Crew Energy Inc. (TSX: CR; OTCQB: CWEGF) (“Crew” or the “Company”),
a growth-oriented, liquids rich natural gas producer operating in
the world-class Montney play in northeast British Columbia (“NE
BC”), is pleased to announce our operating and financial results
for the three and nine month periods ended September 30, 2023.
Crew’s Financial Statements and Notes, as well as Management’s
Discussion and Analysis (“MD&A”) are available on our website
and filed on SEDAR at www.sedar.com.
HIGHLIGHTS
-
26,834 boe per day1 (161 mmcfe per day) average
production in Q3/23 was in-line with previous quarterly guidance of
26,000 to 28,000 boe per day and reflects the impact of shutting-in
production for offsetting completion operations, planned
third-party gas plant maintenance and the shut-down of the Septimus
gas plant for the installation of condensate stabilization and
waste heat recovery. Production for the first nine months of 2023
averaged 29,925 boe per day1.
-
125,729 mmcf per day of natural gas production in
Q3/23 represented 78% of total production and
45% of sales.
-
3,839 bbls per day of condensate and light crude
oil production in Q3/23 represented 14% of total
production and 48% of sales.
-
2,040 bbls per day of natural gas liquids5,6
(“ngls”) production in Q3/23 represented 8% of
total production and 7% of sales.
-
$45.3 million of Adjusted Funds Flow (“AFF”)2
($0.28 per fully diluted share3) was generated in Q3/23, driven by
robust operating netbacks4 that benefited from a 17% increase in
Crew’s realized commodity price over the previous quarter, while
AFF2 for the first nine months of 2023 totaled $178.9 million
($1.11 per fully diluted share).
-
Operating netbacks4 averaged $19.95 per
boe in Q3/23 and $23.75 per boe in the first nine months
of the year, including realized hedging gains of $2.48 per boe and
$5.43 per boe, respectively.
-
$104.0 million of net capital expenditures4 was
invested in Q3/23 at Greater Septimus, compared to $120
million at the midpoint of guidance, and included the
drilling of eight Ultra Condensate Rich (“UCR”) natural gas wells
and one disposal well, the completion of six UCR natural gas wells
and one disposal well, in addition to advancing several
infrastructure projects including condensate stabilization and
waste heat recovery at the Septimus gas plant.
-
$124.6 million in net debt2 at quarter-end
reflects an active capital program in the period, with a net debt
to last 12 months’ EBITDA ratio3 of < 0.5x.
-
Credit facility increased after quarter-end, to
$250 million from $200 million,
providing additional liquidity to finance Crew’s future capital
investments.
-
$10.12 cash costs per boe4 in Q3/23 were 5% higher
than Q2/23, reflecting the impact of shut-in production volumes
which drove higher per unit net operating costs4 ($4.79 per boe)
and net transportation costs4 ($3.74 per boe), partially offset by
reduced interest costs. In the first nine months of 2023, cash
costs per boe4 improved slightly over the same period in 2022,
totaling $9.72 per boe.
-
After quarter-end, Crew received a permit from the
B.C. Energy Regulator (“BCER”) approving the construction of our
planned 180 mmcf per day Groundbirch gas plant as well as 60 well
authorization permits, bringing our total to 85 well
authorizations in the Groundbirch area.
FINANCIAL & OPERATING
HIGHLIGHTS
|
FINANCIAL ($ thousands, except per share
amounts) |
Three monthsendedSept. 30,
2023 |
|
Three monthsendedSept. 30, 2022 |
|
Nine monthsendedSept. 30,
2023 |
|
Nine months endedSept. 30, 2022 |
|
|
Petroleum and natural gas sales |
70,317 |
|
132,950 |
|
237,621 |
|
461,621 |
|
| Cash provided by
operating activities |
46,056 |
|
82,322 |
|
182,652 |
|
254,767 |
|
| Adjusted funds
flow2 |
45,313 |
|
69,417 |
|
178,865 |
|
262,351 |
|
|
Per share3 – basic |
0.29 |
|
0.46 |
|
1.16 |
|
1.72 |
|
|
– diluted |
0.28 |
|
0.43 |
|
1.11 |
|
1.62 |
|
| Net
income |
4,878 |
|
105,658 |
|
79,961 |
|
192,926 |
|
|
Per share – basic |
0.03 |
|
0.69 |
|
0.52 |
|
1.27 |
|
|
– diluted |
0.03 |
|
0.65 |
|
0.49 |
|
1.19 |
|
| Property, plant and
equipment expenditures |
104,045 |
|
53,560 |
|
163,863 |
|
115,982 |
|
|
Net property dispositions4 |
(20) |
|
(129,983) |
|
(1,016) |
|
(129,983) |
|
|
Net capital expenditures4 |
104,025 |
|
(76,423) |
|
162,847 |
|
(14,001) |
|
|
Capital Structure($ thousands) |
As at Sept. 30, 2023 |
|
As at Dec. 31, 2022 |
|
|
Working capital (deficiency) surplus2 |
(57,672) |
|
21,844 |
|
| Other long-term
obligations |
(18,223) |
|
- |
|
| Bank loan |
(48,683) |
|
- |
|
| Senior
unsecured notes |
- |
|
(171,298) |
|
|
Net debt2 |
(124,578) |
|
(149,454) |
|
|
Common shares outstanding (thousands) |
154,478 |
|
154,377 |
|
|
OPERATIONAL |
|
|
Three monthsendedSept. 30,
2023 |
Three monthsendedSept. 30, 2022 |
Nine monthsendedSept. 30,
2023 |
Nine months endedSept. 30, 2022 |
|
|
Daily production |
|
|
|
|
|
|
|
|
Light crude oil (bbl/d)7 |
|
|
85 |
83 |
77 |
102 |
|
|
Condensate (bbl/d) |
|
|
3,754 |
4,731 |
3,996 |
4,745 |
|
|
Natural gas liquids5,6 (bbl/d) |
|
|
2,040 |
2,692 |
2,244 |
2,884 |
|
|
Conventional natural gas (mcf/d) |
|
|
125,729 |
145,715 |
141,647 |
154,041 |
|
|
Total (boe/d @ 6:1) |
|
|
26,834 |
31,792 |
29,925 |
33,405 |
|
| Average
realized3 |
|
|
|
|
|
|
|
|
Light crude oil price ($/bbl) |
|
|
94.38 |
104.30 |
87.80 |
114.75 |
|
|
Condensate price ($/bbl) |
|
|
96.25 |
106.15 |
94.73 |
118.27 |
|
|
Natural gas liquids price ($/bbl) |
|
|
26.46 |
41.30 |
29.59 |
46.52 |
|
|
Natural gas price ($/mcf) |
|
|
2.71 |
5.65 |
2.96 |
6.39 |
|
|
Commodity price ($/boe) |
|
|
28.48 |
45.46 |
29.09 |
50.62 |
|
|
|
Three monthsendedSept. 30,
2023 |
|
Three monthsendedSept. 30, 2022 |
|
Nine monthsendedSept. 30,
2023 |
|
Nine months endedSept. 30, 2022 |
|
|
Netback ($/boe) |
|
|
|
|
|
Petroleum and natural gas sales |
28.48 |
|
45.46 |
|
29.09 |
|
50.62 |
|
|
Royalties |
(2.49 |
) |
(6.86 |
) |
(2.91 |
) |
(4.51 |
) |
|
Realized gain (loss) on derivative financial instruments |
2.48 |
|
(4.63 |
) |
5.43 |
|
(7.52 |
) |
|
Net operating costs4 |
