Oct. 25, 2017, CALGARY /CNW/ - Western Energy Services Corp.
("Western" or the "Company") (TSX: WRG) announces the release of
its third quarter 2017 financial and operating results.
Additional information relating to the Company, including the
Company's financial statements and management's discussion and
analysis as at and for the three and nine months ended September 30, 2017 and 2016 will be available on
SEDAR at www.sedar.com. Non-International Financial Reporting
Standards ("Non-IFRS") measures and abbreviations for standard
industry terms are included in this press release. All
amounts are denominated in Canadian dollars (CDN$) unless otherwise
identified.
Third Quarter 2017 Operating Results:
- Operating Revenue in the third quarter of 2017 benefited from
improved crude oil prices and resulted in higher customer spending
and a corresponding increase in demand for Western's services.
Third quarter Operating Revenue increased by $20.4 million (or 67%) to $51.1 million in 2017 as compared to $30.7 million in 2016. In the contract drilling
segment, Operating Revenue totalled $38.7
million in the third quarter of 2017 as compared to
$20.2 million in the third quarter of
2016, an increase of $18.5 million
(or 92%); while in the production services segment, Operating
Revenue totalled $12.4 million for
the three months ended September 30,
2017 as compared to $10.5
million in the third quarter of 2016, an increase of
$1.9 million (or 19%). Higher
utilization in the third quarter of 2017, and improved pricing in
all divisions, positively impacted Operating Revenue in the
contract drilling and production services segments as described
below:
-
- Drilling rig utilization – Operating Days ("Drilling Rig
Utilization") in Canada averaged
36% in the third quarter of 2017 compared to an average of 20% in
the third quarter of 2016, reflecting a 1,600 basis points ("bps")
increase. Third quarter 2017 Drilling Rig Utilization represented a
premium of 700 bps to the Canadian Association of Oilwell Drilling
Contractors ("CAODC") industry average of 29%, whereas in the third
quarter of 2016, Drilling Rig Utilization of 20% represented a 300
bps premium to the industry average. The increase in the Company's
utilization premium to the industry average in the third quarter of
2017 is attributable to:
-
- the quality of Western's drilling rig fleet;
- the ability of the Company's rig crews;
- the efforts by the Company's marketing group to reposition rigs
for existing and new customers; and
- a number of Western's customers increasing their capital
budgets for 2017, as compared to 2016 when customer spending was
limited.
These factors, combined with
improved commodity prices, resulted in higher demand for the
Company's drilling rigs. Operating Revenue per Billable Day
in the third quarter of 2017 improved by 10% as compared to the
same period in the prior year, as market conditions continued to
improve;
-
- In the United States, four of
the Company's five drilling rigs operated during the quarter, two
of which were working on long term contracts, resulting in Drilling
Rig Utilization of 59% in the third quarter of 2017, as compared to
32% in the same period of the prior year. Further, increased
activity has led to improved pricing, as Operating Revenue per
Billable Day in the United States
improved by 4% in the third quarter of 2017 as compared to the
third quarter of 2016; and
- Well servicing utilization of 27% in the third quarter of 2017
compared to 24% in the same period of the prior year. Improved
market conditions resulted in a 4% increase in hourly rates during
the third quarter of 2017, as compared to the same period in the
prior year. Improved utilization and pricing, led to a $1.6 million (or 19%) increase in well servicing
Operating Revenue in the period.
- Third quarter Adjusted EBITDA improved by $6.0 million to $6.9 million in 2017 as compared
to $0.9 million in the third quarter
of 2016. The year over year change in Adjusted EBITDA is due to
higher activity and improved pricing across all divisions in
2017.
- Administrative expenses, excluding depreciation and stock based
compensation, decreased by 2% in the third quarter of 2017 as
compared to the second quarter of 2017 due to lower employee costs.
Third quarter 2017 administrative expenses increased by
$0.6 million (or 12%) to $5.4 million, as compared to $4.8 million in the third quarter of 2016 mainly
due to higher employee related costs, coupled with one time
professional fees incurred in the period.
- The Company incurred a net loss of $11.5
million in the third quarter of 2017 ($0.16 per basic common share) as compared to a
net loss of $17.0 million in the same
period in 2016 ($0.23 per basic
common share). The change can be attributed to the following:
-
- A $6.0 million increase in
Adjusted EBITDA due to higher utilization and pricing in both the
contract drilling and production services segments;
- A $0.7 million decrease in stock
based compensation expense due to a greater portion of the
Company's outstanding stock options and restricted share units
being fully vested in the quarter; and
- A $0.6 million decrease in
depreciation expense due to lower capital spending and certain
equipment being fully depreciated over the last four quarters.
