CALGARY, AB, March 24, 2022 /CNW/ - Western Energy
Services Corp. ("Western" or the "Company") (TSX: WRG) announces
the release of its fourth quarter and year end 2021 financial and
operating results. Additional information relating to the
Company, including the Company's financial statements and
management's discussion and analysis ("MD&A") as at and for the
year ended December 31, 2021 and 2020
will be available on SEDAR at www.sedar.com.
Non-International Financial Reporting Standards ("Non-IFRS")
measures and ratios, such as Adjusted EBITDA and Adjusted EBITDA as
a percentage of revenue, 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.
Fourth Quarter 2021 Operating Results:
- Fourth quarter revenue increased by $13.7 million or 49%, to $41.4 million in 2021 as compared to $27.7 million in the fourth quarter of
2020. In the contract drilling segment, revenue totalled
$25.1 million in the fourth quarter
of 2021, an increase of $9.8 million
or 64%, compared to $15.3 million in
the fourth quarter of 2020. In the production services
segment, revenue totalled $16.4
million for the three months ended December 31, 2021, as compared to $12.5 million in the same period of the prior
year, an increase of $3.9 million or
31%. While the ongoing COVID-19 pandemic continued to impact
the contract drilling and production services segments in the
fourth quarter of 2021, demand improved compared to 2020 as
described below:
-
- Drilling rig utilization in Canada averaged 21% in the fourth quarter of
2021, compared to 15% in the fourth quarter of 2020. The
increase in activity in the fourth quarter of 2021 was mainly
attributable to the improved demand resulting from the ongoing
COVID-19 vaccination rollouts and the lifting of government
restrictions which re-opened the economy, compared to the fourth
quarter of 2020 when the COVID-19 pandemic impacted demand across
the industry. The Canadian Association of Energy Contractors
("CAOEC") industry average utilization of
30%1 for the fourth quarter of 2021
represented an increase of 1,400 basis points ("bps") compared to
the CAOEC industry average of 16% in the fourth quarter of
2020. Western's market share, represented by the Company's
Operating Days as a percentage of the CAOEC's total Operating Days
in the Western Canadian Sedimentary Basin ("WCSB"), decreased to
7.1% for the fourth quarter of 2021, as compared to 9.0% in the
same period of 2020, as a result of limited capital spent on rig
upgrades during the economic downturn. Revenue per Operating
Day averaged $24,014 in the fourth
quarter of 2021, an increase of 15% compared to the same period of
the prior year, mainly due to improved market rates, as well as the
CAOEC wage increase in 2021;
- In the United States ("US"),
drilling rig utilization averaged 14% in the fourth quarter of
2021, compared to 6% in the fourth quarter of 2020, with Operating
Days improving from 43 days in 2020 to 100 days in 2021.
Revenue per Operating Day for the fourth quarter of 2021 was
US$20,092, a 23% increase compared to
US$16,273 in the same period of the
prior year, mainly due to changes in average active rig mix and
improved market conditions; and
- In Canada, service rig
utilization of 33% in the fourth quarter of 2021 was higher than
27% in the same period of the prior year, mainly due to improved
market activity, as well as funding programs such as the Alberta
Government's site rehabilitation program increasing demand for the
Company's services. However, service rig utilization in the
fourth quarter of 2021 was negatively impacted by field crew
shortages across the industry. Revenue per Service Hour
averaged $780 in the fourth quarter
of 2021 and was 14% higher than the fourth quarter of 2020, as a
result of improved market conditions, as well as increased labour
and fuel charges being passed through to the customer. Higher
utilization led to production services revenue totaling
$16.4 million in the fourth quarter
of 2021, an increase of $3.9 million
or 31%, as compared to the same period in the prior year.
- Administrative expenses decreased by $0.1 million or 2%, to $2.5 million in the fourth quarter of 2021, as
compared to $2.6 million in the
fourth quarter of 2020, mainly due to lower employee related costs,
which was partially offset by reduced receipts related to the
Canada Emergency Wage Subsidy
("CEWS") from the Government of Canada as the program ended October 2021.