(4.79 |
) |
(4.12 |
) |
(4.39 |
) |
(3.71 |
) |
|
Net transportation costs4 |
(3.74 |
) |
(3.42 |
) |
(3.47 |
) |
(3.29 |
) |
|
Operating netback4 |
19.95 |
|
26.43 |
|
23.75 |
|
31.59 |
|
|
General and administrative (“G&A”) |
(1.14 |
) |
(0.99 |
) |
(1.13 |
) |
(0.92 |
) |
|
Interest expenses on debt4 |
(0.45 |
) |
(1.70 |
) |
(0.73 |
) |
(1.90 |
) |
|
Adjusted funds flow2 |
18.36 |
|
23.74 |
|
21.89 |
|
28.77 |
|
________________________1 See table in the
Advisories for production breakdown by product type as defined in
NI 51-101.2 Capital management measure that does not have any
standardized meaning as prescribed by International Financial
Reporting Standards, and therefore, may not be comparable with the
calculations of similar measures for other entities. See
“Advisories – Non-IFRS and Other Financial Measures” contained
within this press release.3 Supplementary financial measure that
does not have any standardized meaning as prescribed by
International Financial Reporting Standards, and therefore, may not
be comparable with the calculations of similar measures for other
entities. See “Advisories – Non-IFRS and Other Financial Measures”
contained within this press release.4 Non-IFRS financial measure or
ratio that does not have any standardized meaning as prescribed by
International Financial Reporting Standards, and therefore, may not
be comparable with calculations of similar measures or ratios for
other entities. See “Advisories – Non-IFRS and Other Financial
Measures” contained within this press release and in our most
recently filed MD&A, available on SEDAR at www.sedar.com.5
Throughout this news release, ngls comprise all natural gas liquids
as defined in National Instrument 51-101, Standards of Disclosure
for Oil and Gas Activities (“NI 51-101”), other than condensate,
which is disclosed separately, and natural gas means conventional
natural gas by NI 51-101 product type.6 Excludes condensate volumes
which have been reported separately.7 Throughout this news release,
light crude oil refers to light and medium crude oil product type
as defined by National Instrument 51-101 Standards of Disclosure
for Oil and Gas Activities (“NI 51-101”).
EXTENSIVE DRILLING INVENTORY AND
UNTAPPED GROWTH POTENTIAL
-
Our Montney land base represents an expansive, contiguous and
ideally situated asset that we believe can propel Crew into the
next phase of growth.
-
With balance sheet strength and financial flexibility, Crew is in
an advantageous position that offers significant optionality across
targeted geological zones, commodity mix, transportation egress and
markets for our products. This affords the Company multiple levers
to respond to macro-economic factors as well as corporate
developments.
-
Commodity mix optionality was demonstrated during Q3/23 as the
Company pivoted to drill condensate-rich/light oil targets
comprising 14% of total production and 48% of total sales, that
provide superior returns to natural gas in the current environment.
Based on current forward curve pricing, Crew’s focus on
condensate-rich drilling targets is expected to continue into
2024.
-
Medium to longer-term, the Company’s multi-zone development
opportunities underpin an internally identified drilling inventory
estimated to include over 2,500 net potential drilling locations8
across Montney layers at Groundbirch, Monias, Greater Septimus and
Tower, with the potential to support a significantly larger
production base.
-
From a market access perspective, Crew has a strategically
positioned resource with extensive end-market optionality for our
products. The Company’s operations are proximal to the Coastal Gas
Link Pipeline; have access to multiple Canadian and US sales hubs;
benefit from potential coastal liquids egress with our proximity to
the CN Rail line; and are ideally positioned for the anticipated
start-up of LNG Canada in 2025, the country's first liquified
natural gas (“LNG”) export terminal located on the coast of
BC.
-
The possibility of increased demand due to Canada’s future LNG
export capabilities provides a supportive backdrop for the
potential to increase our productive capacity to over 60,000 boe
per day, pending expansion of our gas processing infrastructure.
-
Groundbirch development depends on several key factors including
securing additional pipeline and well permitting, a supportive
commodity price and capital cost environment and requisite
financing that would enable Crew to retain an adequate level of
liquidity through the project while maintaining conservative debt
leverage metrics.
-
Ongoing volatility in natural gas markets has continued to impact
current spot and future strip prices, and the Company continues to
monitor price movements that signal additional hedging
opportunities. Active exploration of a variety of project financing
options is also underway while additional regulatory approvals are
pending.
________________________8 See “Drilling Locations” in the
Advisories.
OPERATIONS UPDATE & AREA OVERVIEW
NE BC Montney (Greater
Septimus)
- During Q3/23, Crew
drilled six (6.0 net) wells at our 1-24 pad, two (2.0 net) wells on
the North Septimus 7-18 UCR pad and one (1.0 net) disposal well at
West Septimus. Further, we completed five (5.0 net) UCR wells at
the 4-32 pad, the last well on our 11-27 pad and one disposal well
at Greater Septimus.
- Over the first 30
days on production (“IP30”), five (5.0 net) UCR natural gas wells
which were completed on the 4-32 pad have produced average wellhead
rates of 2,207 mcf per day of natural gas and 953 bbls per day of
condensate.
- Key infrastructure
projects in the Greater Septimus area continued to progress during
Q3/23, including the completion of the condensate stabilization and
waste heat recovery projects at Crew’s Septimus gas plant, which
are expected to increase the plant’s condensate capacity from 1,000
to 5,000 bbls per day and facilitate expanded development of our
UCR area while reducing GHG emissions intensity. We also continued
to advance the electrification of infrastructure at West
Septimus.