Offsetting the above mentioned
items is a $1.9 million decrease in
income tax recovery due to improved earnings before taxes.
- Third quarter 2017 capital expenditures of $6.3 million included $4.0
million of expansion capital and $2.3
million of maintenance capital. In total, capital spending
in the third quarter of 2017 increased by $5.6 million from the $0.7
million incurred in the third quarter of 2016. The Company
incurred expansion capital mainly related to drilling rig upgrades
in the third quarter of 2017, as well as necessary maintenance
capital related to the higher activity in the period.
- Subsequent to September 30, 2017,
on October 17, 2017 the Company
closed the following financing transactions:
-
- A lending agreement with Alberta Investment Management
Corporation ("AIMCo") providing for a $215.0
million second lien secured term loan facility (the "Second
Lien Facility"). The Second Lien Facility is available in a single
draw which will be used to repay a portion of the Company's
outstanding 7⅞% senior unsecured notes (the "Senior Notes").
Interest will be payable semi-annually, at a rate of 7.25% per
annum, on January 1 and July 1 each year. Amortization payments equal to
1% of the principal amount will be payable annually in quarterly
installments beginning on July 1,
2018, with the balance due on maturity, five years from the
draw date. In conjunction with the Second Lien Facility, Western
has issued to AIMCo approximately 7.1 million warrants to purchase
common shares of Western, at an exercise price of $1.77 per common share, which have a three year
life and expire on October 17,
2020;
- A private placement with AIMCo (the "Private Placement") of 9.1
million common shares of Western at a price of $1.25 per common share, for aggregate gross
proceeds of $11.4 million;
- A bought deal offering of common shares of Western with a
syndicate of underwriters (the "Bought Deal") where the
underwriters purchased 9.1 million common shares of Western at a
price of $1.25 per common share, for
aggregate gross proceeds of $11.4
million; and
- Completed a number of amendments to its Credit Facilities,
including the following:
-
- Extended the maturity of its syndicated revolving credit
facility (the "Revolving Facility") and its committed operating
facility (the "Operating Facility" and together the "Credit
Facilities") to December 17,
2020;
- Increased the limit of the Revolving Facility from $50.0 million to $70.0
million, while the $10.0
million Operating Facility limit remains unchanged;
- The interest coverage and current ratio covenants have been
permanently removed;
- A debt service coverage ratio has been added, which is
calculated based on EBITDA, as defined in the Credit Facilities
agreement, divided by the sum of interest expense and scheduled
long term debt principal repayments. This covenant will only be
tested when the outstanding principal under the Credit Facilities
exceeds $40.0 million or net book
value of property and equipment is less than $500.0 million. If applicable, the debt service
coverage ratio must meet or exceed 1.0 as at and prior to
March 31, 2018, 1.25 as at
June 30, 2018, 1.5 as at September 30, 2018 and December 31, 2018, and 2.0 thereafter; and
- The Revolving Facility will continue to include an accordion
feature, whereby an incremental $50.0
million of borrowing would be available, subject to the
approval of the lenders.
Western expects that the net
proceeds of the Second Lien Facility, Private Placement and the
Bought Deal, along with cash on hand and funds available under the
Credit Facilities will be used to repay the Company's Senior Notes
in the first quarter of 2018 when the Senior Notes will be
redeemable at par.
Year to Date 2017 Operating Results:
- Operating Revenue for the nine month period ended September 30, 2017 benefited from improved
commodity prices and higher customer spending which resulted in a
corresponding increase in demand for Western's services. For the
nine months ended September 30, 2017,
Operating Revenue increased by $84.4
million (or 112%) to $159.7
million as compared to $75.3
million for the nine months ended September 30, 2016. In the contract drilling
segment, Operating Revenue totalled $120.8
million for the nine months ended September 30, 2017, an increase of $70.9 million (or 142%), as compared to
$49.9 million in the same period of
the prior year, and included $6.4
million in shortfall commitment revenue in 2017, as compared
to $1.8 million in 2016; while in the
production services segment, Operating Revenue totalled
$39.1 million, an increase of
$13.7 million (or 54%) as compared to
$25.4 million in the same period of
the prior year. Higher utilization for the nine months ended
September 30, 2017, as compared to
the same period of the prior year, offset by lower pricing in the
contract drilling segment, impacted Operating Revenue in the
contract drilling and production services segments as described
below:
-
- Drilling Rig Utilization in Canada of 36% for the nine month period ended
September 30, 2017, compared to 14%
for the nine month period ended September
30, 2016, reflecting a 2,200 bps increase. Drilling Rig
Utilization of 36% in 2017 represents a 700 bps premium to the
CAODC industry average, whereas in the nine months ended
September 30, 2016, Drilling Rig
Utilization of 14% represented a 100 bps discount to the CAODC
industry average. The increase in the Company's utilization premium
in 2017 is attributable to:
-
- the quality of Western's drilling rig fleet;
- the ability of the Company's rig crews;
- the efforts by the Company's marketing group to reposition rigs
for existing and new customers; and
- a number of Western's customers increasing their capital
budgets for 2017, as compared to 2016 when customer spending was
limited
These factors, combined with improved commodity prices, resulted in
higher demand for the Company's drilling rigs. Additionally,
Western continued to increase its market share in 2017. Western's
51 drilling rigs in Canada
represent approximately 8% of the rigs registered with the CAODC,
however Western's total operating days in 2017, represented 10% of
the total industry Operating Days reported by the CAODC. Operating
Revenue per Billable Day in the current period, was consistent with
the same period in the prior year, decreasing by 1% as compared to
the same period in the prior year.