- The Company incurred a net loss of $6.0
million in the fourth quarter of 2021 ($0.07 per basic common share) as compared to a
net loss of $7.4 million in the same
period in 2020 ($0.08 per basic
common share). The change can mainly be attributed to a
$1.8 million decrease in income tax
recovery, a $1.0 million decrease in
other items which mainly consisted of the sale of assets and a
$0.3 million increase in finance
costs, offset partially by a $3.4
million increase in Adjusted EBITDA, and a $1.0 million decrease in depreciation expense due
to certain assets being fully depreciated in the period.
- Fourth quarter Adjusted EBITDA of $9.0
million in 2021 was 60% higher compared to $5.6 million in the fourth quarter of 2020.
Adjusted EBITDA was higher due to improved activity in Canada and the US, offset partially by a
decrease of $3.5 million in CEWS
received, compared to the same period in 2020.
- Fourth quarter 2021 additions to property and equipment of
$2.1 million compared to $1.8 million incurred in the fourth quarter of
2020 and consist of $0.1 million of
expansion capital and $2.0 million of
maintenance capital.
- As previously announced on December 30,
2021, the Company deferred the interest payment on its
second lien secured term loan facility (the "Second Lien Facility")
originally due on January 4, 2022
until February 28, 2022 which was
further deferred to March 21, 2022
and then paid "in kind" by being added to the outstanding principal
amount.
- On March 22, 2022, Western
announced that it had entered into agreements to restructure a
portion of its outstanding debt and raise new capital (the
"Restructuring Transaction"). Pursuant to the Restructuring
Transaction, Western entered into a debt restructuring agreement
(the "Debt Restructuring Agreement") with Alberta Investment
Management Corporation ("AIMCo"), the lender under its second lien
secured term loan (the "Second Lien Facility"). Under the
Debt Restructuring Agreement, subject to the completion of the
other components of the Restructuring Transaction and the
satisfaction of certain other conditions, the Company will convert
$100.0 million of the principal
amount outstanding under the Second Lien Facility into common
shares at a conversion price of $0.05
per share, subject to reduction in the event the offering price in
the Rights Offering (defined below) is less than $0.016 per share (the "Debt Exchange"). On
completion of the Debt Exchange, the Second Lien Facility will be
amended to, among other things, extend its maturity date from
January 31, 2023 to the fourth
anniversary of the closing date of the Debt Exchange.
-
- As a condition to the completion of the Debt Exchange, the
Company will conduct a rights offering of common shares to all of
its shareholders to raise proceeds of $31.5
million (the "Rights Offering"). The subscription price for
each right will be $0.016 per share
or a lower amount determined based on the market price of the
common shares at the commencement of the Rights Offering. G2S2
Capital Inc. ("G2S2"), G2S2's subsidiary Armco Alberta Inc.
("Armco"), Ronald P. Mathison and
Matco Investments Ltd. ("Matco"), currently the Company's largest
shareholders, have entered into a standby purchase agreement with
the Company wherein they have agreed to exercise in full their
basic subscription privilege in the Rights Offering and, in the
case of each of Armco and Matco, subscribe for any shares not
subscribed for by other shareholders under the Rights Offering. The
proceeds of the Rights Offering will be applied to reduce the
principal amount outstanding under the Second Lien Facility by
$10.0 million, with the remaining
$21.5 million being applied to repay
the current draw on the Company's senior secured credit facilities,
fund maintenance and growth capital for the Company and for general
corporate purposes.