- Crew has been
notified by a third party pipeline operator that a sales pipeline
is expected to be shutdown for maintenance for an estimated 10 days
during Q4/23. Approximately 7,400 boe per day of production is
estimated to be affected by the shutdown, or 800 boe per day when
averaged over Q4/23.
Groundbirch
-
Crew recently received final BCER approval for the 180 mmcf per day
Groundbirch gas plant and 60 additional well authorization permits
near the initial 4-17 pad development, taking the total well
authorizations at Groundbirch to 85.
-
Detailed design and long lead items procurement is progressing for
Crew’s proposed Groundbirch plant which would expand our gas
processing infrastructure, supporting the Company’s longer range
plans to double current production following commissioning.
-
The original three (3.0 net) wells on the 4-17 pad have produced an
average of 3.59 bcf of natural gas over the first 600 days,
exceeding our independent reserve evaluator’s year-end 2022 proved
plus probable type curve by approximately 33% to date.
-
The five (5.0 net) extended reach horizontal (“ERH”) wells in the
second phase of development at Crew’s 4-17 pad with a three-zone
development continue to exceed internal type curve estimates, with
an average per well raw gas production rate over 365 days (“IP365”)
of 5,432 mcf per day, averaging 1.94 bcf of natural gas per well
which is in line with our independent reserve evaluator’s year-end
2022 proved plus probable, 12 bcf type curve.
Other NE BC Montney
- The
Company has six (6.0 net) drilled ERH wells on the 15-28 pad at
Tower. Of these wells, four (4.0 net) Upper Montney “B’ wells are
planned to be completed in Q1/24 and the remaining two (2.0 net)
Upper Montney “C” wells are scheduled for completion in Q4/24 or
Q1/25. The wells were drilled to target light oil and feature
lateral lengths of over 4,000 meters.
RISK MANAGEMENT PROFILE
To secure a base level of AFF2 to fund planned
capital projects, Crew continues to utilize hedging to limit
exposure to fluctuations in commodity prices and foreign exchange
rates, while allowing for participation in spot commodity
prices.
As of November 8, 2023, our hedging profile
includes:
-
2023
-
Approximately 46,667 GJ per day of natural gas at C$4.40 per GJ for
the remainder of 2023, or C$5.37 per mcf using Crew’s higher heat
content factor;
-
1,750 bbls per day of condensate at an average price of C$102.58
per bbl for the remainder of 2023; and
-
1,000 bbls per day of WTI at an average price of C$104.36 per bbl
for Q4/23.
-
2024
-
2,500 GJ per day of natural gas at C$2.76 per GJ or C$3.37 per mcf
using Crew’s heat factor;
-
2,000 bbls per day of condensate at an average price of C$104.04
per bbl for 1st half 2024;
-
1,750 bbls per day of condensate at an average price of C$104.01
per bbl for 2nd half 2024;
-
1,000 bbls per day of WTI at C$106.09 per bbl for Q1 2024;
-
500 bbls per day of WTI at C$112.00 per bbl for Q2 2024; and
-
250 bbls per day of WTI at C$110.50 per bbl for 2nd half 2024.
SUSTAINABILITY AND ESG FOCUS
Our commitment to environmental, social and
governance (“ESG”) initiatives remained a key focus in Q3/23 and is
an integral component of our long-term sustainability. We continued
to invest in clean solutions designed to complement our operational
and financial growth. Highlights of our various ESG-focused
initiatives in Q3/23 include:
-
For the first time in Crew’s history, 1,000,000
person hours of work were executed to the end of Q3/23
without a single recordable injury. We are
extremely proud of the dedicated team at Crew who have demonstrated
this unprecedented level of commitment to undertake work both
safely and efficiently.
-
Crew continued to strive for top-tier emissions intensity through
the successful implementation of waste heat recovery at our
Septimus gas plant, and the use of re-spoolable produced water
transfer, with over 185,000 m3 transferred during the third
quarter, removing over 160,000 kilometers of truck traffic and
preventing approximately 470 tonnes of CO2e emissions.
-
Achieved re-certification under the Equitable Origin EO100 standard
for responsible energy development in September 2023.
-
The Company maintains a comprehensive water management strategy
that includes stringent planning related to water usage and
responsible sourcing, which ensures highly efficient water
utilization across our operations, while optimizing recycling and
treatment to reduce the use of freshwater.
-
Directed a total of $0.5 million to abandonment and reclamation
activities.
- Invested
153 volunteer hours to date in 2023 as part of our “Crew Cares”
initiative and made financial contributions into community support
initiatives and not-for-profit organizations, largely geared
towards fostering the health, well-being and resilience of our
local communities and their economies.
OUTLOOK
- 2023
Guidance – Since April of 2023, Crew has been utilizing a
high-spec triple drilling rig which has led to efficiency
improvements and cost savings given in-field rig moves and the
continuity in employing both the same rig and crews to drill our
wells. Given that these specialized rigs are in high demand, Crew
plans to continue drilling with this rig into 2024. As such, we
have brought forward approximately $20 million of 2024 capital and
increased our 2023 capital expenditure budget to a range of $220 to
$230 million by drilling an additional five (5.0 net) wells over
and above the Q2/23 budget update, in addition to paying deposits
on long lead items for the planned electrification of our West
Septimus and proposed Groundbirch gas plants.
- As outlined above,
Crew has been notified by a third party pipeline operator of an
estimated 10 day shutdown for maintenance of a sales pipeline,
affecting an estimated 7,400 boe per day of production, or an
average of 800 boe per day over Q4/23.
- Crew’s updated 2023
annual net capital investment program is forecasted to deliver the
following:
- Generate 2023
average production of 30,000 to
31,000 boe per day1, which reflects the above
mentioned third party pipeline shutdown anticipated in Q4/23;
- Increase light oil
and condensate production to reach over 7,000 bbls per
day in Q4/23;
- Drill a total of
22 (22.0 net) liquids rich
Montney wells, representing an increase of five (5.0 net) wells
from our Q2 budget update, and drill one disposal well;
- Complete
12 (12.0 net) wells and equip and
place on production 12 (12.0 net) UCR wells, which is one (1.0 net)
fewer well than indicated in the Q2/23 budget update and one (1.0
net) horizontal water disposal well; and
- Maintain an
inventory of 17 (17.0 net) drilled and uncompleted
Montney wells at year end 2023, representing a 55% increase from
the 11 (11.0 net) wells outlined in our Q2 2023 budget update.
