CALGARY,
AB, Oct. 24, 2023 /CNW/ - Western Energy
Services Corp. ("Western" or the "Company") (TSX: WRG) announces
the release of its third quarter 2023 financial and operating
results. Additional information relating to the Company,
including the Company's financial statements and management's
discussion and analysis as at September 30,
2023 and for the three and nine months ended September 30, 2023 and 2022 ("MD&A") will be
available on SEDAR+ at www.sedarplus.ca. Non-International
Financial Reporting Standards ("Non-IFRS") measures and ratios,
such as Adjusted EBITDA, Adjusted EBITDA as a percentage of
revenue, revenue per Operating Day, revenue per Service Hour and
Working Capital, as well as abbreviations and definitions for
standard industry terms are defined later in this press
release. All amounts are denominated in Canadian dollars
(CDN$) unless otherwise identified.
Third Quarter 2023 Operating Results:
- On September 29, 2023, the
Company made a lump sum repayment of $4.1
million related to its HSBC Bank Canada six-year committed
term non-revolving facility with the participation of Business
Development Canada (the "HSBC Facility"). The voluntary repayment
included all committed monthly principal payments from September 30, 2023 up to December 31, 2026, resulting in no current
obligation owing on the HSBC Facility as at September 30, 2023. The remaining balance under
the HSBC Facility is due upon maturity of the HSBC Facility on
December 31, 2026.
- Third quarter revenue decreased by $3.5
million or 6%, to $55.0
million in 2023, as compared to $58.5
million in the third quarter of 2022. Contract drilling
revenue totalled $38.3 million in the
third quarter of 2023, which was consistent with $38.1 million in the third quarter of 2022.
Production services revenue was $16.8
million for the three months ended September 30, 2023, a decrease of $3.6 million or 18%, as compared to $20.4 million in the same period of the prior
year. In the third quarter of 2023, revenue was negatively impacted
by lower activity in production services and contract drilling in
Canada and the US due to lower
commodity prices, compared to the third quarter of 2022 as
described below:
- In Canada, Operating Days of
883 days in the third quarter of 2023 were 26 days (or 3%) lower
compared to 909 days in the third quarter of 2022. This compares to
a 7% decrease in the Canadian Association of Energy Contractors
("CAOEC") industry Operating Days in the third quarter of 2023,
compared to the third quarter of 2022. Drilling rig utilization in
Canada was 28% in the third
quarter of 2023, compared to 27% in the same period of the prior
year, as lower Operating Days were offset by three rigs that were
deregistered since September 30,
2022. The CAOEC industry average utilization of
38%1 for the third quarter of 2023
represented a decrease of 200 bps compared to the CAOEC industry
average utilization of 40% in the third quarter of 2022. Revenue
per Operating Day averaged $31,698 in
the third quarter of 2023, an increase of 8% compared to the same
period of the prior year, mainly due to rig upgrades, market driven
increased pricing, and inflationary pressures on operating costs,
including higher wages and fuel charges that are passed through to
the customer;
- In the United States ("US"),
drilling rig utilization averaged 34% in the third quarter of 2023,
compared to 45% in the third quarter of 2022, with Operating Days
decreasing from 333 days in the third quarter of 2022 to 249 days
in the third quarter of 2023 due to lower industry activity.
Average active industry rigs of 6492 in
the third quarter of 2023 were 15% lower compared to the third
quarter of 2022. Revenue per Operating Day for the third quarter of
2023 averaged US$30,898, a 17%
increase compared to US$26,372 in the
same period of the prior year, mainly due to improved spot market
rates; and
- In Canada, service rig
utilization of 33% in the third quarter of 2023 was lower than 45%
in the same period of the prior year as industry activity
decreased, mainly due to the completion of the Federal site
rehabilitation program, several customers waiting on the
restoration of power in areas impacted by wildfires and lower
commodity prices experienced during the first eight months of 2023,
compared to 2022. Revenue per Service Hour averaged $1,012 in the third quarter of 2023 and was 4%
higher than the third quarter of 2022, due to improved pricing and
inflationary pressures on operating costs, including higher wages
and fuel charges that are passed through to the customer.
- Administrative expenses increased by $0.7 million or 21%, to $4.0 million in the third quarter of 2023, as
compared to $3.3 million in the third
quarter of 2022, due to inflationary pressures on all employee
related costs.
- The Company incurred a net loss of $1.3
million in the third quarter of 2023 ($0.04 net loss per basic common share) as
compared to a net income of $0.8
million in the same period in 2022 ($0.02 net income per basic common share). The
change can mainly be attributed to a $3.8
million decrease in Adjusted EBITDA and a $0.5 million increase in depreciation expense due
to property and equipment additions, which were partially offset by
a $1.3 million decrease in income tax
expense, a $0.6 million increase in
other items, a $0.2 million decrease
in stock based compensation expense and a $0.1 million decrease in finance costs due to a
lower total debt balance.
