Crew Energy Inc. (TSX: CR; OTCQB: CWEGF) ("Crew" or the "Company"),
a growth-oriented natural gas weighted 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, 2022. Crew’s
Financial Statements and Notes, as well as Management’s Discussion
and Analysis (“MD&A”) are available on Crew’s website and filed
on SEDAR at www.sedar.com.
“Crew’s Q3 performance reflects continued
success driving our two-year asset development plan (the “Two-Year
Plan”) forward, exceeding the plan’s original leverage, margin
improvement and production targets. As of the end of Q3/22, we have
significantly deleveraged resulting in zero bank debt and a net
debt2 to last twelve month (“LTM”) EBITDA1 ratio of just 0.5 times,
while generating quarterly production volumes of 31,792 boe per day
and Adjusted Funds Flow2 (“AFF”) of $69.4 million,” said Dale
Shwed, President and CEO of Crew. “Due to our outperformance to
date in 2022, paired with strong results from our recent
development initiatives, we believe Crew is in an excellent
position to continue our momentum in responsibly developing our
world-class Montney assets.”
HIGHLIGHTS
-
31,792 boe per day3 (191 mmcfe) average production
in Q3/22 was near the high end of Crew’s production guidance range
of 30,000 to 32,000 boe per day3 and represents a 34% increase over
Q3/21 volumes, despite production shut-in for offsetting completion
operations at Groundbirch and in part for intermittently low
regional spot gas prices. For the first nine months of 2022,
volumes averaged 33,405 boe per day3 (200 mmcfe), 31% above the
same period in 2021.
-
Natural gas production in the quarter increased 36% over Q3/21 to
146 mmcf per day.
-
Condensate production increased 101% over Q3/21 to 4,731
bbls per day.
-
Natural gas liquids4,5 (“NGLs”) increased 20% over Q3/21 to
2,692 bbls per day.
-
$69.4 million of AFF2 ($0.46 per basic share and
$0.43 per fully diluted share) was generated in Q3/22, a 162%
increase from Q3/21, driven by year-over-year production growth and
strong operating netbacks6 of $26.43 per boe. For the first nine
months of 2022, AFF2 of $262.4 million was 205% higher than the
comparable period in 2021.
-
$15.9 million of Free AFF6 was generated in Q3/22,
supporting Crew’s accelerated deleveraging and further
strengthening financial flexibility.
-
62% reduction in net debt2 relative to year end
2021, totaling $152.6 million at quarter-end with nil drawings on
our recently increased $200 million credit facility.
-
Proceeds of $130 million from the previously announced non-core
Attachie and Portage property disposition (the “Disposition”)
facilitated a 43% reduction in Crew’s outstanding Senior Unsecured
Notes compared to year-end 2021, with $172 million now due in
2024.
-
0.5 times net debt2 to LTM EBITDA1 ratio at
quarter-end.
-
25% reduction in cash costs per boe6 to $10.23 per
boe in Q3/22 from $13.61 in Q3/21, with net operating costs6
declining 19% over Q3/21 to $4.12 per
boe.
-
$53.6 million invested in exploration and
development expenditures during Q3/22, below the midpoint
of previously provided guidance of $60 million, with $39.7 million
directed to drilling and completion activities in the Greater
Septimus area, $11.6 million on facilities, equipment and pipelines
and $2.3 million on land, seismic, and other miscellaneous amounts.
-
Net capital expenditures6 in Q3/22 were negative
$76.4 million as disposition proceeds of $130.0 million offset
Crew’s exploration and development expenditures during the
quarter.
FINANCIAL & OPERATING HIGHLIGHTS
|
FINANCIAL($ thousands, except per share
amounts) |
Three months ended Sept.
30, 2022 |
|
Three months ended Sept. 30, 2021 |
|
Nine months ended Sept.
