0.19 |
|
$ |
(0.04 |
) |
$ |
0.14 |
|
$ |
(1.14 |
) |
COMMON SHARES OUTSTANDING |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding - basic |
|
530,675,391 |
|
|
530,675,391 |
|
|
530,675,391 |
|
|
528,220,593 |
|
Weighted average shares outstanding - diluted |
|
547,618,860 |
|
|
530,675,391 |
|
|
544,597,372 |
|
|
528,220,593 |
|
|
|
|
September 30, |
|
December 31, |
|
As at ($ Thousands) |
|
|
2021 |
|
2020 |
|
LIQUIDITY AND BALANCE SHEET |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
$ |
273,989 |
|
$ |
165,201 |
|
Restricted cash |
|
|
$ |
46,107 |
|
$ |
135,624 |
|
Available credit facilities(3) |
|
|
$ |
3,568 |
|
$ |
348 |
|
Face value of long-term debt, including current portion(4) |
|
|
$ |
573,345 |
|
$ |
572,940 |
|
(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 $27.8 million and $66.8 million for the three
and nine months ended September 30, 2021 (three and nine months
ended September 30, 2020 - $7.4 million loss and $38.5 million
gain). |
(3) |
Includes available credit under
Athabasca's Credit Facility and Unsecured Letter of Credit Facility
(see page 13 of the Q3 MD&A). |
(4) |
The face value of the 2022 Notes
is US$450 million. The 2022 Notes were translated into Canadian
dollars at the September 30, 2021 exchange rate of US$1.00 =
C$1.2741 (December 31, 2020 – C$1.2732). |
Operations Update
Thermal Oil
Bitumen production for Q3 2021 averaged 26,729
bbl/d. The Thermal Oil division generated Operating Income of $94.8
million and capital expenditures were $15.2 million. Operating
Netbacks for Leismer and Hangingstone were a record $37.09/bbl and
$32.92/bbl, respectively.
Leismer
Bitumen production for Q3 2021 averaged 18,023
bbl/d. Production has increased over Q2 volumes following the
tie-in of two L6 infills and L7P6 in late June and Leismer is
currently producing ~19,000 bbl/d.
The Company has significantly advanced the
completion of Pad 8. Facility construction was completed in October
and steam circulation has commenced ahead of schedule. First
production is anticipated in early 2022. The initial five well
pairs on Pad L8 are expected to ramp-up in excess of 5,000 bbl/d in
mid-2022. The existing pipeline will support future development for
a total of 14 well pairs on Pad L8. Preparations are underway for
drilling operations to commence on the next sustaining pad in
2022.
Hangingstone
Bitumen production for Q3 2021 averaged 8,706
bbl/d. Reservoir performance through 2021 has been strong as a
result of excellent facility run time and the implementation of NCG
co-injection aiding in pressure build-up and reduced energy usage.
Production is expected to be supported by an additional well pair
(AA03) that is currently steaming and will be placed on production
in November.
Light Oil
Q3 production averaged 7,526 boe/d (55% liquids)
in Q3 2021. The division generated Operating Income of $25.8
million ($37.25/boe) and capital expenditures were $0.1 million.
Athabasca’s Light Oil netback continues to be top tier when
compared to Alberta’s other liquids-rich Montney and Duvernay
resource producers and are supported by a high liquids weighting
and low operating expenses.
At Greater Placid, production averaged 4,205
boe/d (44% liquids) with an Operating Netback of $30.02/boe. The
asset is positioned for flexible future development with an
inventory of ~150 gross drilling locations and no near-term land
retention requirements.
At Greater Kaybob, production averaged 3,321
boe/d (69% liquids) with an Operating Netback of $46.38/boe.
Production results have been consistently strong with wells
screening as top liquids producers in the basin. Athabasca’s latest
12 wells at Kaybob East and Two Creeks have average IP180s of ~725
boe/d (85% liquids) and IP365s of ~550 boe/d (83% liquids). Strong
well results coupled with a large well inventory (~700 gross
drilling locations) and flexible development timing indicate
significant value to Athabasca. The Kaybob area is supported by a
strong Joint Development Agreement, established infrastructure and
no near-term land retention requirements. The Company remains
encouraged by competitor activity and recent new entrants into the
play.