-
Q4 Outlook – Net capital expenditures4 in Q4/23
are forecast at $60 to $70
million with average production of 30,000
to 32,000 boe per day1. Our Q4/23 capital program
includes plans to:
- Complete six (6.0
net) UCR wells; and
- Drill nine (9.0
net) Montney wells.
-
2024 Preliminary Outlook – The Company’s
anticipated 2024 capital expenditures are expected to focus on
developing our high value, liquids-rich natural gas
assets at Septimus and West Septimus along with
progressing further electrification and expansion of our gas
processing facilities, all of which are designed to support the
successful execution of Crew’s growth plan. Crew plans on releasing
our 2024 annual budget early in 2024.
The following table sets forth Crew’s revised and updated
guidance and underlying material assumptions:
|
|
Previous 2023 Guidanceand Assumptions |
Updated 2023 Guidance and
Assumptions9 |
|
Net capital expenditures4 ($Millions) |
190-210 |
220-230 |
|
Annual average production1 (boe/d) |
30,000–32,000 |
30,000–31,000 |
|
Adjusted funds flow2 ($Millions) |
240-260 |
240-260 |
|
Free adjusted funds flow4 ($Millions) |
30-70 |
10-40 |
|
EBITDA4 ($Millions) |
250-270 |
250-270 |
|
Oil price (WTI)($US per bbl) |
75.00 |
79.00 |
|
Natural gas price (NYMEX) ($US per mmbtu) |
3.20 |
2.75 |
|
Natural gas price (AECO 5A) ($C per mcf) |
2.85 |
2.75 |
|
Natural gas price (Crew est. wellhead) ($C per mcf) |
3.30 |
2.95 |
|
Foreign exchange ($US/$CAD) |
0.74 |
0.74 |
|
Royalties |
9–11% |
9–11% |
|
Net operating costs4 ($ per boe) |
4.50–5.00 |
4.50–5.00 |
|
Net transportation costs4 ($ per boe) |
3.50–4.00 |
3.50–4.00 |
|
G&A ($ per boe) |
1.00–1.20 |
1.00–1.20 |
|
Effective interest rate on long-term debt |
6.5–7.5% |
6.5–7.5% |
|
Updated 2023 guidance and material assumptions in the table above
reflect actuals for the nine months ended September 30, 2023 and
forecasts for the three months ended December 31, 2023. Selected
forecasts for the three months ended December 31, 2023 are as
follows: |
|
Oil price (WTI)($US per bbl) |
85.00 |
|
Natural gas price (NYMEX) ($US per mmbtu) |
3.00 |
|
Natural gas price (AECO 5A) ($C per mcf) |
2.70 |
|
Natural gas price (Crew est. wellhead) ($C per mcf) |
2.85 |
|
|
|
Crew intends to continue upholding our
commitment to operational excellence through safe and responsible
execution, while maintaining financial flexibility that we believe
will drive ongoing success over both the near and longer-term
horizons. We extend our appreciation to all the Company’s
stakeholders for their trust, confidence and ongoing support of
Crew while we unlock value from our exciting Montney asset
base.
________________________9 The actual results of
operations of Crew and the resulting financial results will likely
vary from the estimates and material underlying assumptions set
forth in this guidance by the Company and such variation may be
material. The guidance and material underlying assumptions have
been prepared on a reasonable basis, reflecting management's best
estimates and judgments.
ADVISORIES
Forward-Looking Information and
Statements
This news release contains certain
forward–looking information and statements within the meaning of
applicable securities laws. The use of any of the words "expect",
"anticipate", "continue", "estimate", "may", "will", "project",
"should", "believe", "plans", "intends" “forecast” “targets” and
similar expressions are intended to identify forward-looking
information or statements. In particular, but without limiting the
foregoing, this news release contains forward-looking information
and statements pertaining to the following: the ability to execute
on its Four-Year Plan and underlying strategy, plans, goals and
targets, all as more particularly outlined and described in this
press release; our 2023 annual and Q4 capital budget range (the
"2023 Budget"), associated drilling, completion and infrastructure
plans, the anticipated timing thereof, and all associated near term
initiatives, goals and targets, along with all guidance and
underlying assumptions related to the 2023 Budget as outlined in
the “Outlook” section in this press release; preliminary 2024 plans
as outlined in the “Outlook” section in this press release;
production and type-curve estimates and targets under the 2023
Budget and balance of the Four-Year Plan; infrastructure plans and
anticipated benefits outlined in this press release including
construction of the Groundbirch plant and anticipated benefits
thereof including associated longer range plans to double our
production; completion of the Company’s waste heat recovery and
condensate stabilization projects at its Septimus Gas Plant and
anticipated benefits thereof; the planned conversion of our West
Septimus gas processing facility to electric drive and anticipated
timing and benefits thereof; anticipated timing, costs and assumed
receipt of all regulatory approvals required in connection
therewith; our ability to secure financing for the Groundbirch
plant and timing thereof; continued improvement in debt and
leverage metrics; commodity price expectations and assumptions;
Crew's commodity risk management programs and future hedging plans;
marketing and transportation and processing plans and requirements;
estimates of processing capacity and requirements; estimated
potential drilling locations; anticipated reductions in GHG
emissions and decommissioning obligations; future liquidity and
financial capacity and ability to finance our Four-Year Plan;
future results from operations and operating and leverage metrics;
targeted debt levels and leverage metrics over the course of the
Four-Year Plan; world supply and demand projections and long-term
impact on pricing; future development, exploration, acquisition,
disposition and infrastructure activities (including our capital
investment model through 2026 and associated drilling and
completion plans, associated receipt of all required regulatory
permits for our Four-Year Plan, development timing and cost
estimates); the potential to serve a Canadian LNG market including
the anticipated start-up of LNG-Canada in 2025; the potential of
our Groundbirch area to be a core area of future development for
potentially decades, and the anticipated commerciality of up to
four potential prospective zones to be drilled; the successful
implementation of our ESG initiatives as set forth herein and in
our updated ESG Report; and significant emissions intensity
improvements going forward; the amount and timing of capital
projects; and anticipated improvement in our long-term
sustainability and the expected positive attributes discussed
herein attributable to our Four-Year Plan.