- In the United States, four of
the Company's five drilling rigs operated during the period, two of
which were working on long term contracts, resulting in Drilling
Rig Utilization of 48% for the nine months ended September 30, 2017, as compared to 22% in the
same period of the prior year. Operating Revenue per Billable Day
in the United States decreased by
12% for the nine months ended September 30,
2017 due to changes in the mix of rigs working on spot rates
versus long term contracts, as compared to the same period of the
prior year when the Company had one rig working on a long term
legacy contract; and
- Well servicing utilization of 26% for the nine months ended
September 30, 2017 compared to 17% in
the same period of the prior year. Continued improvements in
commodity prices helped improve activity year over year.
Additionally, well servicing hourly rates increased by 2% for the
nine months ended September 30, 2017,
as compared to the nine months ended September 30, 2016. Improved utilization and
pricing led to an $11.2 million (or
56%) increase in well servicing Operating Revenue in the
period.
- Adjusted EBITDA for the nine months ended September 30, 2017 increased by $23.3 million to $25.6
million in 2017 as compared to $2.3
million for the nine months ended September 30, 2016. The year over year increase
in Adjusted EBITDA is due to higher activity across all divisions,
a $4.6 million increase in shortfall
commitment revenue in 2017, and the Company's ability to safely and
efficiently reactivate equipment and crews without incurring
significant costs, including rigs that had been idle for an
extended period of time. These factors were aided by improved
pricing in the production services segment, which was partially
offset by lower pricing in the contract drilling segment.
- Administrative expenses, excluding depreciation and stock based
compensation, for the nine month period ended September 30, 2017 increased by $1.8 million (or 12%) to $16.8 million as compared to $15.0 million in the same period of the prior
year. The increase in administrative expenses is mainly due to
higher employee related costs, coupled with one time professional
fees incurred in the period.
- The Company incurred a net loss of $32.5
million for the nine months ended September 30, 2017 ($0.44 per basic common share) as compared to a
net loss of $47.5 million for the
same period in 2016 ($0.64 per basic
common share). The decrease in net loss can be attributed to the
following:
-
- A $23.3 million increase in
Adjusted EBITDA due to higher utilization in both the contract
drilling and production services segments, and increased shortfall
commitment revenue;
- A prior period loss on asset decommissioning of $5.2 million in the contract drilling
segment;
- A $1.7 million decrease in stock
based compensation expense, due to a greater portion of the
Company's outstanding stock options and restricted share units
being fully vested in the period; and
- A $0.7 million decrease in
finance costs mainly due to the Company reducing its available
Credit Facilities in 2016 from $195.0
million to $60.0 million, resulting in lower standby
fees.
Offsetting the above mentioned
items are the following:
-
- An increase of $7.4 million in
depreciation expense due to the Company changing from unit of
production to straight line depreciation for drilling and well
servicing rigs effective April 1,
2016;
- A $3.5 million increase in other
items, as the first quarter of 2016 included foreign exchange gains
of $2.5 million, while the first
quarter of 2017 included $1.6 million
in transaction costs related to the unsuccessful acquisition of
Savanna Energy Services Corp. ("Savanna"); and
- A $5.1 million decrease in income
tax recovery due to improved earnings before taxes.
- Year to date capital expenditures of $12.2 million included $6.4 million of expansion capital and
$5.8 million of maintenance capital.
In total, capital spending for the nine months ended September 30, 2017 increased by $10.2 million from the $2.0 million incurred in the same period of 2016.
The Company incurred expansion capital mainly related to drilling
rig upgrades in the nine months ended September 30, 2017, which have contributed to the
increase in cash flow from operating activities year to date, as
well as necessary maintenance capital related to the higher
activity in the period.