It is also a condition to completion of the Debt Exchange that the
Company and AIMCo enter into a registration rights agreement
pursuant to which AIMCo will be granted the right to cause the
Company to file a prospectus to facilitate the sale of its common
shares in a public offering, or to allow it to participate in a
public offering of common shares by the Company, in each case
subject to certain customary restrictions and limitations. The
Registration Rights Agreement will terminate when AIMCo and its
permitted transferees beneficially own, in the aggregate, less than
10% of the then outstanding common shares and further that the
Company, AIMCo, G2S2, Armco, Matco and Mr. Mathison will enter into
an investor rights agreement pursuant to which AIMCo will be
granted the right to appoint two nominees for election as directors
of the Company for so long as AIMCo's shareholding percentage of
the Company's common shares is 30% or greater.
In connection with the Restructuring Transaction, Western has
entered into a commitment letter with two of the lenders under its
senior secured credit agreement to make certain amendments to its
senior secured credit facilities. Upon completion of the
Restructuring Transaction, the principal amount of the Second Lien
Facility is expected to be approximately $108.5 million and
AIMCo is expected to hold approximately 49.7% of the outstanding
common shares.
Completion of the Restructuring Transaction is subject to various
conditions, including completion of definitive amendments to the
Second Lien Facility agreement and the senior secured credit
facility substantially on the terms specified in the Debt
Restructuring Agreement, approval of the
Restructuring Transaction by the Toronto Stock Exchange and
completion of the Rights Offering. Details of the
Restructuring Transaction and proposed amendments to Western's
senior credit facilities are contained in the press release filed
under Western's SEDAR profile on www.sedar.com.
2021 Operating Results:
- Revenue for the year ended December 31,
2021, increased by $28.0
million or 27%, to $131.7
million as compared to $103.7
million for the year ended December
31, 2020. Contract drilling revenue totalled
$76.8 million in 2021, an increase of
$14.8 million or 24%, as compared to
$62.0 million in 2020.
Production services revenue totalled $55.5
million for the year ended December
31, 2021, as compared to $42.1
million in the same period of the prior year, an increase of
$13.4 million or 32%. While the
ongoing COVID-19 pandemic continues to have an impact on revenue in
the contract drilling and production services segments, demand
began to recover in 2021 as described below:
-
- Drilling rig utilization in Canada averaged 18% for the year ended
December 31, 2021, compared to 12%
for the year ended December 31, 2020,
a 600 bps increase. The increase in activity in 2021 was
mainly attributable to the improved demand resulting from the
ongoing COVID-19 vaccination rollouts and the lifting of government
restrictions which re-opened the economy, compared to 2020 when the
COVID-19 pandemic significantly impacted demand across the
industry. The CAOEC industry average of
25%2 for the year ended December 31, 2021, represented an increase of 900
bps compared to the CAOEC industry average of 16% for the prior
year. Western's market share, represented by the Company's
Operating Days as a percentage of the CAOEC's total Operating Days
in the WCSB, was 7.1% for the year ended December 31, 2021, which was consistent with 7.0%
in the prior year due to changes in average customer mix.
Revenue per Operating Day decreased by 6% for the year ended
December 31, 2021, as compared to the
prior year, as current market rates weakened in the first part of
2021 but showed improvement in the fourth quarter of 2021;
- In the United States, drilling
rig utilization averaged 13% in 2021, compared to 7% in the prior
year, reflecting a 93% increase in Operating Days. Revenue
per Operating Day for the year ended December 31, 2021, decreased by 26% to average
US$16,615, as compared to
US$22,594 in the prior year, due to
changes in average active rig mix as there were no Operating Days
worked on long term contracts in 2021 compared to 2020 when one rig
was under contract; and
- In Canada, service rig
utilization of 29% for the year ended December 31, 2021 was higher than the prior year
due to improved industry demand as a result of improved commodity
prices, however was impacted by field crew shortages in the last
half of 2021. Service Hours improved year over year, and 2021
had a higher proportion of abandonment work than 2020, due to
previously announced government incentives. Revenue per
Service Hour averaged $735 for the
year ended December 31, 2021 and was
6% higher than the same period of 2020. Improved utilization
led to production services revenue totaling $55.5 million for the year ended December 31, 2021, an increase of $13.4 million or 32%, as compared to the prior
year.