- Adjusted EBITDA of $11.0 million
in the third quarter of 2023 was $3.8
million, or 25%, lower compared to $14.8 million in the third quarter of 2022.
Adjusted EBITDA in 2023 was lower due to lower production services
activity in Canada and lower
contract drilling activity in the US and Canada, as well as inflationary cost
increases, offset partially by higher pricing across all
divisions.
- Third quarter additions to property and equipment of
$7.3 million in 2023 compared to
$8.5 million in the third quarter of
2022, consisting of $1.7 million of
expansion capital related to the substantial completion of the
Company's rig upgrade program and $5.6
million of maintenance capital.
1
Source: CAOEC, monthly Contractor Summary.
2 Source: Baker Hughes Company, North America
Rotary Rig Count.
|
Year to Date 2023 Operating Results:
- During the nine months ended September
30, 2023, the Company reduced its total debt by $13.6 million (or 10%), primarily through
repayments of its Credit Facilities (as defined in this press
release) as well as a $4.1 million
voluntary repayment of all committed monthly principal amounts
owing on its HSBC Facility to its maturity on December 31, 2026 as described previously.
- Western's drilling rig upgrade program, which was initiated in
2022, has been a success and has generated a substantial portion of
revenue in the nine months ended September
30, 2023. Since the upgrades have been performed and the
rigs recommissioned into service, all upgraded drilling rigs have
worked for customers. Additionally, the upgraded rigs have
generated higher day rates which contributed to increased revenue
for the nine months ended September 30,
2023.
- Revenue for the nine months ended September 30, 2023, increased by $37.6 million or 27%, to $177.2 million as compared to $139.6 million for the nine months ended
September 30, 2022. Contract drilling
revenue totalled $126.9 million for
the nine months ended September 30,
2023, an increase of $40.6
million or 47%, compared to $86.3
million in the same period of the prior year. Production
services revenue was $50.6 million
for the nine months ended September 30,
2023, a decrease of $2.9
million or 6%, as compared to $53.5
million in the same period of the prior year. In the nine
months ended September 30, 2023,
revenue was positively impacted by improved pricing in all
divisions, rig upgrades, as well as higher activity in contract
drilling, partially offset by lower activity in production
services, compared to the same period of 2022 as described below:
- In Canada, Operating Days of
2,742 days for the nine months ended September 30, 2023, were 430 days (or 19%)
higher, compared to 2,312 days for the nine months ended
September 30, 2022, resulting in
drilling rig utilization of 30% for the nine months ended
September 30, 2023, compared to 23%
in the same period of the prior year. This compares to a 1%
increase in CAOEC Operating Days for the nine months ended
September 30, 2023, compared to the
same period in the prior year. The CAOEC industry average
utilization of 36%3 for the nine months
ended September 30, 2023, represented
an increase of 200 bps compared to the CAOEC industry average
utilization of 34% for the nine months ended September 30, 2022. Revenue per Operating Day
averaged $32,755 for the nine months
ended September 30, 2023, an increase
of 17% compared to the same period of the prior year, mainly due to
rig upgrades, market driven increased pricing, and inflationary
pressures on operating costs, including higher wages and fuel
charges that are passed through to the customer;
- In the US, drilling rig utilization averaged 39% for the nine
months ended September 30, 2023,
compared to 31% in the same period of 2022, with Operating Days
improving by 160 days from 683 days in 2022 to 843 days in 2023.
Average active industry rigs of 7094 in
the nine months ended September 30,
2023 were 1% higher than the average for the nine months
ended September 30, 2022. Revenue per
Operating Day for the nine months ended September 30, 2023 averaged US$32,038, a 31% increase compared to
US$24,421 in the same period of the
prior year, mainly due to improved spot market pricing in the
Williston Basin; and
- In Canada, service rig
utilization of 33% for the nine months ended September 30, 2023 was lower than 42% in the same
period of the prior year as industry activity decreased, mainly due
to the completion of the Federal site rehabilitation program,
several customers waiting on the restoration of power in areas
impacted by wildfires and lower commodity prices. Revenue per
Service Hour averaged $1,030 for the
nine months ended September 30, 2023
and was 11% higher than the same period of the prior year, due to
improved pricing and inflationary pressures on operating costs,
including higher wages and fuel charges that are passed through to
the customer.
- Administrative expenses increased by $2.3 million or 23%, to $12.4 million for the nine months ended
September 30, 2023, as compared to
$10.1 million in the same period of
2022, due to higher employee related costs along with inflationary
costs and higher professional fees.