30, 2022 |
|
Nine months ended Sept. 30, 2021 |
|
|
Petroleum and natural gas sales |
132,950 |
|
75,628 |
|
461,621 |
|
229,695 |
|
| Cash provided by
operating activities |
82,322 |
|
18,072 |
|
254,767 |
|
73,409 |
|
| Adjusted funds
flow2 |
69,417 |
|
26,511 |
|
262,351 |
|
86,036 |
|
|
Per share1 – basic |
0.46 |
|
0.17 |
|
1.72 |
|
0.56 |
|
|
- diluted |
0.43 |
|
0.17 |
|
1.62 |
|
0.55 |
|
| Net
income |
105,658 |
|
176,183 |
|
192,926 |
|
154,398 |
|
|
Per share – basic |
0.69 |
|
1.14 |
|
1.27 |
|
1.01 |
|
|
- diluted |
0.65 |
|
1.12 |
|
1.19 |
|
0.99 |
|
| Property, plant and
equipment expenditures |
53,560 |
|
64,295 |
|
115,982 |
|
135,583 |
|
|
Net property dispositions6 |
(129,983 |
) |
(7,816 |
) |
(129,983 |
) |
(7,816 |
) |
|
Net capital expenditures6 |
(76,423 |
) |
56,479 |
|
(14,001 |
) |
127,767 |
|
|
Capital Structure($ thousands) |
As at Sept. 30, 2022 |
|
As at Dec. 31, 2021 |
|
|
Working capital surplus (deficiency)2 |
18,521 |
|
(33,068 |
) |
| Bank
loan |
- |
|
(75,067 |
) |
|
|
18,521 |
|
(108,135 |
) |
| Senior
unsecured notes |
(171,149 |
) |
(297,834 |
) |
|
Net debt2 |
(152,628 |
) |
(405,969 |
) |
|
Common shares outstanding (thousands) |
152,285 |
|
152,480 |
|
|
OPERATIONAL |
|
|
Three months ended Sept.
30, 2022 |
Three months ended Sept. 30, 2021 |
Nine months ended Sept.
30, 2022 |
Nine months ended Sept. 30, 2021 |
|
Daily production |
|
|
|
|
|
|
|
Crude oil
(bbl/d)7 |
|
|
83 |
1,157 |
102 |
1,230 |
|
Condensate
(bbl/d) |
|
|
4,731 |
2,350 |
4,745 |
2,691 |
|
Natural gas liquids
(“ngl”)4,5 (bbl/d) |
|
|
2,692 |
2,242 |
2,884 |
2,442 |
|
Conventional
natural gas (mcf/d) |
|
|
145,715 |
107,459 |
154,041 |
115,016 |
|
Total (boe/d @
6:1) |
|
|
31,792 |
23,659 |
33,405 |
25,532 |
| Average
realized1 |
|
|
|
|
|
|
|
Light crude oil
price ($/bbl) |
|
|
104.30 |
78.29 |
114.75 |
71.26 |
|
Natural gas liquids
price ($/bbl) |
|
|
41.30 |
23.76 |
46.52 |
16.09 |
|
Condensate price
($/bbl) |
|
|
106.15 |
81.47 |
118.27 |
75.30 |
|
Natural gas price
($/mcf) |
|
|
5.65 |
4.65 |
6.39 |
4.56 |
|
Commodity price
($/boe) |
|
|
45.46 |
34.75 |
50.62 |
32.95 |
|
|
Three months ended Sept.
30, 2022 |
|
Three months ended Sept. 30, 2021 |
|
Nine months ended Sept.