Selected Financial
Information
|
(stated in
thousands, except share and per share amounts)
|
|
Three months ended
Sept 30
|
Nine months ended
Sept 30
|
Financial
Highlights
|
2017
|
2016
|
Change
|
2017
|
2016
|
Change
|
Revenue
|
54,131
|
32,485
|
67%
|
171,660
|
79,312
|
116%
|
Operating
Revenue(1)
|
51,111
|
30,665
|
67%
|
159,733
|
75,258
|
112%
|
Gross
Margin(1)
|
12,299
|
5,685
|
116%
|
42,424
|
17,255
|
146%
|
Gross Margin as a
percentage of Operating Revenue
|
24%
|
19%
|
26%
|
27%
|
23%
|
17%
|
Adjusted
EBITDA(1)
|
6,882
|
896
|
668%
|
25,628
|
2,269
|
1,029%
|
Adjusted EBITDA as a
percentage of Operating Revenue
|
13%
|
3%
|
333%
|
16%
|
3%
|
433%
|
Cash flow from
operating activities
|
1,609
|
909
|
77%
|
25,441
|
17,958
|
42%
|
Capital
expenditures
|
6,349
|
651
|
875%
|
12,220
|
1,995
|
513%
|
Net loss
|
(11,478)
|
(16,973)
|
(32%)
|
(32,471)
|
(47,464)
|
(32%)
|
|
-basic net loss per
share
|
(0.16)
|
(0.23)
|
(30%)
|
(0.44)
|
(0.64)
|
(31%)
|
|
-diluted net loss per
share
|
(0.16)
|
(0.23)
|
(30%)
|
(0.44)
|
(0.64)
|
(31%)
|
Weighted average
number of shares
|
|
|
|
|
|
|
|
-basic
|
73,877,203
|
73,722,144
|
-
|
73,823,970
|
73,672,389
|
-
|
|
-diluted
|
73,877,203
|
73,722,144
|
-
|
73,823,970
|
73,672,389
|
-
|
Outstanding common
shares as at period end
|
73,974,594
|
73,795,266
|
-
|
73,974,594
|
73,795,266
|
-
|
(1) See "Non-IFRS
measures" included in this press release.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
Sept 30
|
Nine months ended
Sept 30
|
Operating
Highlights(1)
|
2017
|
2016
|
Change
|
2017
|
2016
|
Change
|
Contract
Drilling
|
|
|
|
|
|
|
Canadian
Operations:
|
|
|
|
|
|
|
Contract drilling rig
fleet:
|
|
|
|
|
|
|
|
-Average active rig
count
|
20.2
|
11.4
|
77%
|
20.3
|
8.0
|
154%
|
|
-End of
period
|
51
|
51
|
-
|
51
|
51
|
-
|
Operating Revenue per
Billable Day
|
16,825
|
15,256
|
10%
|
17,109(3)
|
17,206(4)
|
(1%)
|
Operating Revenue per
Operating Day
|
18,604
|
17,017
|
9%
|
18,862(3)
|
19,224(4)
|
(2%)
|
Operating
Days
|
1,681
|
940
|
79%
|
5,027
|
1,959
|
157%
|
Drilling rig
utilization - Billable Days
|
40%
|
22%
|
82%
|
40%
|
15%
|
167%
|
Drilling rig
utilization - Operating Days
|
36%
|
20%
|
80%
|
36%
|
14%
|
157%
|
CAODC industry
average utilization(2)
|
29%
|
17%
|
71%
|
29%
|
15%
|
93%
|
|
|
|
|
|
|
|
United States
Operations:
|
|
|
|
|
|
|
Contract drilling rig
fleet:
|
|
|
|
|
|
|
|
-Average active rig
count
|
3.3
|
1.8
|
83%
|
2.8
|
1.3
|
115%
|
|
-End of
period
|
5
|
5
|
-
|
5
|
5
|
-
|
Operating Revenue per
Billable Day (US$)
|
19,801
|
18,967
|
4%
|
19,763
|
22,515
|
(12%)
|
Operating Revenue per
Operating Day (US$)
|
21,832
|
22,246
|
(2%)
|
22,850
|
25,923
|
(12%)
|
Operating
Days
|
272
|
145
|
88%
|
656
|
306
|
114%
|
Drilling rig
utilization - Billable Days
|
65%
|
37%
|
76%
|
56%
|
26%
|
115%
|
Drilling rig
utilization - Operating Days
|
59%
|
32%
|
84%
|
48%
|
22%
|
118%
|
|
|
|
|
|
|
|
Production
Services
|
|
|
|
|
|
|
Well servicing rig
fleet:
|
|
|
|
|
|
|
|
-Average active rig
count
|
17.7
|
15.6
|
13%
|
17.3
|
11.4
|
52%
|
|
-End of
period
|
66
|
66
|
-
|
66
|
66
|
-
|
Service rig Operating
Revenue per Service Hour
|
629
|
603
|
4%
|
661
|
646
|
2%
|
Service
Hours
|
16,328
|
14,335
|
14%
|
47,296
|
31,123
|
52%
|
Service rig
utilization
|
27%
|
24%
|
13%
|
26%
|
17%
|
53%
|
(1)
|
See "Non-IFRS
measures" included in this press release.