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”, “forecast”, “continue”, “estimate”, “expect”,
“may”, “will”, “project”, “target”, “should”, “believe”, “predict”,
“pursue”, “potential”, “view” and “contemplate” and similar
expressions 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 and, except as required by applicable securities laws,
the Company undertakes no obligation to update any forward-looking
statement to reflect events or circumstances after the date on
which such statement is made or to reflect the occurrence of
unanticipated events. In particular, this News Release contains
forward-looking information pertaining to, but not limited to, the
following: our strategic plans and Free Cash Flow potential;
expected capital programs to maintain production; the Company’s
2021 Outlook, including expected unrestricted cash, EBITDA, funds
flow, net debt, production outlook and capital budget; EBITDA
sensitivity; future debt levels and composition; timing of Leismer
well on stream dates and expected benefits therefrom; our drilling
plans in Leismer and L8 project economics; timing for first oil
from new well pair at Hangingstone; expectations for WCS heavy oil
to be amongst the most valuable global crude benchmarks; target net
debt to Adjusted EBITDA; and other matters.
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 and sustaining capital 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
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, 2020 (which is respectively referred to herein as the "McDaniel
Report”).
Actual results could differ materially from
those anticipated in this forward-looking information as a result
of the risk factors set forth in the Company’s Annual Information
Form (“AIF”) dated March 3, 2021 and Management’s Discussion and
Analysis dated November 3, 2021, 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; continued impact
of the COVID-19 pandemic; ability to finance capital requirements;
climate change and carbon pricing risk; regulatory environment and
changes in applicable law; gathering and processing facilities,
pipeline systems and rail; statutes and regulations regarding the
environment; political uncertainty; state of capital markets;
anticipated benefits of acquisitions and dispositions; abandonment
and reclamation costs; changing demand for oil and natural gas
products; royalty regimes; foreign exchange rates and interest
rates; reserves; hedging; operational dependence; operating costs;
project risks; 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; 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.
Also included in this News Release are estimates
of Athabasca's 2021 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 financial outlook
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 financial outlook, 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 in this
News Release 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, 2020. 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. 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.
The 700 Duvernay (Greater Kaybob) drilling
locations referenced include: 7 proved undeveloped locations and 78
probable undeveloped locations for a total of 85 booked locations
with the balance being unbooked locations. The 150 Montney drilling
(Greater Placid) locations referenced include: 63 proved
undeveloped locations and 35 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, 2020 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 Financial Measures and
Production Disclosure
The "Adjusted Funds Flow”, "Light Oil Operating
Income", “Light Oil Operating Netback”, “Placid Operating Netback”,
Kaybob Operating Netback”, “Light Oil Capital Expenditures Net of
Capital‐Carry”, "Thermal Oil Operating Income (Loss)", "Thermal Oil
Operating Netback", “Consolidated Operating Income”, “Consolidated
Operating Netback”, “Consolidated Operating Income Net of Realized
Hedging”, “Consolidated Operating Netback Net of Realized Hedging”,
“Consolidated Capital Expenditures Net of Capital‐Carry”, “Adjusted
EBITDA”, “Net Debt” and “Free Cash Flow” 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
measures. 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.
The “Advisories and Other Guidance” section within the Company’s Q3
2021 MD&A includes reconciliations of these measures, where
applicable, to the nearest IFRS measures.
Adjusted Funds Flow is not intended to represent
cash flow from operating activities, net earnings or other measures
of financial performance calculated in accordance with IFRS.
Adjusted Funds Flow is calculated by adjusting for changes in
non-cash working capital, restructuring expenses and settlement of
provisions from cash flow from operating activities. The Adjusted
Funds Flow measure allows 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 calculated as Adjusted Funds Flow divided by the applicable
number of weighted average shares outstanding.
The Operating Income (Loss) measures in this
News Release are calculated by subtracting the cost of diluent,
royalties, operating expenses and cash transportation &
marketing expenses from petroleum, natural gas and midstream sales.