30, 2022 |
|
Nine months ended Sept. 30, 2021 |
|
|
Netback ($/boe) |
|
|
|
|
|
Petroleum and
natural gas sales |
45.46 |
|
34.75 |
|
50.62 |
|
32.95 |
|
|
Royalties |
(6.86 |
) |
(2.74 |
) |
(4.51 |
) |
(2.27 |
) |
|
Realized loss on
derivative financial instruments |
(4.63 |
) |
(6.22 |
) |
(7.52 |
) |
(5.64 |
) |
|
Net operating
costs6 |
(4.12 |
) |
(5.11 |
) |
(3.71 |
) |
(4.84 |
) |
|
Transportation
costs |
(3.42 |
) |
(4.61 |
) |
(3.29 |
) |
(4.28 |
) |
|
Operating
netback6 |
26.43 |
|
16.07 |
|
31.59 |
|
15.92 |
|
|
General and
administrative (“G&A”) |
(0.99 |
) |
(1.05 |
) |
(0.92 |
) |
(0.97 |
) |
|
Financing costs on
debt6 |
(1.70 |
) |
(2.84 |
) |
(1.90 |
) |
(2.61 |
) |
|
Adjusted funds
flow2 |
23.74 |
|
12.18 |
|
28.77 |
|
12.34 |
|
____________________________
1 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.
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 See table in the Advisories for production
breakdown by product type as detailed in NI 51-101.
4 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.
5 Excludes condensate volumes which have been
reported separately.
6 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.
7 Throughout this news release, crude oil refers
to light, medium and heavy crude oil product type as defined by
National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities ("NI 51-101").
TWO-YEAR PLAN NEARS
COMPLETION
Crew continues to develop a renewed strategic
plan designed to build on momentum created with our current
Two-Year Plan, for which we anticipate communicating details of
towards the end of this year. We are proud to showcase the
following accomplishments realized from the Two-Year Plan to
date:
- Significant
Deleveraging – Crew lowered outstanding bank debt to zero
and reduced our outstanding Senior Unsecured Notes by 43% in Q3/22,
together driving a 62% reduction in quarter-end net debt2 to $152.6
million compared to year-end 2021. Crew’s deleveraging strategy has
achieved our target of a net debt2 to LTM EBITDA1 ratio of under
1.0 times with a September 30, 2022 ratio of 0.5 times.
-
Strengthened Production Profile – Average Q3/22
production of 31,792 boe per day3 (191 mmcfe per day) increased 34%
compared to Q3/21 despite the Company electing to temporarily
shut-in production during the quarter for offsetting completion
operations and for major third-party pipeline maintenance that
eroded regional spot natural gas prices. The year-over-year
increase was driven largely by strong well results from Crew’s
ultra-condensate rich (“UCR”) wells added earlier in 2022. Crew’s
high-value condensate production increased 101% over Q3/21,
contributing to our strong financial performance and setting the
stage for future success.
-
Improved Margins – Cash costs per boe6 associated
with operating, transportation, G&A and interest expense
totaled $9.82 per boe in the first nine months of 2022, a 23%
improvement from the same period in 2021, contributing to a 133%
increase in AFF2 per boe1 to $28.77 over the same period in 2022.
Crew successfully improved margins throughout the Two-Year Plan,
assisted by increasing production to match committed transportation
and processing capacity.
OPERATIONS & AREA
OVERVIEW
NE BC Montney (Greater
Septimus)
-
Crew drilled five (5.0 net) of the six (6.0 net) planned extended
reach horizontal (“ERH”) wells on the West Septimus 11-27 pad
during Q3/22 and finished drilling the sixth well early in the
fourth quarter. These wells are planned to be completed in Q4/22,
with production expected in mid January 2023.
-
In Q3/22, the Company constructed a pipeline connection from our
11-27 pad to the West Septimus Gas Plant to enable the use of Crew
produced natural gas to fuel future operations and to tie-in pad
production once completed.
-
The five (5.0 net) previously established ERH UCR wells drilled on
the eastern segment of our 4-14 pad in the Upper Montney “B” zone
continued to exceed internal expectations, producing average
wellhead IP170 rates of 1,711 mcf per day of natural gas and 633
bbls per day of condensate. On the western segment of the 4-14 pad,
the three (3.0 net) additional ERH UCR wells produced IP240 volumes
that also continue to exceed internal expectations, with average
wellhead rates of 7,638 mcf per day of natural gas and 416 bbls per
day of condensate.