The internal projections, expectations, or
beliefs underlying our Board approved 2023 Budget and associated
guidance, as well as management's preliminary strategy, and
associated plans, goals and targets in respect of the balance of
its Four-Year Plan, are subject to change in light of, without
limitation, the Russia/Ukraine conflict, war in the middle east and
any related actions taken by businesses and governments, ongoing
results, prevailing economic circumstances, volatile commodity
prices, resulting changes in our underlying assumptions, goals and
targets provided herein and changes in industry conditions and
regulations. Crew's financial outlook and guidance provides
shareholders with relevant information on management's expectations
for results of operations, excluding any potential acquisitions or
dispositions, for such time periods based upon the key assumptions
outlined herein. In this press release reference is made to the
Company's longer range 2024 and beyond internal plan and associated
economic model. Such information reflects internal goals and
targets used by management for the purposes of making capital
investment decisions and for internal long-range planning and
future budget preparation. Readers are cautioned that events or
circumstances and updates to underlying assumptions could cause
capital plans and associated results to differ materially from
those predicted and Crew's guidance for 2023, and more particularly
its internal plan, goals and targets for 2024 and beyond which are
not based upon Board approved budget(s) at this time, may not be
appropriate for other purposes. Accordingly, undue reliance should
not be placed on same.
In addition, forward-looking statements or
information are based on several material factors, expectations or
assumptions of Crew which have been used to develop such statements
and information, but which may prove to be incorrect. Although Crew
believes that the expectations reflected in such forward-looking
statements or information are reasonable, undue reliance should not
be placed on forward-looking statements because Crew can give no
assurance that such expectations will prove to be correct. In
addition to other factors and assumptions which may be identified
herein, assumptions have been made regarding, among other things:
that Crew will continue to conduct its operations in a manner
consistent with past operations; results from drilling and
development activities consistent with past operations; the quality
of the reservoirs in which Crew operates and continued performance
from existing wells; the continued and timely development of
infrastructure in areas of new production; the accuracy of the
estimates of Crew’s reserve volumes; certain commodity price and
other cost assumptions; continued availability of debt and equity
financing and cash flow to fund Crew’s current and future plans and
expenditures; the impact of increasing competition; the general
stability of the economic and political environment in which Crew
operates; that future business, regulatory and industry conditions
will be within the parameters expected by Crew; the general
continuance of current industry conditions; the timely receipt of
any required regulatory approvals; the ability of Crew to obtain
qualified staff, equipment and services in a timely and cost
efficient manner; drilling results; the ability of the operator of
the projects in which Crew has an interest in to operate the field
in a safe, efficient and effective manner; the ability of Crew to
obtain financing on acceptable terms; field production rates and
decline rates; the ability to replace and expand oil and natural
gas reserves through acquisition, development and exploration; the
timing and cost of pipeline, storage and facility construction and
expansion and the ability of Crew to secure adequate product
transportation; future commodity prices; currency, exchange and
interest rates; regulatory framework regarding royalties, taxes,
environmental and indigenous matters in the jurisdictions in which
Crew operates; that regulatory authorities in British Columbia
continue granting approvals for oil and gas activities on time
frames, and on terms and conditions, consistent with past
practices; and the ability of Crew to successfully market its oil
and natural gas products.
The forward-looking information and statements
included in this news release are not guarantees of future
performance and should not be unduly relied upon. Such information
and statements, including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors
that may cause actual results or events to defer materially from
those anticipated in such forward-looking information or statements
including, without limitation: the continuing and uncertain impact
of pandemics; the Russia / Ukraine conflict and war in the middle
east; changes in commodity prices; changes in the demand for or
supply of Crew's products, the early stage of development of some
of the evaluated areas and zones and the potential for variation in
the quality of the Montney formation; interruptions, unanticipated
operating results or production declines; changes in tax or
environmental laws, royalty rates; climate change regulations, or
other regulatory matters; changes in development plans of Crew or
by third party operators of Crew's properties, increased debt
levels or debt service requirements; inaccurate estimation of
Crew's oil and gas reserve volumes and identified drilling
inventory; limited, unfavourable or a lack of access to capital
markets; increased costs; a lack of adequate insurance coverage;
the impact of competitors; and certain other risks detailed from
time-to-time in Crew's public disclosure documents (including,
without limitation, those risks identified in this news release and
Crew's MD&A and Annual Information Form).
This press release contains future-oriented
financial information and financial outlook information
(collectively, "FOFI") about Crew's prospective capital
expenditures and associated guidance, all of which are subject to
the same assumptions, risk factors, limitations, and qualifications
as set forth in the above paragraphs. The actual results of
operations of Crew and the resulting financial results will likely
vary from the amounts set forth in this press release and such
variation may be material. Crew and its management believe that the
FOFI has been prepared on a reasonable basis, reflecting
management's best estimates and judgments. However, because this
information is subjective and subject to numerous risks, it should
not be relied on as necessarily indicative of future results.
Except as required by applicable securities laws, Crew undertakes
no obligation to update such FOFI. FOFI contained in this press
release was made as of the date of this press release and was
provided for the purpose of providing further information about
Crew's anticipated future business operations. Readers are
cautioned that the FOFI contained in this press release should not
be used for purposes other than for which it is disclosed
herein.
The forward-looking information and statements
contained in this news release speak only as of the date of this
news release, and Crew does not assume any obligation to publicly
update or revise any of the included forward-looking statements or
information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities
laws.
Risk Factors to the Company’s Four-Year
Plan
Risk factors that could materially impact
successful execution and actual results of the Four-Year Plan
include:
- volatility of
petroleum and natural gas prices and inherent difficulty in the
accuracy of predictions related thereto;
- changes in Federal
and Provincial regulations;
- execution of
construction timelines from BC Hydro to support the electrification
of the Groundbirch plant;
- receipt of
high-value regulatory permits required to launch development under
the Four-Year Plan;
- the Company’s
ability to secure financing for the Groundbirch plant sourced from
AFF, bank or other Debt instruments, asset sales, equity issuance,
infrastructure financing or some combination thereof; and
- Those additional
risk factors set forth in the Company’s MD&A and most recent
Annual Information Form filed on SEDAR.
Information Regarding Disclosure on Oil
and Gas Operational Information
All amounts in this news release are stated in
Canadian dollars unless otherwise specified. This press release
contains metrics commonly used in the oil and natural gas industry.
Each of these metrics are determined by Crew as specifically set
forth in this news release. These terms do not have standardized
meanings or standardized methods of calculation and therefore may
not be comparable to similar measures presented by other companies,
and therefore should not be used to make such comparisons. Such
metrics have been included to provide readers with additional
information to evaluate the Company’s performance however, such
metrics are not reliable indicators of future performance and
therefore should not be unduly relied upon for investment or other
purposes. See "Non-IFRS and Other Financial Measures" below for
additional disclosures.