- The Company generated a net loss of $4.7
million for the nine months ended September 30, 2023 ($0.14 net loss per basic common share) as
compared to net income of $32.4
million in the same period in 2022 ($1.89 net income per basic common share). The
change can mainly be attributed to the $49.4
million gain on debt forgiveness in 2022 in connection with
the Company's restructuring transaction completed in May 2022, a $6.7
million increase in Adjusted EBITDA, a $4.0 million decrease in income tax expense and a
$2.7 million decrease in finance
costs due to the lower total debt balance, offset partially by a
$1.1 million increase in stock based
compensation expense and a $1.1
million increase in depreciation expense due to property and
equipment additions.
- Adjusted EBITDA of $34.4 million
for the nine months ended September 30,
2023 was $6.7 million, or 24%,
higher compared to $27.7 million in
the same period of 2022. Adjusted EBITDA was higher due to improved
contract drilling activity in Canada and the US in the first half of 2023,
higher pricing across all divisions, and US$0.6 million of shortfall commitment revenue,
which was offset partially by lower activity in the third quarter
of 2023, one-time costs of $0.6
million related to reactivating certain drilling rigs and
inflationary cost increases and $0.8
million lower government subsidies received in 2023 compared
to 2022.
- Year to date 2023 additions to property and equipment of
$19.2 million compared to
$26.5 million in the same period of
2022, consisting of $6.8 million of
expansion capital related to the substantial completion of the
Company's rig upgrade program and $12.4
million of maintenance capital.
3
Source: CAOEC, monthly Contractor Summary.
4 Source: Baker Hughes Company, North America
Rotary Rig Count.
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Selected Financial
Information
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|
|
|
|
|
|
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(stated in
thousands, except share and per share amounts)
|
|
|
|
|
|
Three months ended September
30
|
Nine months ended September 30
|
|
Financial
Highlights
|
2023
|
2022
|
Change
|
2023
|
2022
|
Change
|
|
Revenue
|
55,003
|
58,483
|
(6 %)
|
177,196
|
139,552
|
27 %
|
|
Adjusted
EBITDA(1)
|
11,033
|
14,799
|
(25 %)
|
34,369
|
27,688
|
24 %
|
|
Adjusted EBITDA as a
percentage of revenue(1)
|
20 %
|
25 %
|
(20 %)
|
19 %
|
20 %
|
(5 %)
|
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Cash flow from
operating activities
|
13,267
|
6,854
|
94 %
|
45,085
|
22,039
|
105 %
|
|
Additions to property
and equipment
|
7,348
|
8,470
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(13 %)
|
19,218
|
26,520
|
(28 %)
|
|
Net income
(loss)
|
(1,267)
|
818
|
(255 %)
|
(4,691)
|
32,415
|
(114 %)
|
|
– basic
and diluted net income (loss) per share
|
(0.04)
|
0.02
|
(300 %)
|
(0.14)
|
1.89
|
(107 %)
|
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Weighted average number
of shares
|
|
|
|
|
|
|
|
–
basic
|
33,841,781
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33,839,658
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-
|
33,841,478
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17,120,283
|
98 %
|
|
–
diluted
|
33,841,781
|
33,839,658
|
-
|
33,841,478
|
17,120,936
|
98 %
|
|
Outstanding common
shares as at period end
|
33,843,009
|
33,841,318
|
-
|
33,843,009
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33,841,318
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-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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|
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(1) See "Non-IFRS
Measures and Ratios" included in this press release.