Groundbirch
-
During Q3/22, Crew completed, equipped and tied-in five (5.0 net)
previously drilled ERH wells on the 4-17 pad that build on the
success of the initial three wells previously developed in the
area. Early well results indicate that four zones exist for
commercial development in the upper Montney at Groundbirch, with
the five wells flowing up tubing at an average restricted raw gas
rate of 8,500 mcf per day at an average casing pressure of 2,665
psi after 19 days of cleanup and testing. These wells are being
produced intermittently, reflecting regional gas price volatility
which has recently moderated.
-
To evaluate spacing for full field development, Crew deployed
downhole fiber optic monitoring while fracturing the pad to
optimally determine future vertical and horizontal well spacing as
well as proppant loading.
-
The three (3.0 net) previously established wells at Groundbirch
continue to exceed the Proved plus Probable area type curve
forecasts reflected in Crew’s year-end 2021 independent reserves
evaluation8, with an average per well raw gas production rate after
180 days (“IP180”) of 8,593 mcf per day.
-
Crew owns over 70,000 net acres of contiguous land in the Greater
Groundbirch area. The Upper Montney at Groundbirch is approximately
470 feet in thickness and has four prospective zones, all of which
have now been tested following the 4-17 exploration and development
program in Q3/22, with each having generated promising initial
commercial development rates.
Other NE BC Montney
- Crew has
commenced drilling the six-well, 15-28 ERH pad at Tower which is
expected to be finished in Q4/22, with completion activities
planned following spring break-up in 2023. The wells will target
light oil in the upper Montney “B” and “C” zones and are planned to
have lateral lengths of over 4,000 meters.
SUSTAINABILITY AND ESG
INITIATIVES
Crew's environmental, social and governance
("ESG") initiatives continue to be a key focus as we maintain our
steadfast commitment to safe and responsible energy production.
During Q3/22, Crew achieved independent certification of our
natural gas and natural gas liquids production from our NE BC
Development area under the Equitable Origin EO100™ Standard for
Responsible Energy Development. The certification confirms Crew’s
best-practice methods for ESG performance in the energy sector and
demonstrates our commitment to continuous improvement.
Please visit esg.crewenergy.com to see our
recently updated digital ESG Report and to learn more about our
latest sustainable solutions.
OUTLOOK
- Crew’s strong 2022
financial performance in achieving leverage targets provides the
flexibility to expedite two projects that were originally planned
for the first quarter of next year. Accelerating these projects
allows Crew to capture the economic benefit of meaningful cost
savings and efficiency gains by completing wells in Q4/22 and
through continuous drilling operations. This revised program also
enables additional flush production volumes to be produced into a
higher forecast natural gas price environment anticipated through
the winter of 2023. With renewed financial flexibility, Crew’s plan
is to weight future capital investments to the third and fourth
quarters of the year, which generally offer numerous operational,
capital investment and revenue optimization advantages.
- During Q4/22, Crew
now plans to complete six (6.0 net) ERH UCR wells on the 11-27 pad
and drill six (6.0 net) ERH oil wells on the 15-28 pad, taking
anticipated annual expenditures for the full year to $175 to $185
million, from the $130 to $140 million previously forecast. Crew's
annual 2022 production guidance is refined to 32,500 to 33,000 boe
per day3 from 32,000 to 33,000 boe per day.
- To further secure
superior returns on our investment, Crew has hedged 67,500 GJ’s per
day of natural gas production at an average price of $4.65 per GJ
(or $5.60 per mcf using Crew’s heat content factor), and 1,500 bbls
per day of condensate at $106.00 per bbl for the first half of
2023.
- The Company’s net
capital expenditures6 through the first half of 2023 are forecast
to reflect reduced investment activity through the period due to
the projects brought forward into 2022. A preliminary budget of $45
to $55 million is targeted to result in June 30, 2023 net debt2 of
under $100 million.