Drilling Locations
This press release discloses internally
identified “potential drilling locations” which are comprised of:
(i) proved locations; (ii) probable locations; and (iii) unbooked
locations. Proved locations and probable locations are derived from
the Company’s independent reserve evaluator’s report effective
December 31, 2022 (the “Sproule Report”) and account for drilling
inventory that have associated proved and/or probable reserves
assigned by Sproule. Unbooked locations are internally identified
potential drilling opportunities based on the Company's prospective
acreage and an assumption as to the number of wells that can be
drilled per section based on industry practice and internal review.
Unbooked locations do not have reserves or resources attributed to
them and are not estimates of drilling locations which have been
evaluated by a qualified reserves evaluator performed in accordance
with the COGE Handbook. There is no certainty that the Company will
drill any of these potential drilling opportunities 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 we actually drill wells will ultimately depend
upon the availability of capital, regulatory approvals, seasonal
restrictions, oil and natural gas prices, costs, actual drilling
results, additional reservoir information that is obtained and
other factors.
The following table provides a detailed breakdown of the
identified gross potential drilling locations presented herein:
|
|
Total DrillingLocations |
Proved Locations |
Probable Locations |
UnbookedLocations |
|
|
Montney Total Drilling Locations |
2,537 |
110 |
77 |
2,350 |
|
| Groundbirch Locations |
1,717 |
19 |
28 |
1,670 |
|
| West Septimus Locations |
483 |
45 |
41 |
397 |
|
| Septimus Locations |
191 |
46 |
5 |
140 |
|
| Tower
Locations |
146 |
- |
3 |
143 |
|
The above Proved and Probable locations reflect
locations booked in the December 31, 2022 Sproule Report of Crew’s
year-end reserves, internally adjusted to reflect Crew’s 2023
drilling program to the end of Q3 2023. In the first nine months of
2023, the Company has drilled 11 Proved and 0 Probable locations
leaving a total of 187 total Proved and Probable locations
booked.
Test Results and Initial Production
Rates
A pressure transient analysis or well-test
interpretation has not been carried out and thus certain of the
test results provided herein should be preliminary until such
analysis or interpretation has been completed. Test results and
initial production (“IP”) rates disclosed herein, particularly
those short in duration, may not necessarily be indicative of
long-term performance or of ultimate recovery.
BOE and Mcfe Conversions
Measurements expressed in barrel of oil
equivalents, BOEs or Mcfe may be misleading, particularly if used
in isolation. A BOE conversion ratio of 6 mcf: 1 bbl and an Mcfe
conversion ratio of 1 bbl:6 Mcf are based on an energy equivalency
conversion method primarily applicable at the burner tip and do not
represent a value equivalency at the wellhead. Given that the value
ratio based on the current price of crude oil as compared to
natural gas is significantly different than the energy equivalency
of 6:1, utilizing the 6:1 conversion ratio may be misleading as an
indication of value.
Non-IFRS and Other Financial
Measures
Throughout this press release and other
materials disclosed by the Company, Crew uses certain measures to
analyze financial performance, financial position and cash flow.
These non-IFRS and other specified financial measures do not have
any standardized meaning prescribed under IFRS and therefore may
not be comparable to similar measures presented by other entities.
The non-IFRS and other specified financial measures should not be
considered alternatives to, or more meaningful than, financial
measures that are determined in accordance with IFRS as indicators
of Crew’s performance. Management believes that the presentation of
these non-IFRS and other specified financial measures provides
useful information to shareholders and investors in understanding
and evaluating the Company’s ongoing operating performance, and the
measures provide increased transparency and the ability to better
analyze Crew’s business performance against prior periods on a
comparable basis.
Capital Management Measures
a) Funds from
Operations and Adjusted Funds FlowFunds from operations
represents cash provided by operating activities before changes in
operating non-cash working capital, accretion of deferred financing
charges and transaction costs on property dispositions. Adjusted
funds flow represents funds from operations before decommissioning
obligations settled (recovered). The Company considers these
metrics as key measures that demonstrate the ability of the
Company’s continuing operations to generate the cash flow necessary
to maintain production at current levels and fund future growth
through capital investment and to service and repay debt.
Management believes that such measures provide an insightful
assessment of the Company's operations on a continuing basis by
eliminating certain non-cash charges, actual settlements of
decommissioning obligations and transaction costs on property
dispositions, the timing of which is discretionary. Funds from
operations and adjusted funds flow should not be considered as an
alternative to or more meaningful than cash provided by operating
activities as determined in accordance with IFRS as an indicator of
the Company’s performance. Crew’s determination of funds from
operations and adjusted funds flow may not be comparable to that
reported by other companies. Crew also presents adjusted funds flow
per share whereby per share amounts are calculated using weighted
average shares outstanding consistent with the calculation of
income per share. The applicable reconciliation to the most
directly comparable measure, cash provided by operating activities,
is contained under “free adjusted funds flow” below.
b) Net Debt and Working
Capital Surplus (Deficiency)Crew closely monitors its
capital structure with a goal of maintaining a strong balance sheet
to fund the future growth of the Company. The Company monitors net
debt as part of its capital structure. The Company uses net debt
(bank debt plus working capital deficiency or surplus, excluding
the current portion of the fair value of financial instruments) as
an alternative measure of outstanding debt. Management considers
net debt and working capital deficiency (surplus) an important
measure to assist in assessing the liquidity of the Company.
Non-IFRS Financial Measures and
Ratios
a) Net
Property Acquisitions (Dispositions)Net property
acquisitions (dispositions) equals property acquisitions less
property dispositions and transaction costs on property
dispositions. Crew uses net property acquisitions (dispositions) to
measure its total capital investment compared to the Company’s
annual capital budgeted expenditures. The most directly comparable
IFRS measures to net property acquisitions (dispositions) are
property acquisitions and property dispositions.
b) Net Capital
ExpendituresNet capital expenditures equals property,
plant and equipment expenditures less net property acquisitions
(dispositions). Crew uses net capital expenditures to measure its
total capital investment compared to the Company’s annual capital
budgeted expenditures. The most directly comparable IFRS measure to
net capital expenditures is property, plant and equipment
expenditures.
|
($ thousands) |
Three months ended Sept.
30, 2023 |
|
Three months ended June 30, 2023 |
|
Three months ended Sept. 30, 2022 |
|
Nine months ended Sept.