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Three
months ended September 30
|
Nine months ended September 30
|
Operating
Highlights(2)
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|
2023
|
|
2022
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|
Change
|
2023
|
|
2022
|
Change
|
Contract
Drilling
|
|
|
|
|
|
|
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Canadian
Operations:
|
|
|
|
|
|
|
|
|
Contract drilling rig
fleet:
|
|
|
|
|
|
|
|
|
– Average
active rig count
|
9.6
|
|
9.9
|
|
(3 %)
|
10.0
|
8.5
|
18 %
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Operating
Days
|
883
|
|
909
|
|
(3 %)
|
2,742
|
2,312
|
19 %
|
Revenue per Operating
Day(3)
|
31,698
|
|
29,283
|
|
8 %
|
32,755
|
28,002
|
17 %
|
Drilling rig
utilization
|
28 %
|
|
27 %
|
|
4 %
|
30 %
|
23 %
|
30 %
|
CAOEC industry average
utilization – Operating Days(4)
|
38 %
|
|
40 %
|
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(5 %)
|
36 %
|
34 %
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6 %
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Average meters drilled
per well
|
7,035
|
|
5,929
|
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19 %
|
6,908
|
6,077
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14 %
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Average Operating Days
per well
|
10.6
|
|
11.4
|
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(7 %)
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12.7
|
12.1
|
5 %
|
|
|
|
|
|
|
|
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United States
Operations:
|
|
|
|
|
|
|
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Contract drilling rig
fleet:
|
|
|
|
|
|
|
|
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– Average
active rig count
|
2.7
|
|
3.6
|
|
(25 %)
|
3.1
|
2.5
|
24 %
|
Operating
Days
|
249
|
|
333
|
|
(25 %)
|
843
|
683
|
23 %
|
Revenue per Operating
Day (US$)(3)
|
30,898
|
|
26,372
|
|
17 %
|
32,038
|
24,421
|
31 %
|
Drilling rig
utilization
|
34 %
|
|
45 %
|
|
(24 %)
|
39 %
|
31 %
|
26 %
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Average meters drilled
per well
|
3,609
|
|
3,727
|
|
(3 %)
|
3,459
|
3,604
|
(4 %)
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Average Operating Days
per well
|
12.8
|
|
9.8
|
|
31 %
|
13.0
|
10.9
|
19 %
|
|
|
|
|
|
|
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Production
Services
|
|
|
|
|
|
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Well servicing rig
fleet:
|
|
|
|
|
|
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– Average
active rig count
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21.5
|
|
28.4
|
|
(24 %)
|
21.5
|
26.4
|
(19 %)
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Service
Hours
|
13,984
|
|
18,492
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(24 %)
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42,081
|
51,635
|
(19 %)
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Revenue per Service
Hour(3)
|
1,012
|
|
975
|
|
4 %
|
1,030
|
928
|
11 %
|
Service rig
utilization
|
33 %
|
|
45 %
|
|
(27 %)
|
33 %
|
42 %
|
(21 %)
|
|
|
|
|
|
|
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|
|
|
|
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(2) See "Defined Terms"
included in this press release.
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(3) See "Non-IFRS
Measures and Ratios" included in this press release.
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(4) Source: The
CAOEC monthly Contractor Summary. The CAOEC industry average
is based on Operating Days divided by total available drilling
days.
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Financial Position
at (stated in thousands)
|
September 30,
2023
|
|
December 31,
2022
|
September 30,
2022
|
Working
capital(1)
|
16,473
|
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21,923
|
21,439
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Total assets
|
453,980
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|
475,708
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475,651
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Long term debt – non
current portion
|
114,107
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126,527
|
127,639
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(1) See "Non-IFRS
Measures and Ratios" included in this press release.
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Business Overview
Western is an energy services company that provides contract
drilling services in Canada and in
the US and production services in Canada through its various divisions, its
subsidiary, and its first nations relationships.
Contract Drilling
Western markets a fleet of 42 drilling rigs specifically suited
for drilling complex horizontal wells across Canada and the US. Western is currently
the fourth largest drilling contractor in Canada, based on the CAOEC registered drilling
rigs5.
Western's marketed and owned contract drilling rig fleets are
comprised of the following:
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As at September
30
|
|
2023
|
|
2022
|
Rig
class(1)
|
Canada
|
US
|
Total
|
|
Canada
|
US
|
Total
|
Cardium
|
11
|
1
|
12
|
|
11
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2
|
13
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Montney
|
18
|
1
|
19
|
|
19
|
-
|
19
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Duvernay
|
5
|
6
|
11
|
|
7
|
6
|
13
|
Total marketed
drilling rigs(2)
|
34
|
8
|
42
|
|
37
|
8
|
45
|
Total owned drilling
rigs
|
48
|
8
|
56
|
|
49
|
8
|
57
|
(1) See "Contract
Drilling Rig Classifications" included in this press
release.
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(2) Source: CAOEC
Contractor Summary as at October 24, 2023.
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Production Services
Production services provides well servicing and oilfield
equipment rentals in Canada.
Western operates 65 well servicing rigs and is the second largest
well servicing company in Canada
based on CAOEC registered well servicing rigs6.
Western's well servicing rig fleet is comprised of the
following:
Owned well servicing
rigs
|
As at September 30
|
Mast
type
|
2023
|
2022
|
Single
|
30
|
30
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Double
|
27
|
25
|
Slant
|
8
|
8
|
Total owned well
servicing rigs
|
65
|
63
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Business Environment
Crude oil and natural gas prices impact the cash flow of
Western's customers, which in turn impacts the demand for Western's
services. The following table summarizes average crude oil
and natural gas prices, as well as average foreign exchange rates,
for the three and nine months ended September 30, 2023 and 2022.