____________________________
8 Complete details of Crew’s year-end 2021 independent reserves
evaluation are contained within our Annual Information Form,
available on SEDAR at www.sedar.com.
|
|
Previous 2022 Guidanceand Material Assumptions |
Updated 2022 Guidanceand Material
Assumptions9 |
|
Property, plant and equipment expenditures ($MM) |
130-140 |
175-185 |
|
Net capital expenditures6 ($MM) |
130-140 |
45-5510 |
|
Annual average production (boe/d) |
32,000-33,000 |
32,500-33,000 |
|
AFF2 ($MM) |
300-320 |
300-320 |
|
Free AFF6 ($MM) |
160-190 |
115-145 |
|
EBITDA6 ($MM) |
324-344 |
324-344 |
|
Oil price (WTI)($US per bbl) |
93.00 |
93.00 |
|
Natural gas price (NYMEX) ($US per mmbtu) |
6.15 |
6.15 |
|
Natural gas price (AECO 5A) ($C per mcf) |
5.45 |
5.45 |
|
Natural gas price (Crew est. wellhead) ($C per mcf) |
6.25 |
6.25 |
|
Foreign exchange ($US/$CAD) |
0.78 |
0.78 |
|
Royalties |
8-9% |
8-9% |
|
Net operating costs6 ($ per boe) |
3.50-4.00 |
3.50-4.00 |
|
Transportation ($ per boe) |
3.00-3.50 |
3.00-3.50 |
|
G&A ($ per boe) |
0.80-1.00 |
0.80-1.00 |
|
Effective interest rate on long-term debt |
6.0-6.5% |
6.0-6.5% |
Updated 2022 guidance and material assumptions
in the table above reflect actuals for the nine months ended
September 30, 2022 and forecasts for the three months ended
December 31, 2022. Selected forecasts for the three months ended
December 31, 2022 are as follows:
|
Oil price (WTI)($US per bbl) |
85.00 |
|
Natural gas price (NYMEX) ($US per mmbtu) |
6.00 |
|
Natural gas price (AECO 5A) ($C per mcf) |
4.95 |
|
Natural gas price (Crew est. wellhead) ($C per mcf) |
5.80 |
-
Q4/22 Capital Program – Crew’s Q4/22 net capital
expenditures6 are expected to range between $60 and $70 million,
and although the Company’s current productive capacity is over
34,000 boe per day, Q4/22 production is expected to average between
30,000 and 32,000 boe per day3. The Company plans to shut-in
production volumes for offsetting completion operations at the
11-27 pad and has deferred production in October that was exposed
to low regional spot gas prices which have since recovered to
seasonal averages.
- Planned
Q4/22 capital investment includes:
- The completion of
six (6.0 net) ERH UCR wells on the 11-27 pad which are expected to
be on production in mid-January 2023, following up on our highly
successful 4-14 pad;
- The drilling of six
(6.0 net) ERH oil wells on the 15-28 pad at Tower, with completion
planned following spring break-up in 2023;
- A condensate
stabilization infrastructure project at the Septimus Gas Plant to
increase condensate capacity from 1,000 bbls per day to 4,700 bbls
per day by summer 2023; and
- Placing deposits on
long lead items for our 2023 program.
-
Near Term Initiatives
-
Direct Free AFF6 to further debt reduction and improvement of
leverage metrics;
-
Further assess optimal refinancing and payment options for the
remaining $172 million of Senior Unsecured Notes due 2024;
-
Continue to focus on technical efficiency improvements to help
offset inflationary factors;
-
Invest in capital projects offering robust rates of return with
targeted payback periods under 12 months, which can be supported by
an active hedging program;
-
Outline details of the Company’s renewed strategic plan; and
-
Actively monitor service industry efficiencies, costs, supply chain
trends and commodity prices to assess potential budget adjustments
as market conditions change throughout the year.
____________________________
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. 10 Net
of $130 million of proceeds from the previously announced non-core
Attachie and Portage property disposition.
Our ‘Crew’ remains excited about the results we
have realized by executing our Two-Year Plan to date and we look
forward to sharing an updated plan before year end. We commend the
hard work of Crew’s employees, contractors and directors whose
commitment and dedication are critical to our ongoing success and
thank all shareholders and bondholders for your ongoing
support.