- Administrative expenses increased by $0.2 million or 2%, to $10.7 million for the year ended December 31, 2021, as compared to $10.5 million in the prior year, mainly due to a
decrease in the CEWS received related to administrative expenses in
2021, as a result of the CEWS program ending in October 2021 and the CEWS rates decreasing as the
program ended.
- The Company incurred a net loss of $35.8
million for the year ended December
31, 2021 ($0.39 per basic
common share) as compared to a net loss of $41.3 million in the prior year ($0.45 per basic common share). The change
is mainly attributable to an asset impairment of $11.5 million in 2020, a $6.3 million decrease in depreciation expense in
2021 due to certain assets being fully depreciated in the period,
and a $2.7 million increase in
Adjusted EBITDA, which were offset partially by an $11.1 million decrease in income tax recovery, a
$2.4 million decrease in other items
and a $1.7 million increase in
finance costs.
- Adjusted EBITDA for the year ended December 31, 2021 was $2.7
million higher than the prior year and totalled $23.0 million, compared to $20.3 million in 2020. Adjusted EBITDA in
2021 was higher due to improved activity in both Canada and the US and an increase in the CEWS
of $0.4 million due to 2021 including
11 months of CEWS compared to only 8 months in 2020, which was
partially offset by US$5.0 million of
shortfall commitment revenue received in 2020 with none in
2021.
- Year to date additions to property and equipment in 2021 of
$6.9 million compared to $2.8 million incurred in the same period of 2020,
consisting of $1.1 million of
expansion capital and $5.8 million of
maintenance capital.
Selected Financial
Information
|
(stated in
thousands, except share and per share amounts)
|
|
Three months ended
December 31
|
Year ended
December 31
|
Financial
Highlights
|
2021
|
2020
|
Change
|
2021
|
2020
|
Change
|
Revenue
|
41,363
|
27,679
|
49%
|
131,678
|
103,684
|
27%
|
Adjusted
EBITDA(1)
|
8,950
|
5,610
|
60%
|
23,047
|
20,278
|
14%
|
Adjusted EBITDA as a
percentage of revenue(1)
|
22%
|
20%
|
10%
|
18%
|
20%
|
(10%)
|
Cash flow from
operating activities
|
8,236
|
2,011
|
310%
|
16,631
|
27,723
|
(40%)
|
Additions to property
and equipment
|
2,107
|
1,805
|
17%
|
6,866
|
2,788
|
146%
|
Net loss
|
(6,021)
|
(7,443)
|
(19%)
|
(35,812)
|
(41,301)
|
(13%)
|
– basic and diluted net
loss per share
|
(0.07)
|
(0.08)
|
(13%)
|
(0.39)
|
(0.45)
|
(13%)
|
Weighted average
number of shares
|
|
|
|
|
|
|
– basic and
diluted
|
91,699,989
|
91,165,112
|
1%
|
91,372,740
|
91,253,521
|
-
|
Outstanding common
shares as at period end
|
91,706,457
|
91,165,112
|
1%
|
91,706,457
|
91,165,112
|
1%
|
(1) See
"Non-IFRS measures" included in this press release.