|
Three months ended
September 30
|
Nine months ended
September 30
|
|
2023
|
2022
|
Change
|
2023
|
2022
|
Change
|
Average crude oil
and natural gas prices(1)(2)
|
|
|
|
|
|
Crude
Oil
|
|
|
|
|
|
West Texas Intermediate
(US$/bbl)
|
82.26
|
91.56
|
(10 %)
|
77.40
|
98.09
|
(21 %)
|
Western Canadian Select
(CDN$/bbl)
|
93.19
|
93.53
|
-
|
80.42
|
105.55
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(24 %)
|
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|
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Natural
Gas
|
|
|
|
|
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30 day Spot AECO
(CDN$/mcf)
|
2.70
|
4.62
|
(42 %)
|
2.86
|
5.70
|
(50 %)
|
|
|
|
|
|
|
|
Average foreign
exchange rates(2)
|
|
|
|
|
|
|
US dollar to Canadian
dollar
|
1.34
|
1.31
|
2 %
|
1.34
|
1.28
|
5 %
|
(1) See "Abbreviations" included in this press
release.
(2) Source: Sproule September 30, 2023, Price Forecast,
Historical Prices.
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5
Source: CAOEC Drilling Contractor Summary as at October 24,
2023.
6 Source: CAOEC Well Servicing Fleet List as at
October 24, 2023.
|
West Texas Intermediate ("WTI") on average decreased by 10% and
21% respectively, for the three and nine months ended September 30, 2023, compared to the same periods
in the prior year. Pricing on Western Canadian Select ("WCS")
crude oil for the three months ended September 30, 2023, was consistent with the same
period of the prior year, whereas for the nine months ended
September 30, 2023, WCS decreased by
24%, compared to the same period in the prior year. In the
first eight months of 2023, both WTI and WCS were lower than the
same period of 2022, however pricing for both WTI and WCS improved
at the end of the third quarter of 2023, compared to the third
quarter of 2022. In 2023, crude oil prices decreased due to
global economic concerns including weakening demand for crude oil,
the fear of a North American recession and continued high interest
rates implemented to manage inflationary factors. Natural gas
prices in Canada also declined in
2023 due to lower demand, as well as weather related factors
including warmer winter seasons in both North America and Europe, as the 30-day spot AECO price
decreased by 42% and 50% respectively, for the three and nine
months ended September 30, 2023,
compared to the same periods of the prior year. Additionally,
the US dollar to the Canadian dollar foreign exchange rate for the
three and nine months ended September 30,
2023, strengthened by 2% and 5% respectively, compared to
the same periods of the prior year.
In both the US and Canada,
lower commodity prices in the first eight months of the year
reduced industry activity in the third quarter of 2023. As
reported by Baker Hughes Company7, the number
of active drilling rigs in the US decreased by approximately 19% to
623 rigs as at September 30, 2023, as
compared to 765 rigs at September 30,
2022 due to lower commodity prices. In Canada, there were 190 active rigs in the
Western Canadian Sedimentary Basin ("WCSB") at September 30, 2023, compared to 215 active rigs
as at September 30, 2022,
representing a decrease of approximately 12%. The
CAOEC8 reported that for drilling in
Canada, the total number of
Operating Days in the WCSB for the three months ended September 30, 2023, were 7% lower than the same
period in the prior year. For the nine months ended
September 30, 2023, the total number
of Operating Days in the WCSB in Canada were 1% higher than the same period of
the prior year. In addition to lower commodity prices, there
remains continued service industry concerns over the prevailing
customer preference to return cash to shareholders through share
buyback programs and dividends, or pay down debt, rather than grow
production through the drill bit thereby limiting industry drilling
activity.
Outlook
In 2023, crude oil prices have been impacted in the short term
by the fear of a North American recession, concerns surrounding
demand from a weak global economy, continued uncertainty concerning
the ongoing war in Ukraine and
most recently, by the Israel-Palestine conflict in the Middle
East. Events such as these contribute to the volatility of
commodity prices and the precise duration and extent of the adverse
impacts of the current macroeconomic environment on Western's
customers, operations, business and global economic activity,
remains uncertain at this time. Additionally, the threatened
shutdown and relocation of a portion of the Enbridge Line 5
pipeline has contributed to continued uncertainty regarding
takeaway capacity. However, recent positive events such as
the Trans Mountain pipeline expansion, now expected to be
mechanically complete in 2023 and start operating in early 2024,
the Coastal Gaslink pipeline project which is 98% complete, and the
LNG Canada liquefied natural gas project in British Columbia expected to be online in
2025, may contribute to increased industry activity.
Controlling fixed costs, maintaining balance sheet strength and
flexibility, repaying debt and managing through a volatile market
are priorities for the Company, as prices and demand for Western's
services continue to improve.
As a result of the reduced industry activity in the third
quarter of 2023 caused by lower commodity prices in the first eight
months of the year, Western has reduced its capital budget for 2023
to $25 million, which represents a
decrease of $5 million from Western's
previous capital budget of $30
million. The revised budget is comprised of
$8 million of expansion capital and
$17 million of maintenance
capital. Western will continue to manage its costs in a
disciplined manner and make required adjustments to its capital
program as customer demand changes. Currently, 15 of
Western's drilling rigs and 19 of Western's well servicing rigs are
operating.