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” 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 continue to execute on
its Two-Year Plan and underlying strategy and targets as described
herein; as to our plan to continue to optimize and increase
production and infrastructure utilization, reduce unit costs,
materially improve leverage metrics and generate increasing
Adjusted Funds Flow and meaningful Free Adjusted Funds Flow; our
2022 annual capital budget range, our preliminary plans and budget
for H1 2023, associated drilling and completion plans, the timing
thereof, and all associated near term initiatives and targets,
along with all guidance and underlying assumptions in the Outlook
section of this press release; production estimates including
forecast production per share growth, 2022 annual averages and Q4
2022 production estimates; infrastructure plans and anticipated
benefits; forecast 2022 AFF estimates and targeted 2022 Free AFF
and improvement in debt and leverage metrics; commodity price
expectations including Crew’s estimates of natural gas pricing
exposure; Crew's commodity risk management programs and future
hedging opportunities; well abandonment plans; marketing and
transportation and processing plans and requirements; estimates of
processing capacity and requirements; anticipated reductions in GHG
emissions and decommissioning obligations; future liquidity and
financial capacity; future results from operations and operating
and leverage metrics; expected well payouts under 12 months; our
first half 2023 capital expenditure plans including targeted June
30, 2023 debt levels; world supply and demand projections and
long-term impact on pricing; future development, exploration,
acquisition and disposition activities (including drilling and
completion plans, anticipated on-stream dates and associated
development timing and cost estimates); the potential for another
liquids-rich hydrocarbon window on Crew’s acreage at Greater
Septimus; the potential of our Groundbirch area to be a core area
of future development and the anticipated commerciality of up to
four potential prospective zones to be drilled; the successful
implementation of our ESG initiatives, 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 Two-Year Plan.
The internal projections, expectations, or
beliefs underlying our Board approved 2022 capital budget and
associated guidance are subject to change in light of the impact of
the COVID-19 pandemic, the Russia / Ukraine conflict and any
related actions taken by businesses and governments, ongoing
results, prevailing economic circumstances, commodity prices, and
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. Such information reflects
internal targets used by management for the purposes of making
capital investment decisions and for internal long-range planning
and budget preparation. Readers are cautioned that events or
circumstances could cause capital plans and associated results to
differ materially from those predicted and Crew's guidance for 2022
and 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 a number of 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 will
resume 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 COVID-19 and the Russia / Ukraine conflict; 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; 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, 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.
Information Regarding Disclosure on Oil
and Gas Reserves and 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.
BOE Conversions
Barrel of oil equivalents or BOEs may be
misleading, particularly if used in isolation. A BOE conversion
ratio of 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. 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 Flow (“AFF”)