|
|
|
|
|
|
Three months ended
December 31
|
Year ended
December 31
|
Operating
Highlights(2)
|
2021
|
2020
|
Change
|
2021
|
2020
|
Change
|
Contract
Drilling
|
|
|
|
|
|
|
Canadian
Operations:
|
|
|
|
|
|
|
Contract drilling rig
fleet:
|
|
|
|
|
|
|
–
Average active rig count
|
10.2
|
7.3
|
40%
|
8.6
|
5.6
|
54%
|
– End of
period
|
49
|
49
|
-
|
49
|
49
|
-
|
Operating
Days
|
940
|
675
|
39%
|
3,124
|
2,064
|
51%
|
Revenue per Operating
Day
|
24,014
|
20,883
|
15%
|
21,931
|
23,417
|
(6%)
|
Drilling rig
utilization
|
21%
|
15%
|
40%
|
18%
|
12%
|
50%
|
CAOEC industry
average utilization – Operating Days(3)
|
30%
|
16%
|
88%
|
25%
|
16%
|
56%
|
|
|
|
|
|
|
|
United States
Operations:
|
|
|
|
|
|
|
Contract drilling rig
fleet:
|
|
|
|
|
|
|
–
Average active rig count
|
1.1
|
0.5
|
120%
|
1.1
|
0.6
|
83%
|
– End of
period
|
8
|
8
|
-
|
8
|
8
|
-
|
Operating
Days
|
100
|
43
|
133%
|
387
|
201
|
93%
|
Revenue per Operating
Day (US$)
|
20,092
|
16,273
|
23%
|
16,615
|
22,594(4)
|
(26%)
|
Drilling rig
utilization
|
14%
|
6%
|
133%
|
13%
|
7%
|
86%
|
|
|
|
|
|
|
|
Production
Services
|
|
|
|
|
|
|
Canadian
Operations:
|
|
|
|
|
|
|
Well servicing rig
fleet:
|
|
|
|
|
|
|
–
Average active rig count
|
20.7
|
17.3
|
20%
|
18.4
|
14.6
|
26%
|
– End of
period
|
63
|
63
|
-
|
63
|
63
|
-
|
Service
Hours
|
19,046
|
15,924
|
20%
|
67,323
|
53,351
|
26%
|
Revenue per Service
Hour
|
780
|
685
|
14%
|
735
|
693
|
6%
|
Service rig
utilization
|
33%
|
27%
|
22%
|
29%
|
23%
|
26%
|
(2)
|
See "Defined Terms"
included in this press release.
|
(3)
|
Source: The
Canadian Association of Energy Contractors ("CAOEC") monthly
Contractor Summary. The CAOEC industry average is based on
Operating Days divided by total available drilling days.
|
(4)
|
Excludes shortfall
commitment revenue from take or pay contracts of US$5.0 million for
the year ended December 31, 2020.
|
Financial Position
at (stated in thousands)
|
December
31, 2021
|
|
December 31,
2020
|
December 31,
2019
|
Working
capital
|
2,224(5)
|
|
15,997
|
7,031
|
Total
assets
|
456,003
|
|
495,625
|
550,537
|
Long term
debt
|
226,884
|
|
237,633
|
228,274
|
(5)
|
As at December 31,
2021, working capital of $2.2 million includes the classification
of the Company's $8.0 million draw on its credit facility as a
current liability, as described on page 12 of the Company's
Management Discussion and Analysis for the year ended December 31,
2021, under Liquidity and Capital Resources.
|
Business Overview
Western is an energy services company that provides contract
drilling services and production services in Canada and the
United States through its various divisions, subsidiaries,
and first nations joint venture.
Contract Drilling Services
Western operates a fleet of 57 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
rigs3. Subsequent to December 31, 2021, Western deregistered 12
drilling rigs with the CAOEC, all of which can be reactivated at a
later date.
Production Services
Production Services provides well servicing and oilfield
equipment rentals primarily in Canada. Western operates 63 well servicing
rigs and is the third largest well servicing company in
Canada based on CAOEC registered
well servicing rigs4. During the fourth quarter of
2021, the Company sold three well servicing rigs that operated in
the United States.