30, 2023 |
|
Nine months ended Sept. 30, 2022 |
|
|
Property, plant and equipment expenditures |
104,045 |
|
37,657 |
|
53,560 |
|
163,863 |
|
115,982 |
|
| Less: Net property
dispositions |
(20) |
|
(996) |
|
(129,983) |
|
(1,016) |
|
(129,983) |
|
|
Net capital expenditures |
104,025 |
|
36,661 |
|
(76,423) |
|
162,847 |
|
(14,001) |
|
c) EBITDAEBITDA is
calculated as consolidated net income (loss) before interest and
financing expenses, income taxes, depletion, depreciation and
amortization, adjusted for certain non-cash, extraordinary and
non-recurring items primarily relating to unrealized gains and
losses on financial instruments and impairment losses. The Company
considers this metric as key measures that demonstrate the ability
of the Company’s continuing operations to generate the cash flow
necessary to maintain production at current levels and fund future
growth through capital investment and to service and repay debt.
The most directly comparable IFRS measure to EBITDA is cash
provided by operating activities.
|
($ thousands) |
Three months ended Sept.
30, 2023 |
Three months ended June 30, 2023 |
Three months ended Sept. 30, 2022 |
Nine months ended Sept.
30, 2023 |
Nine months ended Sept. 30, 2022 |
|
|
Adjusted funds flow |
45,313 |
59,035 |
69,417 |
178,865 |
262,351 |
|
|
Financing expenses on debt |
1,120 |
2,003 |
6,916 |
5,739 |
19,240 |
|
|
EBITDA |
46,433 |
61,038 |
76,333 |
184,604 |
281,591 |
|
d) Free
Adjusted Funds FlowFree adjusted funds flow represents
adjusted funds flow less capital expenditures, excluding
acquisitions and dispositions. The Company considers this metric a
key measure that demonstrates the ability of the Company’s
continuing operations to fund future growth through capital
investment and to service and repay debt. The most directly
comparable IFRS measure to free adjusted funds flow is cash
provided by operating activities.
|
($ thousands) |
Three months ended Sept.
30, 2023 |
|
Three months ended June 30, 2023 |
|
Three months ended Sept. 30, 2022 |
|
Nine months ended Sept.
30, 2023 |
|
Nine months ended Sept. 30, 2022 |
|
|
Cash provided by operating activities |
46,056 |
|
69,952 |
|
82,322 |
|
182,652 |
|
254,767 |
|
|
Change in operating non-cash working capital |
(1,238) |
|
(12,154) |
|
(16,243) |
|
(8,872) |
|
766 |
|
|
Accretion of deferred financing costs |
- |
|
(49) |
|
(214) |
|
(199) |
|
(705) |
|
|
Financing costs on property disposition |
- |
|
- |
|
203 |
|
- |
|
203 |
|
|
Funds from operations |
44,818 |
|
57,749 |
|
66,068 |
|
173,581 |
|
255,031 |
|
|
Decommissioning obligations settled excluding government
grants |
495 |
|
1,286 |
|
3,349 |
|
5,284 |
|
7,320 |
|
|
Adjusted funds flow |
45,313 |
|
59,035 |
|
69,417 |
|
178,865 |
|
262,351 |
|
|
Less: property, plant and equipment expenditures |
104,045 |
|
37,657 |
|
53,560 |
|
163,863 |
|
115,982 |
|
|
Free adjusted funds flow |
(58,732) |
|
21,378 |
|
15,857 |
|
15,002 |
|
146,369 |
|
e) Net
Operating CostsNet operating costs equals operating
expenses net of processing revenue. Management views net operating
costs as an important measure to evaluate its operational
performance. The most directly comparable IFRS measure for net
operating costs is operating expenses.
|
($ thousands, except per boe) |
Three months ended Sept.
30, 2023 |
|
Three months ended June 30, 2023 |
|
Three months ended Sept. 30, 2022 |
|
Nine months ended Sept.
30, 2023 |
|
Nine months ended Sept. 30, 2022 |
|
|
Operating expenses |
12,372 |
|
12,712 |
|
12,580 |
|
37,642 |
|
36,644 |
|
|
Processing revenue |
(557) |
|
(610) |
|
(520) |
|
(1,803) |
|
(2,825) |
|
|
Net operating costs |
11,815 |
|
12,102 |
|
12,060 |
|
35,839 |
|
33,819 |
|
|
Per boe |
4.79 |
|
4.43 |
|
4.12 |
|
4.39 |
|
3.71 |
|
f) Net
Operating Costs per boeNet operating costs per boe equals
net operating costs divided by production. Management views net
operating costs per boe as an important measure to evaluate its
operational performance. The calculation of Crew’s net operating
costs per boe can be seen in the non-IFRS measure entitled “Net
Operating Costs” above.
g) Net
Transportation CostsNet transportation costs equals
transportation expenses net of transportation revenue. Management
views net transportation costs as an important measure to evaluate
its operational performance. The most directly comparable IFRS
measure for net transportation costs is transportation expenses.
The calculation of Crew’s net transportation costs can be seen in
the section entitled “Net Transportation Costs” of this
MD&A.
|
($ thousands, except per boe) |
Three months ended Sept.
30, 2023 |
|
Three months ended June 30, 2023 |
|
Three months ended Sept. 30, 2022 |
|
Nine months ended Sept.
30, 2023 |
|
Nine months ended Sept. 30, 2022 |
|
|
Transportation expenses |
11,053 |
|
10,967 |
|
11,482 |
|
33,308 |
|
34,419 |
|
|
Transportation revenue |
(1,827) |
|
(1,576) |
|
(1,485) |
|
(4,923) |
|
(4,407) |
|
|
Net transportation costs |
9,226 |
|
9,391 |
|
9,997 |
|
28,385 |
|
30,012 |
|
|
Per boe |
3.74 |
|
3.43 |
|
3.42 |
|
3.47 |
|
3.29 |
|
h) Net
Transportation Costs per boeNet transportation costs per
boe equals net transportation costs divided by production.
Management views net transportation costs per boe as an important
measure to evaluate its operational performance.
i) Operating Netback per
boeOperating netback per boe equals petroleum and natural
gas sales including realized gains and losses on commodity related
derivative financial instruments, marketing income, less royalties,
net operating costs and transportation costs calculated on a boe
basis. Management considers operating netback per boe an important
measure to evaluate its operational performance as it demonstrates
its field level profitability relative to current commodity
prices.
|
($/boe) |
Three months ended Sept.
30, 2023 |
|
Three months ended June 30, 2023 |
|
Three months ended Sept. 30, 2022 |
|
Nine months ended Sept.