Funds from operations represents cash provided
by operating activities before changes in operating non-cash
working capital, accretion of deferred financing costs 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
Expenditures
Net capital expenditures equals exploration and
development 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 endedSept. 30, 2022 |
|
Three months endedJune 30, 2022 |
Three months endedSept. 30, 2021 |
|
Nine months endedSept. 30, 2022 |
|
Nine months endedSept. 30, 2021 |
|
|
Property, plant and equipment expenditures |
53,560 |
|
7,061 |
64,295 |
|
115,982 |
|
135,583 |
|
| Less: Net property
dispositions |
(129,983 |
) |
- |
(7,816 |
) |
(129,983 |
) |
(7,816 |
) |
|
Net capital expenditures |
(76,423 |
) |
7,061 |
56,479 |
|
(14,001 |
) |
127,767 |
|
c) EBITDA
EBITDA 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 endedSept. 30, 2022 |
|
Three months endedJune 30, 2022 |
|
Three months endedSept. 30, 2021 |
|
Nine months endedSept. 30, 2022 |
|
Nine months endedSept. 30, 2021 |
|
|
|
|
|
|
|
|
| Cash provided by operating
activities |
82,322 |
|
117,363 |
|
18,072 |
|
254,767 |
|
73,409 |
|
| Change in operating non-cash
working capital |
(16,243 |
) |
(2,666 |
) |
5,707 |
|
766 |
|
9,512 |
|
| Accretion of deferred
financing costs |
(214 |
) |
(245 |
) |
(245 |
) |
(705 |
) |
(737 |
) |
| Transaction costs on property
dispositions |
203 |
|
- |
|
2,505 |
|
203 |
|
2,505 |
|
|
Funds from operations |
66,068 |
|
114,452 |
|
26,039 |
|
255,031 |
|
84,689 |
|
|
Decommissioning obligations settled excluding government
grants |
3,349 |
|
822 |
|
472 |
|
7,320 |
|
1,347 |
|
|
Adjusted funds flow |
69,417 |
|
115,274 |
|
26,511 |
|
262,351 |
|
86,036 |
|
|
Interest |
6,916 |
|
6,230 |
|
6,183 |
|
19,240 |
|
18,200 |
|
|
EBITDA |
76,333 |
|
121,504 |
|
32,694 |
|
281,591 |
|
104,236 |
|
d) Free Adjusted
Funds Flow
Free 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 endedSept. 30, 2022 |
|
Three months endedJune 30, 2022 |
|
Three months endedSept. 30, 2021 |
|
Nine months endedSept. 30, 2022 |
|
Nine months endedSept. 30, 2021 |
|
|
|
|
|
|
|
|
| Cash provided by operating
activities |
82,322 |
|
117,363 |
|
18,072 |
|
254,767 |
|
73,409 |
|
| Change in operating non-cash
working capital |
(16,243 |
) |
(2,666 |
) |
5,707 |
|
766 |
|
9,512 |
|
| Accretion of deferred
financing costs |
(214 |
) |
(245 |
) |
(245 |
) |
(705 |
) |
(737 |
) |
| Transaction costs on property
disposition |
203 |
|
- |
|
2,505 |
|
203 |
|
2,505 |
|
|
Funds from operations |
66,068 |
|
114,452 |
|
26,039 |
|
255,031 |
|
84,689 |
|
|
Decommissioning obligations settled excluding government
grants |
3,349 |
|
822 |
|
472 |
|
7,320 |
|
1,347 |
|
|
Adjusted funds flow |
69,417 |
|
115,274 |
|
26,511 |
|
262,351 |
|
86,036 |
|
| Less:
property, plant and equipment expenditures |
53,560 |
|
7,061 |
|
64,295 |
|
115,983 |
|
135,583 |
|
|
Free adjusted funds flow |
15,857 |
|
108,213 |
|
(37,784 |
) |
146,368 |
|
(49,547 |
) |
e) Net Operating
Costs
Net operating costs equals operating costs 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 costs.
|
($ thousands, except per boe) |
Three months endedSept. 30, 2022 |
|
Three months endedJune 30, 2022 |
|
Three months endedSept. 30, 2021 |
|
Nine months endedSept. 30, 2022 |
|
Nine months endedSept. 30, 2021 |
|
|
|
|
|
|
|
|
| Operating costs |
12,580 |
|
12,705 |
|
11,866 |
|
36,644 |
|
35,541 |
|
|
Processing revenue |
(520 |
) |
(1,475 |
) |
(750 |
) |
(2,825 |
) |
(1,786 |
) |
|
Net operating costs |
12,060 |
|
11,230 |
|
11,116 |
|
33,819 |
|
33,755 |
|
| Per
boe |
4.12 |
|
3.52 |
|
5.11 |
|
3.71 |
|
4.84 |
|
f) Net Operating
Costs per boe
Net 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) Operating
Netback per boe
Operating 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.