Western's contract drilling and well servicing rig fleets
comprise the following:
December
31
|
Drilling
rigs
|
|
Well servicing
rigs
|
|
2021
|
|
2020
|
|
2021
|
2020
|
|
Rig
class(1)
|
Canada
|
US
|
Total
|
|
Canada
|
US
|
Total
|
|
Mast
type
|
Total
|
Total
|
|
Cardium
|
23
|
2
|
25
|
|
23
|
2
|
25
|
|
Single
|
30
|
33
|
|
Montney
|
19
|
-
|
19
|
|
19
|
-
|
19
|
|
Double
|
25
|
25
|
|
Duvernay
|
7
|
6
|
13
|
|
7
|
6
|
13
|
|
Slant
|
8
|
8
|
|
Total
|
49
|
8
|
57
|
|
49
|
8
|
57
|
|
|
63
|
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
See "Defined Terms"
included in this press release.
|
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 months ended December 31,
2021 and 2020 and for the years ended December 31, 2021 and 2020.
|
|
|
|
Three months ended
December 31
|
Year ended
December 31
|
|
2021
|
2020
|
Change
|
2021
|
2020
|
Change
|
Average crude oil
and natural gas prices(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil
|
|
|
|
|
|
|
West Texas
Intermediate (US$/bbl)
|
77.19
|
42.66
|
81%
|
67.91
|
39.40
|
72%
|
Western Canadian
Select (CDN$/bbl)
|
78.71
|
43.42
|
81%
|
68.73
|
35.59
|
93%
|
|
|
|
|
|
|
|
Natural
Gas
|
|
|
|
|
|
|
30 day Spot AECO
(CDN$/mcf)
|
4.92
|
2.74
|
80%
|
3.77
|
2.18
|
63%
|
|
|
|
|
|
|
|
Average foreign
exchange rates(2)
|
|
|
|
|
|
|
US dollar to Canadian
dollar
|
1.26
|
1.30
|
(3%)
|
1.25
|
1.34
|
(7%)
|
(1) See
"Abbreviations" included in this press release.
|
(2) Source: Sproule
December 31, 2021 Price Forecast, Historical Prices
|
West Texas Intermediate ("WTI") on average improved by 81% and
72% for the three months and year ended December 31, 2021 respectively, compared to the
same periods in the prior year. Similarly, pricing on Western
Canadian Select ("WCS") crude oil increased by 81% and 93%
respectively, for the three months and year ended December 31, 2021, compared to the same periods
in the prior year. Crude oil prices in 2020 for both
Canada and the US were
significantly impacted by the COVID-19 pandemic. However, in
2021 pricing improved as demand for crude oil recovered and vaccine
rollouts continued worldwide. Natural gas prices in
Canada also strengthened in 2021,
as the 30-day spot AECO price improved by 80% and 63% respectively,
for the three months and year ended December
31, 2021, compared to the same periods of the prior
year. Offsetting this increase in pricing, the US dollar to
the Canadian dollar foreign exchange rate weakened in the three
months and year ended December 31,
2021, compared to the same periods of the prior year, which
impacted the cash flows of Western's Canadian customers, when
selling US dollar denominated commodities.
In the United States, industry
activity improved in the fourth quarter of 2021. As reported
by Baker Hughes Company5, the number of
active drilling rigs in the United
States increased by approximately 67% to 586 rigs at
December 31, 2021, as compared to 351
rigs at December 31, 2020. The
number of active rigs in the WCSB totalled 73 active rigs at
December 31, 2021, compared to 67
active rigs at December 31,
2020. The CAOEC6 reported that for
drilling in Canada, the total
number of Operating Days in the WCSB increased by approximately 76%
for the three months ended December 31,
2021, compared to the same period in the prior year.
Similarly, for the year ended December 31,
2021, the total number of Operating Days in the WCSB
increased by approximately 48%, compared to the prior year.
There remains continued industry concerns over the prevailing
customer preference to return cash to shareholders, or pay down
debt, rather than grow production through the drill bit in
Canada and the US.