As at September 30, 2023, Western
had no amounts drawn on its $45.0
million senior secured credit facilities (the "Credit
Facilities") and $6.3 million
outstanding on its HSBC Facility, which matures on December 31, 2026. As at September 30, 2023, Western had $106.6 million outstanding on its second lien
term loan facility with Alberta Investment Management Corporation
(the "Second Lien Facility").
Energy service activity in Canada will be affected by the continued
development of resource plays in Alberta and northeast British Columbia which will be impacted by
continued pipeline construction, environmental regulations, and the
level of investment in Canada. The January 2023 announcement that the government of
British Columbia and the Blueberry
River First Nations reached an agreement which provides a framework
for how resource development may continue within the Blueberry
River First Nations claim area, including the restoration and
future development of land, water and natural resources, has
facilitated an increase in 2023 drilling license approvals, which
should lead to higher demand for Montney and Duvernay class rigs. With Western's
recent drilling rig upgrade program substantially complete, the
Company is well positioned to be the contractor of choice to supply
drilling rigs in a tightening market. Western's upgraded
drilling rigs have all worked for customers since the upgrades were
completed. Western is also active with three fit for purpose
drilling rigs in the Clearwater
formation in northern Alberta. In the short term, the largest
challenges facing the energy service industry are a lack of
qualified field personnel and the restrained growth in customer
drilling activity due to their continuing preference to return cash
to shareholders through share buybacks, increased dividends and
repayment of debt, rather than grow production. If commodity
prices stabilize for an extended period and as customers strengthen
their balance sheets by reducing debt levels, we expect that
drilling activity will increase. In the medium term,
Western's rig fleet is well positioned to benefit from the LNG
Canada liquefied natural gas project and the Trans Mountain
pipeline expansion. Western is an experienced deep horizontal
driller in Canada, with an average
well length of 6,908 meters drilled per well and an average of 12.7
operating days to drill per well for the nine months ended
September 30, 2023. It remains
Western's view that its upgraded drilling rigs and modern well
servicing rigs, reputation for quality and capacity of the
Company's rig fleet, and disciplined cash management provides
Western with a competitive advantage.
7
Source: Baker Hughes Company, 2023 Rig Count monthly press
releases.
8 Source: CAOEC, monthly Contractor
Summary.
|
Non-IFRS Measures and Ratios
Western uses certain financial measures in this press release
which do not have any standardized meaning as prescribed by
International Financial Reporting Standards ("IFRS"). These
measures and ratios, which are derived from information reported in
the condensed consolidated financial statements, may not be
comparable to similar measures presented by other reporting
issuers. These measures and ratios have been described and
presented in this press release to provide shareholders and
potential investors with additional information regarding the
Company. The non-IFRS measures and ratios used in this press
release are identified and defined as follows:
Adjusted EBITDA and Adjusted EBITDA as a Percentage of
Revenue
Adjusted earnings before interest and finance costs, taxes,
depreciation and amortization, other non-cash items and one-time
gains and losses ("Adjusted EBITDA") is a useful non-GAAP financial
measure as it is used by management and other stakeholders,
including current and potential investors, to analyze the Company's
principal business activities prior to consideration of how
Western's activities are financed and the impact of foreign
exchange, income taxes and depreciation. Adjusted EBITDA
provides an indication of the results generated by the Company's
principal operating segments, which assists management in
monitoring current and forecasting future operations, as certain
non-core items such as interest and finance costs, taxes,
depreciation and amortization, and other non-cash items and
one-time gains and losses are removed. The closest IFRS
measure would be net income (loss) for consolidated results.
Adjusted EBITDA as a percentage of revenue is a non-IFRS
financial ratio which is calculated by dividing Adjusted EBITDA by
revenue for the relevant period. Adjusted EBITDA as a
percentage of revenue is a useful financial measure as it is used
by management and other stakeholders, including current and
potential investors, to analyze the profitability of the Company's
principal operating segments.