|
($/boe) |
|
|
Three months endedSept. 30, 2022 |
|
Three months endedJune 30, 2022 |
|
Three months endedSept. 30, 2021 |
|
|
|
|
|
|
|
|
|
Petroleum and natural gas sales |
|
|
45.46 |
|
62.16 |
|
34.75 |
|
|
Royalties |
|
|
(6.86 |
) |
(3.98 |
) |
(2.74 |
) |
|
Realized loss on derivative financial instruments |
|
|
(4.63 |
) |
(12.41 |
) |
(6.22 |
) |
|
Net operating costs |
|
|
(4.12 |
) |
(3.52 |
) |
(5.11 |
) |
|
Transportation costs |
|
|
(3.42 |
) |
(3.33 |
) |
(4.61 |
) |
|
Operating netbacks |
|
|
26.43 |
|
38.92 |
|
16.07 |
|
|
Production (boe/d) |
|
|
31,792 |
|
35,044 |
|
23,659 |
|
h) Cash costs per
boe
Cash costs per boe is comprised of net
operating, transportation, general and administrative and financing
costs on debt calculated on a boe basis. Management views cash
costs per boe as an important measure to evaluate its operational
performance.
|
($/boe) |
Three months endedSept. 30, 2022 |
Three months endedJune 30, 2022 |
Three months endedSept. 30, 2021 |
Nine months endedSept. 30, 2022 |
Nine months endedSept. 30, 2021 |
|
|
|
|
|
|
|
| Net operating costs |
4.12 |
3.52 |
5.11 |
3.71 |
4.84 |
| Transportation costs |
3.42 |
3.33 |
4.61 |
3.29 |
4.28 |
| General and administrative
expenses |
0.99 |
0.83 |
1.05 |
0.92 |
0.97 |
|
Financing costs on debt |
1.70 |
1.95 |
2.84 |
1.90 |
2.61 |
|
Cash costs |
10.23 |
9.63 |
13.61 |
9.82 |
12.70 |
i) Financing costs
on debt per boe
Financing costs 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 financing costs on debt per boe as an
important measure to evaluate its cost of debt financing.
|
($ thousands, except per boe) |
Three months endedSept. 30,
2022 |
Three months endedJune 30, 2022 |
Three months endedSept. 30, 2021 |
Nine months endedSept. 30,
2022 |
Nine months endedSept. 30, 2021 |
|
|
|
|
|
|
|
| Interest on bank loan and
other |
154 |
1,123 |
1,023 |
2,317 |
2,878 |
| Interest on senior notes |
4,607 |
4,862 |
4,915 |
14,277 |
14,585 |
|
Accretion of deferred financing charges |
214 |
245 |
245 |
705 |
737 |
|
Financing costs on debt |
4,975 |
6,230 |
6,183 |
17,299 |
18,200 |
| Production (boe/d) |
31,792 |
35,044 |
23,659 |
33,405 |
25,532 |
|
Financing costs on debt per boe |
1.70 |
1.95 |
2.84 |
1.90 |
2.61 |
Supplementary Financial
Measures
"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 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 transportation costs and do not include gains and
losses on financial instruments.
"Average realized heavy crude oil
price" is comprised of heavy crude oil commodity sales
from production, as determined in accordance with IFRS, divided by
the Company's heavy crude oil production. Average prices are before
deduction of 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 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 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 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:
|
|
Crude Oil |
Condensate |
Natural GasLiquids1 |
Conventional Natural Gas |
Total(boe/d) |
|
Q3 2021 Average |
1,157 bbls/d |
2,350 bbls/d |
2,242 bbls/d |
107,459 mcf/d |
23,659 |
| Q2 2022
Average |
108 bbls/d |
5,570 bbls/d |
3,108 bbls/d |
157,547 mcf/d |
35,044 |
| Q3 2022
Average |
83 bbls/d |
4,731 bbls/d |
2,682 bbls/d |
145,715 mcf/d |
31,792 |
| First 9 Months of 2022
Average |
102 bbls/d |
4,745 bbls/d |
2,884 bbls/d |
154,041 mcf/d |
33,405 |
| Q4 2022
Average |
0% |
12% |
8% |
80% |
30,000-32,000 |
|
2022 Annual Average |
0% |
14% |
9% |
77% |
32,500-33,000 |
Notes: 1) Excludes
condensate volumes which have been reported separately.
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 considered to 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.
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 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 CEOJohn Leach, Executive Vice President
and CFO |
Phone: (403) 266-2088Email: investor@crewenergy.com |
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