The Operating Netback measures are calculated by dividing the
respective projects Operating Income (Loss) by its respective sales
volumes and is presented on a per boe basis. The Operating Income
(Loss) and the Operating Netback measures allow management and
others to evaluate the production results from the Company’s
assets.
The Consolidated Operating Income (Loss) Net of
Realized Hedging measure in this News Release is calculated by
adding or subtracting realized gains (losses) on commodity risk
management contracts, royalties, cost of diluent, operating
expenses and cash transportation & marketing expenses from
petroleum, natural gas and midstream sales. The Consolidated
Operating Netback Net of Realized Hedging measure is calculated by
dividing Consolidated Operating Income (Loss) Net of Realized
Hedging by the total sales volumes and is presented on a per boe
basis. The Consolidated Operating Income (Loss) Net of Realized
Hedging and the Consolidated Operating Netback Net of 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.
The Consolidated Capital Expenditures Net of
Capital-Carry and Light Oil Capital Expenditures Net of
Capital-Carry measures in this News Release are outlined in the
Company’s Q3 2021 MD&A. These measures allow management and
others to evaluate the true net cash outflow related to Athabasca's
capital expenditures.
Net Debt is defined as face value of term debt
plus accounts payable and accrued liabilities plus current portion
of provisions and other liabilities less current assets.
Adjusted EBITDA is defined as Net income (loss)
and comprehensive income (loss) before financing and interest
expense, depreciation, depletion, impairment and taxation
(recovery) expense adjusted for unrealized foreign exchange gain
(loss), unrealized gain (loss) on risk management contracts, gain
(loss) on revaluation of provisions and other, gain (loss) on sale
of assets and non-cash stock-based compensation.
The Free Cash Flow measure in this News Release
is calculated by subtracting Capital Expenditures Net of
Capital-Carry from Adjusted Funds Flow. This measure allows
management and others to evaluate Athabasca's ability to generate
funds to finance operations and capital expenditures.
Liquidity is defined as cash and cash
equivalents plus available credit capacity.
Term Debt is defined as the face value of the
New Notes.
Production volumes details
|
|
Three months
endedSeptember 30, |
|
Nine months
endedSeptember 30, |
Production |
|
2021 |
|
2020 |
2021 |
|
|
|
2020 |
Light Oil: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil(1) |
bbl/d |
|
1,984 |
|
3,685 |
|
|
2,258 |
|
|
3,208 |
Condensate NGLs |
bbl/d |
|
1,312 |
|
2,612 |
|
|
1,430 |
|
|
2,005 |
Oil and condensate NGLs |
bbl/d |
|
3,296 |
|
6,297 |
|
|
3,688 |
|
|
5,213 |
Other NGLs |
bbl/d |
|
846 |
|
964 |
|
|
862 |
|
|
785 |
Natural gas(2) |
mcf/d |
|
20,304 |
|
27,414 |
|
|
21,087 |
|
|
23,129 |
Total Light Oil division |
boe/d |
|
7,526 |
|
11,830 |
|
|
8,065 |
|
|
9,853 |
Total Thermal Oil division bitumen |
bbl/d |
|
26,729 |
|
20,231 |
|
|
26,374 |
|
|
22,043 |
Total Company production |
boe/d |
|
34,255 |
|
32,061 |
|
|
34,439 |
|
|
31,896 |
(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 total average daily production of 34,250
boe/d for 2021. Athabasca expects that approximately 78% of that
production will be comprised of bitumen, 10% shale gas, 6% tight
oil, 4% condensate natural gas liquids and 2% other natural gas
liquids.
Liquids is defined as bitumen, tight oil, light
crude oil, medium crude oil and natural gas liquids.
Additionally, this News Release makes reference
to Athabasca's well results in Two Creeks and Kaybob East that have
seen average productivity of ~725 boe/d IP180s (85% Liquids), which
is comprised of ~80% tight oil, ~15% shale gas and ~5% NGLs, and
~550 boe/d (83% Liquids) IP365s, which is comprised of ~78% tight
oil, ~17% shale gas and ~5% NGLs.
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