Outlook
In 2021, crude oil prices recovered after reaching historical
lows in 2020 due to the demand destruction caused by the COVID-19
pandemic. However, heightened uncertainty persists concerning
the impact of global COVID-19 variants on possible future
government restrictions, which have an impact on demand in the near
term. The precise duration and extent of the adverse impacts
of the current macroeconomic environment and the COVID-19 pandemic
on Western's customers, operations, business and global economic
activity remains highly uncertain at this time. Additionally,
the January 2021 executive order by
the President of the United States
cancelling the permit that had allowed construction of the Keystone
XL pipeline, the uncertain timing of completion of construction on
the Trans Mountain pipeline expansion and the threatened shutdown
of Enbridge Line 5, have all resulted in continued uncertainty
regarding takeaway capacity. However, activity levels in 2022
are expected to be higher than 2021 levels as a result of increased
capital spending by Western's customers. Controlling fixed
costs, maintaining balance sheet strength and flexibility and
managing through a post-pandemic market are priorities for the
Company, as prices and demand for Western's services continue to
improve.
Due to increased activity levels in 2021 as a result of the
successful COVID-19 vaccine rollout, lifting of government
restrictions, and limited maintenance capital spending on the rig
fleet in prior years, Western's capital budget for the first
quarter of 2022 is expected to total approximately $8.1 million. The budgeted capital is
expected to be comprised of $3.5
million of maintenance capital and $4.6 million of expansion capital, with
$6.5 million allocated to the
contract drilling segment and $1.6
million allocated to the production services segment.
The Company's Board of Directors plans to review and evaluate the
Company's 2022 capital budget for the remainder of the year and
revise as necessary depending on market conditions. Western
will continue to manage its costs in a disciplined manner and make
required adjustments to its capital program as customer demand
changes. Currently, 10 of Western's drilling rigs and 26 of
Western's well servicing rigs are operating.
As at December 31, 2021, Western had
$8.0 million drawn on its
$60.0 million Credit
Facilities. As described previously, subsequent to
December 31, 2021, the Company agreed
to amend the terms of its Credit Facilities, including extending
the maturity date and amending its financial covenants.
Western had drawn $12.5 million on
its HSBC Bank Canada six-year committed term non-revolving facility
with the participation of Business Development Canada (the "HSBC
Facility"), which matures on December
31, 2026. Western currently has $218.5 million outstanding on its Second Lien
Facility. As previously announced on March 22, 2022, the Company has entered into a
Debt Restructuring Agreement with AIMCo, pursuant to which the
maturity date of the Second Lien Facility will be extended upon
completion of the Debt Restructuring Transaction. The Debt
Restructuring Transaction will result in the repayment of
$100.0 million of Second Lien
Facility principal which will reduce the Company's finance costs on
a go forward basis. Additionally, the $31.5 million proceeds from the Rights Offering
will be used to repay $10.0 million
of principal on the Second Lien Facility, the current draw on the
Company's Credit Facilities and invest the remainder in capital
upgrades on its drilling rig fleet.
Oilfield 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. In the short term, the largest
challenges facing the oilfield service industry are a lack of
qualified field personnel and ongoing liquidity concerns, due to
the prevailing customer preference to return cash to shareholders
through share buybacks, increased dividends or repayment of debt,
rather than grow production. In the medium term, Western's
rig fleet is well positioned to benefit from the LNG Canada
liquefied natural gas project now under construction in British
Columbia. It remains Western's view that its modern drilling
and well servicing rig fleets, reputation, and disciplined cash
management provides Western with a competitive
advantage.