|
(2)
|
Source: The
Canadian Association of Oilwell Drilling Contractors
("CAODC"). The CAODC industry average is based on Operating
Days divided by total available days.
|
(3)
|
Excludes shortfall
commitment revenue from take or pay contracts of $6.4 million for
the nine months ended September 30, 2017.
|
(4)
|
Excludes shortfall
commitment revenue from take or pay contracts of $1.8 million for
the nine months ended September 30, 2016.
|
|
|
|
|
|
Financial Position
at (stated in thousands)
|
|
September 30,
2017
|
December 31,
2016
|
September 30,
2016
|
Working
capital
|
|
46,184
|
51,118
|
55,259
|
Property and
equipment
|
|
663,542
|
708,567
|
720,554
|
Total
assets
|
|
737,385
|
793,525
|
794,170
|
Long term
debt
|
|
264,958
|
264,070
|
264,118
|
Western is an oilfield service company focused on three core
business lines: contract drilling, well servicing and oilfield
rental equipment services. Western provides contract drilling
services through its division, Horizon Drilling ("Horizon") in
Canada, and its wholly owned
subsidiary, Stoneham Drilling Corporation ("Stoneham") in
the United States ("US").
Western provides well servicing and oilfield rental equipment
services in Canada through its
wholly owned subsidiary Western Production Services Corp. ("Western
Production Services"). Western Production Services' division,
Eagle Well Servicing ("Eagle") provides well servicing operations,
while its division, Aero Rental Services ("Aero") provides oilfield
rental equipment services. Financial and operating results
for Horizon and Stoneham are
included in Western's contract drilling segment, while financial
and operating results for Eagle and Aero are included in Western's
production services segment.
Western has a drilling rig fleet of 56 rigs specifically suited
for drilling horizontal wells of increased complexity.
Western is currently the fifth largest drilling contractor in
Canada, based on the CAODC
registered rigs, with a fleet of 51 rigs operating through
Horizon. Of the Canadian fleet, 24 are classified as Cardium
class rigs, 19 as Montney class
rigs and eight as Duvernay class
rigs. As compared to the Cardium class rigs, the Montney class rigs have a larger hookload,
while the Duvernay class rigs have
the largest hookload allowing the rig to support more drill pipe
downhole. Additionally, Western has five Duvernay class triple drilling rigs deployed
in the United States operating
through Stoneham. Western is also the sixth largest well
servicing company in Canada with a
fleet of 66 rigs operating through Eagle. Western's oilfield
rental equipment division, which operates through Aero, provides
oilfield rental equipment for hydraulic fracturing services, well
completions and production work, coil tubing and drilling
services.
Crude oil and natural gas prices impact the cash flow of
Western's customers, which in turn impacts the demand for Western's
services. West Texas Intermediate ("WTI") on average was
relatively constant in the third quarter of 2017 as compared to the
second quarter of 2017, however was 7% higher compared to the same
period in the prior year. For Western's Canadian customers,
the impact of foreign exchange rates when translating WTI into the
Canadian equivalent, resulted in only a 3% increase for the three
months ended September 30, 2017, as
compared to the same period in the prior year. Additionally,
in the third quarter of 2017, Western Canadian Select ("WCS") on
average declined by 1% as compared to the second quarter of 2017,
however improved by 18% as compared to the same period of the prior
year. For the nine months ended September 30, 2017, WTI was 19% higher than the
same period of the prior year. Similarly, WCS also improved
for the nine months ended September 30,
2017, increasing by 34% as compared to the nine months ended
September 30, 2016.
Canadian natural gas prices, such as AECO, declined quarter over
quarter, decreasing on average by 41% from the second quarter of
2017 to the third quarter of 2017. Further, AECO decreased in
the third quarter of 2017 as compared to the same period of the
prior year, decreasing by 31%, however for the nine month period
ending September 30, 2017 AECO
improved by 29% as compared to the same period in the prior
year. 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, 2017 and 2016.