The following table provides a reconciliation of net income
(loss), as disclosed in the condensed consolidated statements of
operations and comprehensive income, to Adjusted EBITDA:
|
Three months ended
September 30
|
Nine months ended September 30
|
(stated in
thousands)
|
2023
|
2022
|
2023
|
2022
|
|
|
Net income
(loss)
|
(1,267)
|
818
|
(4,691)
|
32,415
|
|
|
Income tax expense
(recovery)
|
(268)
|
1,013
|
(931)
|
3,035
|
|
|
Income (loss) before
income taxes
|
(1,535)
|
1,831
|
(5,622)
|
35,450
|
|
|
Add
(deduct):
|
|
|
|
|
|
|
Gain on debt
forgiveness
|
-
|
-
|
-
|
(49,357)
|
|
|
Depreciation
|
10,283
|
9,744
|
30,831
|
29,652
|
|
|
Stock based
compensation
|
574
|
795
|
2,212
|
1,135
|
|
|
Finance
costs
|
2,789
|
2,946
|
8,710
|
11,428
|
|
|
Other
items
|
(1,078)
|
(517)
|
(1,762)
|
(620)
|
|
|
Adjusted
EBITDA
|
11,033
|
14,799
|
34,369
|
27,688
|
|
|
|
|
|
|
|
|
|
|
|
Revenue per Operating Day
This non-IFRS measure is calculated as total drilling revenue
for both Canada and the US
respectively, divided by Operating Days in Canada and the US respectively. This
calculation represents the average day rate by country charged to
Western's customers.
Revenue per Service Hour
This non-IFRS measure is calculated as total well servicing
revenue divided by total Service Hours. This calculation
represents the average hourly rate charged to Western's
customers.
Working Capital
This non-IFRS measure is calculated as current assets less
current liabilities as disclosed in the Company's condensed
consolidated financial statements.
Defined Terms
Average active rig count (contract drilling): Calculated
as drilling rig utilization multiplied by the average number of
drilling rigs in the Company's fleet for the period.
Average active rig count (production services):
Calculated as service rig utilization multiplied by the average
number of service rigs in the Company's fleet for the period.
Average meters drilled per well: Defined as total meters
drilled divided by the number of wells completed in the period.
Average Operating Days per well: Defined as total
Operating Days divided by the number of wells completed in the
period.
Drilling rig utilization: Calculated based on
Operating Days divided by total available days.
Operating Days: Defined as contract drilling days,
calculated on a spud to rig release basis.
Service Hours: Defined as well servicing hours
completed.
Service rig utilization: Calculated as total
Service Hours divided by 217 hours per month per rig multiplied by
the average rig count for the period as defined by the CAOEC
industry standard.
Contract Drilling Rig Classifications
Cardium class rig: Defined as any contract drilling rig
which has a total hookload less than or equal to 399,999 lbs (or
177,999 daN).
Montney class rig:
Defined as any contract drilling rig which has a total hookload
between 400,000 lbs (or 178,000 daN) and 499,999 lbs (or 221,999
daN).
Duvernay class rig:
Defined as any contract drilling rig which has a total hookload
equal to or greater than 500,000 lbs (or 222,000 daN).
Abbreviations
- Barrel ("bbl");
- Basis point ("bps"): A 1% change equals 100 basis points and a
0.01% change is equal to one basis point;
- Canadian Association of Energy Contractors ("CAOEC");
- DecaNewton ("daN");
- International Financial Reporting Standards ("IFRS");
- Pounds ("lbs");
- Thousand cubic feet ("mcf");
- Western Canadian Sedimentary Basin ("WCSB");
- Western Canadian Select ("WCS"); and
- West Texas Intermediate ("WTI").
Forward-Looking Statements and Information
This press release contains certain forward-looking statements
and forward-looking information (collectively, "forward-looking
information") within the meaning of applicable Canadian securities
laws, as well as other information based on Western's current
expectations, estimates, projections and assumptions based on
information available as of the date hereof. All information
and statements contained herein that are not clearly historical in
nature constitute forward-looking information, and words and
phrases such as "may", "will", "should", "could", "expect",
"intend", "anticipate", "believe", "estimate", "plan", "predict",
"potential", "continue", or the negative of these terms or other
comparable terminology are generally intended to identify
forward-looking information. Such information represents the
Company's internal projections, estimates or beliefs concerning,
among other things, an outlook on the estimated amounts and timing
of additions to property and equipment, anticipated future debt
levels and revenues or other expectations, beliefs, plans,
objectives, assumptions, intentions or statements about future
events or performance. This forward-looking information
involves known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from
those anticipated in such forward-looking information.