Non-IFRS Measures and Ratios
Western uses certain measures in this press release which do not
have any standardized meaning as prescribed by International
Financial Reporting Standards ("IFRS"). These measures, which
are derived from information reported in the consolidated financial
statements, may not be comparable to similar measures presented by
other reporting issuers. These measures have been described
and presented in this press release in order to provide
shareholders and potential investors with additional information
regarding the Company. The Non-IFRS measure used in this
press release is identified and defined as follows:
Adjusted EBITDA
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 supplemental measure as it
is used by management and other stakeholders, including current and
potential investors, to analyze the Company's principal business
activities. 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 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 supplemental 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 loss, as
disclosed in the consolidated statements of operations and
comprehensive income, to Adjusted EBITDA:
|
|
|
|
Three months ended
December 31
|
Year ended
December 31
|
(stated in
thousands)
|
2021
|
2020
|
2021
|
2020
|
Net
loss
|
(6,021)
|
(7,443)
|
(35,812)
|
(41,301)
|
Income tax
recovery
|
(1,038)
|
(2,828)
|
(3,457)
|
(14,609)
|
Loss before income
taxes
|
(7,059)
|
(10,271)
|
(39,269)
|
(55,910)
|
Add
(deduct):
|
|
|
|
|
Depreciation
|
10,263
|
11,314
|
42,024
|
48,268
|
Stock based
compensation
|
34
|
130
|
253
|
449
|
Finance
costs
|
4,720
|
4,381
|
19,664
|
17,963
|
Other items
|
992
|
56
|
375
|
(1,992)
|
Impairment of property
and equipment
|
-
|
-
|
-
|
11,500
|
Adjusted
EBITDA
|
8,950
|
5,610
|
23,047
|
20,278
|
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.
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 based on
Service Hours divided by available hours, being 10 hours per day,
per well servicing rig, 365 days per year.
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: commodity
pricing; the future demand for the Company's services and
equipment, in particular, the expectation of improved activity
levels in 2022 as a result of increased capital spending by
Western's customers; the potential impact of the ongoing COVID-19
pandemic on Western's customers, operations, business and global
economic activity; the pricing for the Company's services and
equipment; Western's maintenance and expansion capital plans for
2022, including with respect to the Company's capital budget of
approximately $8.1 million for the
first quarter of 2022, and its ability to make changes thereto in
response to customer demands; the Company's liquidity needs
including the ability of current capital resources to cover
Western's financial obligations; the use, availability and
sufficiency of the Company's Credit Facilities; the Company's
ability to maintain certain covenants under its Credit Facilities;
the repayment of the Company's debt; maturities of the Company's
contractual obligations with third parties; opportunities relating
to Debt Restructuring Transaction; expectations as to the changes
in crude oil transportation capacity through pipeline developments
and uncertainties related thereto; expectations as to the benefits
of the LNG Canada natural gas project in British Columbia on the Company and its rig
fleet; the potential impact of changes to laws, governmental and
environmental regulations, and the price on carbon emissions; the
expectation of continued investment in the Canadian crude oil and
natural gas industry; the development of Alberta and British
Columbia resource plays; expectations relating to producer
spending and activity levels for oilfield services; the Company's
ability to maintain a competitive advantage; and the Company's
ability to find and maintain enough field crew members.
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 continued business
relationships between the Company and its significant customers;
crude oil transport, pipeline and LNG export facility approval and
development; 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 2022 and in the future; the impact, direct
and indirect, of the COVID-19 pandemic 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;
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, the ongoing
impact of the COVID-19 pandemic on global demand and prices for oil
and gas, including the impact on demand for Western's services;
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, economic, and environmental
conditions in Canada, the United States and globally; supply and
demand for oilfield services relating to contract drilling, well
servicing and oilfield rental equipment services; changes to laws,
regulations and policies; 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; 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 AIF for the year ended December
31, 2021, which may be accessed through the SEDAR website at
www.sedar.com. 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.
1 Source:
CAOEC, monthly Contractor Summary.
|
2 Source:
CAOEC, monthly Contractor Summary.
|
3 Source:
CAOEC Contractor Summary as at March 24, 2022.
|
4 Source:
CAOEC Fleet List as at March 24, 2022.
|
5 Source: Baker Hughes Company, 2021
Rig Count monthly press releases.
|
6 Source: CAOEC, monthly Contractor
Summary.
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SOURCE Western Energy Services Corp.