|
|
|
|
|
|
|
Three months ended
Sept 30
|
|
Nine months ended
Sept 30
|
|
|
2017
|
2016
|
Change
|
|
2017
|
2016
|
Change
|
Average crude oil
and natural gas prices(1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude
Oil
|
|
|
|
|
|
|
|
|
West Texas
Intermediate (US$/bbl)
|
|
48.16
|
44.88
|
7%
|
|
49.32
|
41.44
|
19%
|
Western Canadian
Select (CDN$/bbl)
|
|
47.27
|
40.00
|
18%
|
|
49.62
|
37.09
|
34%
|
|
|
|
|
|
|
|
|
|
Natural
Gas
|
|
|
|
|
|
|
|
|
30 day Spot AECO
(CDN$/mcf)
|
|
1.65
|
2.38
|
(31%)
|
|
2.40
|
1.86
|
29%
|
|
|
|
|
|
|
|
|
|
Average foreign
exchange rates(2)
|
|
|
|
|
|
|
|
|
US dollar to Canadian
dollar
|
|
1.25
|
1.30
|
(4%)
|
|
1.31
|
1.32
|
(1%)
|
(1)
|
See "Abbreviations"
included in this press release.
|
(2)
|
Source:
Bloomberg
|
Improved commodity prices in 2017 has led to a corresponding
increase in the demand for oilfield services in both Canada and the United States. The CAODC
reported that for drilling in Canada, the total number of Operating Days in
the Western Canadian Sedimentary Basin ("WCSB") increased
approximately 41% and 72% for the three and nine months ended
September 30, 2017 respectively, as
compared to the same periods in the prior year. Similarly, as
reported by Baker Hughes, a GE Company, the number of active
drilling rigs in the United States
increased approximately 97% and 77% for the three and nine months
ended September 30, 2017
respectively, as compared to the same periods in the prior
year.
Outlook
Currently, 22 of Western's drilling rigs are operating.
Five of Western's 56 drilling rigs (or 9%) are under long term take
or pay contracts, with two expected to expire in 2018, two expected
to expire in 2019 and one expected to expire in 2020. These
contracts each typically generate between 250 and 350 Billable Days
per year.
Western's capital budget for 2017 remains unchanged and totals
approximately $20 million comprised
of $8 million in expansion capital
and $12 million in maintenance
capital. The majority of the capital budget relates to
expansion capital in the contract drilling segment related to
drilling rig upgrades that offer compelling economics.
Western believes the revised 2017 capital budget provides a prudent
use of cash resources and will allow it to maintain its premier
drilling and well servicing rig fleets, while remaining responsive
to customer requirements. Western will continue to manage its
operations in a disciplined manner and make any required
adjustments to its capital program as customer demand
changes. Approximately $2
million from the revised 2017 capital budget is expected to
be carried forward into 2018.
Since hitting 10 year lows in the first quarter of 2016,
commodity prices, while remaining well below previous highs, have
improved. As such, North American drilling rig counts have
begun to recover and the Company is expecting increased year over
year activity levels throughout the remainder of 2017.
However, improved pricing for the Company's services has lagged the
recovery in activity and is expected to occur gradually as rates
are typically increased for rigs and drilling programs on an
individual basis rather than universally. Improving gross
margin is a priority for the Company and, as has been demonstrated
over the last two quarters, Western is working to implement higher
rates with each rig that is awarded work. Prices for
Western's services below historical levels will continue to impact
Adjusted EBITDA and cash flow from operating activities in the near
term. However, Western's variable cost structure and a
prudent capital budget will aid in preserving balance sheet
strength. In addition to $39.6
million in cash and cash equivalents at September 30, 2017, Western currently has
$80.0 million of available credit
under its undrawn amended Credit Facilities, which do not mature
until December 17, 2020.
Additionally, Western plans to repay the Senior Notes in the first
quarter of 2018 with proceeds from the Second Lien Facility,
Private Placement and the Bought Deal completed subsequent to
September 30, 2017, along with cash
on hand and funds available under the Credit Facilities.
Completing these financing transactions will lower Western's total
debt and leverage metrics, decrease Western's effective interest
rates and extend the maturity on all of Western's long term
debt. Additionally, Western will save approximately
$5.3 million annually in cash
interest expense, due to the decreased total debt level and lower
interest rate on the Second Lien Facility, as compared to the
existing Senior Notes.
Oilfield service activity in Canada will be impacted by the development of
resource plays in Alberta and
northeast British Columbia
including those related to increased crude oil transportation
capacity through pipeline development, increased environmental
regulations including the implementation of a carbon tax in
Alberta, and decreased foreign
investment into Canada. Currently, the largest challenges
facing the oilfield service industry are continued customer
spending constraints as a result of lower commodity prices and the
increasing challenge of staffing field crews, particularly in the
well servicing division. Western's view is that its modern
drilling and well servicing rig fleets, reputation, and disciplined
cash management provide a competitive advantage which will enable
the Company to manage through the current slowdown in oilfield
service activity.
2017 Third Quarter Financial and Operating Results Conference
Call and Webcast
Western has scheduled a conference call and webcast to begin
promptly at 9:00 a.m. MDT
(11:00 a.m. EDT) on Thursday, October 26, 2017.