30, 2023 |
|
Nine months ended Sept. 30, 2022 |
|
| Petroleum and natural gas
sales |
28.48 |
|
24.37 |
|
45.46 |
|
29.09 |
|
50.62 |
|
| Royalties |
(2.49) |
|
(1.95) |
|
(6.86) |
|
(2.91) |
|
(4.51) |
|
| Realized gain (loss) on
derivative financial instruments |
2.48 |
|
8.87 |
|
(4.63) |
|
5.43 |
|
(7.52) |
|
| Net operating costs |
(4.79) |
|
(4.43) |
|
(4.12) |
|
(4.39) |
|
(3.71) |
|
| Net transportation costs |
(3.74) |
|
(3.43) |
|
(3.42) |
|
(3.47) |
|
(3.29) |
|
|
Operating netbacks |
19.94 |
|
23.43 |
|
26.43 |
|
23.75 |
|
31.59 |
|
|
Production (boe/d) |
26,834 |
|
30,046 |
|
31,792 |
|
29,925 |
|
33,405 |
|
j) Cash
costs per boeCash costs per boe is comprised of net
operating, transportation, general and administrative and financing
expenses on debt calculated on a boe basis. Management views cash
costs per boe as an important measure to evaluate its operational
performance.
|
($/boe) |
Three months ended Sept.
30, 2023 |
Three months ended June 30, 2023 |
Three months ended Sept. 30, 2022 |
Nine months ended Sept.
30, 2023 |
Nine months ended Sept. 30, 2022 |
|
|
Net operating costs |
4.79 |
4.43 |
4.12 |
4.39 |
3.71 |
|
|
Net transportation costs |
3.74 |
3.43 |
3.42 |
3.47 |
3.29 |
|
|
General and administrative expenses |
1.14 |
1.09 |
0.99 |
1.13 |
0.92 |
|
|
Financing expenses on debt |
0.45 |
0.73 |
1.70 |
0.73 |
1.90 |
|
|
Cash costs |
10.12 |
9.68 |
10.23 |
9.72 |
9.82 |
|
k) Interest
expenses on debt per boeInterest expenses on debt per boe
is comprised of the sum of interest on bank loan and other,
interest on senior notes and accretion of deferred financing
charges, divided by production. Management views interest expenses
on debt per boe as an important measure to evaluate its cost of
debt financing.
|
($ thousands, except per boe) |
Three months ended Sept.
30, 2023 |
Three months ended June 30, 2023 |
Three months ended Sept. 30, 2022 |
Nine months ended Sept.
30, 2023 |
Nine months ended Sept. 30, 2022 |
|
|
Interest on bank loan and other |
1,120 |
1,127 |
154 |
2,155 |
2,317 |
|
|
Interest on senior notes |
- |
827 |
4,607 |
3,584 |
14,277 |
|
|
Accretion of deferred financing costs |
- |
49 |
214 |
199 |
705 |
|
|
Financing expenses on debt |
1,120 |
2,003 |
4,975 |
5,938 |
17,299 |
|
|
Production (boe/d) |
26,834 |
30,046 |
31,792 |
29,925 |
33,405 |
|
|
Interest expenses on debt per boe |
0.45 |
0.73 |
1.70 |
0.73 |
1.90 |
|
Supplementary Financial Measures
“Adjusted fund flow margin” is
comprised of adjusted funds flow divided by petroleum and natural
gas sales.
"Adjusted funds flow per basic
share" is comprised of adjusted funds flow divided by the
basic weighted average common shares.
"Adjusted funds flow per diluted
share" is comprised of adjusted funds flow divided by the
diluted weighted average common shares.
"Adjusted funds flow per boe"
is comprised of adjusted funds flow divided by total
production.
"Average realized commodity
price" is comprised of commodity sales from production, as
determined in accordance with IFRS, divided by the Company's
production. Average prices are before deduction of net
transportation costs and do not include gains and losses on
financial instruments.
“Average realized light crude oil
price” is comprised of light crude oil commodity sales
from production, as determined in accordance with IFRS, divided by
the Company’s light crude oil production. Average prices are before
deduction of net transportation costs and do not include gains and
losses on financial instruments.
"Average realized ngl price" is
comprised of ngl commodity sales from production, as determined in
accordance with IFRS, divided by the Company's ngl production.
Average prices are before deduction of net transportation costs and
do not include gains and losses on financial instruments.
“Average realized condensate
price” is comprised of condensate commodity sales from
production, as determined in accordance with IFRS, divided by the
Company’s condensate production. Average prices are before
deduction of net transportation costs and do not include gains and
losses on financial instruments.
"Average realized natural gas
price" is comprised of natural gas commodity sales from
production, as determined in accordance with IFRS, divided by the
Company's natural gas production. Average prices are before
deduction of net transportation costs and do not include gains and
losses on financial instruments.
"Net debt to last twelve months (“LTM”)
EBITDA" is calculated as net debt at a point in time
divided by EBITDA earned from that point back for the trailing
twelve months.
Supplemental Information Regarding
Product Types
References to gas or natural gas and ngls in
this press release refer to conventional natural gas and natural
gas liquids product types, respectively, as defined in National
Instrument 51-101, Standards of Disclosure for Oil and Gas
Activities ("NI 51-101"), except where specifically noted
otherwise.
The following is intended to provide the product
type composition for each of the production figures provided
herein, where not already disclosed within tables above:
| |
Light & MediumCrude Oil |
Condensate |
Natural GasLiquids1 |
ConventionalNatural Gas |
Total(boe/d) |
|
|
Q4 2023 Average |
0 |
% |
20 |
% |
7 |
% |
73 |
% |
30,000-32,000 |
|
|
2023 Annual Average |
0 |
% |
15 |
% |
7 |
% |
78 |
% |
30,000-31,000 |
|
Notes: 1) Excludes
condensate volumes which have been reported separately.
Crew is a growth-oriented natural gas and
liquids producer, committed to pursuing sustainable per share
growth through a balanced mix of financially and socially
responsible exploration and development. The Company’s operations
are exclusively located in northeast British Columbia and feature a
vast Montney resource with a large contiguous land base in the
Greater Septimus, Tower and Groundbirch areas in British Columbia,
offering significant development potential over the long-term. Crew
has access to diversified markets with operated infrastructure and
access to multiple pipeline egress options. The Company’s common
shares are listed for trading on the Toronto Stock Exchange (“TSX”)
under the symbol “CR” and on the OTCQB in the US under ticker
“CWEGF”.
FOR DETAILED INFORMATION, PLEASE
CONTACT:
|
Dale Shwed, President and CEO |
Phone: (403) 266-2088 |
| John Leach, Executive Vice
President and CFO |
Email:
investor@crewenergy.com |
Crew Energy (TSX:CR)
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