In particular, forward-looking information in this press release
includes, but is not limited to, statements relating to: the
business of Western; industry, market and economic conditions and
any anticipated effects on Western; commodity pricing; the future
demand for the Company's services and equipment, in particular, the
Company's expectations regarding improved activity in 2023;
Western's expectations regarding prevailing customer preferences;
the effect of inflation and commodity prices on customer spending;
the success of Western's drilling rig upgrade program; the
potential impact of the current conflict in Ukraine on crude oil prices; the
potential impact of a North American recession; the potential
impact of a weak economy on demand for crude oil; the
potential impact of the conflict in Israel on crude oil prices; revisions to the
Company's capital budget for 2023, including the allocation of such
budget; Western's plans for managing its capital program; the
energy service industry and global economic activity; expectations
with respect to the Trans Mountain pipeline expansion; the
potential shutdown and relocation of the Enbridge Line 5 pipeline;
expectations with respect to the Coastal GasLink pipeline project
and LNG Canada facility; the impact of the Blueberry River First
Nations decision; the development of Alberta and British
Columbia resource plays; challenges facing the energy
service industry; expectations as to the benefits of the LNG Canada
natural gas project in British
Columbia on the Company and its rig fleet; expectations
relating to producer spending and activity levels for oilfield
services; and the Company's ability to maintain a competitive
advantage, including the factors and practices anticipated to
produce and sustain such advantage.
The material assumptions that could cause results or events to
differ from current expectations reflected in the forward-looking
information in this press release include, but are not limited to:
demand levels and pricing for oilfield services; demand for crude
oil and natural gas and the price and volatility of crude oil and
natural gas; pressures on commodity pricing; the impact of
inflation; the continued business relationships between the Company
and its significant customers; crude oil transport, pipeline and
LNG export facility approval and development; that all required
regulatory and environmental approvals can be obtained on the
necessary terms and in a timely manner, as required by the Company;
liquidity and the Company's ability to finance its operations; the
effectiveness of the Company's cost structure and capital budget;
the effects of seasonal and weather conditions on operations and
facilities; the competitive environment to which the various
business segments are, or may be, exposed in all aspects of their
business and the Company's competitive position therein; the
ability of the Company's various business segments to access
equipment (including spare parts and new technologies); global
economic conditions and the accuracy of the Company's market
outlook expectations for 2023 and in the future; the impact, direct
and indirect, of the COVID-19 pandemic and geopolitical events,
including the war in Ukraine and
the conflict in Israel on
Western's business, customers, business partners, employees, supply
chain, other stakeholders and the overall economy; changes in laws
or regulations; currency exchange fluctuations; the ability of the
Company to attract and retain skilled labour and qualified
management; the ability to retain and attract significant
customers; the ability to maintain a satisfactory safety record;
that any required commercial agreements can be reached; that there
are no unforeseen events preventing the performance of contracts
and general business, economic and market conditions.
Although Western believes that the expectations and assumptions
on which such forward-looking information is based on are
reasonable, undue reliance should not be placed on the
forward-looking information as Western cannot give any assurance
that such will prove to be correct. By its nature,
forward-looking information is subject to inherent risks and
uncertainties. Actual results could differ materially from
those currently anticipated due to a number of factors and
risks. These include, but are not limited to, volatility in
market prices for crude oil and natural gas and the effect of this
volatility on the demand for oilfield services generally; reduced
exploration and development activities by customers and the effect
of such reduced activities on Western's services and products;
political, industry, market, economic, and environmental conditions
in Canada, the US, Ukraine and globally; supply and demand for
oilfield services relating to contract drilling, well servicing and
oilfield rental equipment services; the proximity, capacity and
accessibility of crude oil and natural gas pipelines and processing
facilities; liabilities and risks inherent in oil and natural gas
operations, including environmental liabilities and risks; changes
to laws, regulations and policies; the ongoing geopolitical events
in Eastern Europe and the duration
and impact thereof; fluctuations in foreign exchange or interest
rates; failure of counterparties to perform or comply with their
obligations under contracts; regional competition and the increase
in new or upgraded rigs; the Company's ability to attract and
retain skilled labour; Western's ability to obtain debt or equity
financing and to fund capital operating and other expenditures and
obligations; the potential need to issue additional debt or equity
and the potential resulting dilution of shareholders; uncertainties
in weather and temperature affecting the duration of the service
periods and the activities that can be completed; the Company's
ability to comply with the covenants under the Credit Facilities,
HSBC Facility and the Second Lien Facility and the restrictions on
its operations and activities if it is not compliant with such
covenants; Western's ability to protect itself from "cyber-attacks"
which could compromise its information systems and critical
infrastructure; disruptions to global supply chains; and other
general industry, economic, market and business conditions.
Readers are cautioned that the foregoing list of risks,
uncertainties and assumptions are not exhaustive. Additional
information on these and other risk factors that could affect
Western's operations and financial results are discussed under the
headings "Risk Factors" in Western's annual information form
for the year ended December 31, 2022,
which may be accessed through the SEDAR+ website at
www.sedarplus.ca.
The forward-looking statements and information contained in this
news release are made as of the date hereof and Western does not
undertake any obligation to update publicly or revise any
forward-looking statements and information, whether as a result of
new information, future events or otherwise, unless so required by
applicable securities laws. Any forward-looking statements
contained herein are expressly qualified by this cautionary
statement.
SOURCE Western Energy Services Corp.