The conference call dial-in number is 1-888-231-8191.
A live webcast of the conference call will be accessible on
Western's website at www.wesc.ca by selecting "Investors",
then "Webcasts". Shortly after the live webcast, an
archived version will be available for approximately 14 days.
An archived recording of the conference call will also be
available approximately two hours after the completion of the call
until November 9, 2017 by dialing
1-855-859-2056, passcode 95867128.
Non-IFRS Measures
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 condensed 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. These Non-IFRS measures
are identified and defined as follows:
Operating Revenue
Management believes that in addition to revenue, Operating
Revenue is a useful supplemental measure as it provides an
indication of the revenue generated by Western's principal
operating activities, excluding flow through third party charges
such as rig fuel, which at the customer's request may be paid for
initially by Western, then recharged in its entirety to Western's
customers.
Gross Margin
Management believes that in addition to net income, Gross Margin
is a useful supplemental measure as it provides an indication of
the results generated by Western's principal operating activities
prior to considering administrative expenses, depreciation and
amortization, stock based compensation, how those activities are
financed, the impact of foreign exchange, how the results are
taxed, how funds are invested, and how non-cash items and one-time
gains and losses affect results.
The following table provides a reconciliation of revenue under
IFRS, as disclosed in the condensed consolidated statements of
operations and comprehensive income, to Operating Revenue and Gross
Margin:
|
|
|
|
|
|
|
Three months ended
Sept 30
|
|
Nine months ended
Sept 30
|
(stated in
thousands)
|
2017
|
2016
|
|
2017
|
2016
|
Operating
Revenue
|
|
|
|
|
|
|
Drilling
|
38,711
|
20,210
|
|
120,754
|
49,922
|
|
Production
services
|
12,411
|
10,460
|
|
39,094
|
25,354
|
|
Less: inter-company
eliminations
|
(11)
|
(5)
|
|
(115)
|
(18)
|
|
51,111
|
30,665
|
|
159,733
|
75,258
|
Third party
charges
|
3,020
|
1,820
|
|
11,927
|
4,054
|
Revenue
|
54,131
|
32,485
|
|
171,660
|
79,312
|
Less: operating
expenses
|
(58,049)
|
(43,601)
|
|
(178,419)
|
(103,904)
|
Add:
|
|
|
|
|
|
|
Depreciation –
operating
|
16,196
|
16,712
|
|
48,989
|
41,352
|
|
Stock based
compensation – operating
|
21
|
89
|
|
194
|
495
|
Gross
Margin
|
12,299
|
5,685
|
|
42,424
|
17,255
|
Adjusted EBITDA
Management believes that in addition to net income, 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 provides
an indication of the results generated by the Company's principal
operating segments similar to Gross Margin but also factors in the
cash administrative expenses incurred in the period.
Operating Earnings
Management believes that in addition to net income, Operating
Earnings is a useful supplemental measure as it provides an
indication of the results generated by the Company's principal
operating segments similar to Adjusted EBITDA but also factors in
the depreciation expense incurred in the period.
The following table provides a reconciliation of net loss under
IFRS, as disclosed in the condensed consolidated statements of
operations and comprehensive income, to earnings before interest
and finance costs, taxes, depreciation and amortization ("EBITDA"),
Adjusted EBITDA and Operating Loss:
|
|
|
|
|
Three months ended
Sept 30
|
|
Nine months ended
Sept 30
|
(stated in
thousands)
|
2017
|
2016
|
|
2017
|
2016
|
Net
loss
|
(11,478)
|
(16,973)
|
|
(32,471)
|
(47,464)
|
Add:
|
|
|
|
|
|
|
Finance
costs
|
5,521
|
5,708
|
|
16,352
|
17,044
|
|
Income tax
recovery
|
(4,071)
|
(6,043)
|
|
(11,713)
|
(16,772)
|
|
Depreciation –
operating
|
16,196
|
16,712
|
|
48,989
|
41,352
|
|
Depreciation –
administrative
|
300
|
378
|
|
929
|
1,204
|
EBITDA
|
6,468
|
(218)
|
|
22,086
|
(4,636)
|
Add:
|
|
|
|
|
|
|
Stock based
compensation – operating
|
21
|
89
|
|
194
|
495
|
|
Stock based
compensation – administrative
|
158
|
759
|
|
1,292
|
2,651
|
|
Loss on asset
decommissioning
|
-
|
-
|
|
-
|
5,225
|
|
Other
items
|
235
|
266
|
|
2,056
|
(1,466)
|
Adjusted
EBITDA
|
6,882
|
896
|
|
25,628
|
2,269
|
Subtract:
|
|
|
|
|
|
|
Depreciation –
operating
|
(16,196)
|
(16,712)
|
|
(48,989)
|
(41,352)
|
|
Depreciation –
administrative
|
(300)
|
(378)
|
|
(929)
|
(1,204)
|
Operating
Loss
|
(9,614)
|
(16,194)
|
|
(24,290)
|
(40,287)
|
Net Debt
The following table provides a reconciliation of long term debt
under IFRS, as disclosed in the condensed consolidated balance
sheets to Net Debt:
|
|
|
|
|
|
(stated in
thousands)
|
|
|
|
September 30,
2017
|
December 31,
2016
|
Long term
debt
|
|
|
|
264,958
|
264,070
|
Current portion of
long term debt
|
|
|
|
500
|
684
|
Less: cash and cash
equivalents
|
|
|
|
(39,576)
|
(44,597)
|
Net
Debt
|
|
|
|
225,882
|
220,157
|
Defined Terms:
Average active rig count (contract drilling): Calculated
as drilling rig utilization – Billable Days 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.
Billable Days: Defined as Operating Days plus rig
mobilization days.
Drilling rig utilization – Operating Days (or
"Drilling Rig Utilization"): Calculated based on
Operating Days divided by total available days.
Drilling rig utilization – Billable Days:
Calculated based on Billable 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 in 2017 (2016: 366
days).
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 Oilwell Drilling Contractors
("CAODC");
- DecaNewton ("daN");
- International Financial Reporting Standards ("IFRS");
- Pounds ("lbs");
- Thousand cubic feet ("mcf");
- West Texas Intermediate ("WTI"); and
- Western Canadian Sedimentary Basin ("WCSB").
Forward-Looking Statements and Information
This press release contains certain statements or disclosures
relating to Western that are based on the expectations of Western
as well as assumptions made by and information currently available
to Western which may constitute forward-looking information under
applicable securities laws. All such statements and
disclosures, other than those of historical fact, which address
activities, events, outcomes, results or developments that Western
anticipates or expects may, or will occur in the future (in whole
or part) should be considered forward-looking information. In
some cases forward-looking information can be identified by terms
such as "forecast", "future", "may", "will", "expect",
"anticipate", "believe", "potential", "enable", "plan", "continue",
or other comparable terminology.
In particular, forward-looking information in this press release
includes, but is not limited to, statements relating to commodity
pricing; the future demand for and utilization of the Company's
services and equipment; the pricing for the Company's services and
equipment; the terms of existing and future drilling contracts in
Canada and the US and the revenue
resulting therefrom (including the number of Operating Days
typically generated from the Company's contracts); the Company's
expansion and maintenance capital plans for 2017; the Company's
liquidity needs including the ability of current capital resources
to cover Western's financial obligations and the 2017 capital
budget; the expected use of proceeds of the Second Lien Facility,
Private Placement and the Bought Deal; the Company's expected
sources of funding to support such capital plans and the Company's
ability to adjust capital spending for the remainder of 2017 if
market conditions, including customer demand changes; the expected
benefits from cost control measures; the use and availability of
the Company's Credit Facilities; pricing for Western's services and
impact on Adjusted EBITDA; the Company's ability to maintain
certain covenants under its Credit Facilities; the future
declaration of dividends; expectations as to the increase in crude
oil transportation capacity through pipeline development; the
potential impact of changes to environmental laws and regulations
and the implementation of a carbon tax in Alberta; the expectation of continued foreign
investment into the Canadian crude oil and natural gas industry;
expectations relating to producer spending, and the Company's
ability to find and maintain enough field crew members and the
Company's change to its depreciation assumptions.
The material assumptions in making the forward-looking
statements in this press release include, but are not limited to,
assumptions relating to, demand levels and pricing for oilfield
services; fluctuations in the price and demand for crude oil and
natural gas; the continued low levels of and pressures on commodity
pricing; the continued business relationship between the Company
and its significant customers; general economic and financial
market conditions; crude oil transport and pipeline approval and
development; the Company's ability to finance its operations; 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; the ability of the Company's various business segments to
access equipment (including spare parts and new technologies);
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; and other unforeseen conditions which could impact the
use of services supplied by Western including Western's ability to
respond to such conditions.
Although Western believes that the expectations and assumptions
on which such forward-looking statements and information are based
on are reasonable, undue reliance should not be placed on the
forward-looking statements and information as Western cannot give
any assurance that they will prove to be correct. Since
forward-looking statements and information address future events
and conditions, by their very nature they involve 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 risk that
the demand for oilfield services will not continue to improve for
the remainder of 2017 and that commodity prices will remain low,
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 included in
Western's annual information form which may be accessed through the
SEDAR website at www.sedar.com. The forward-looking
statements and information contained in this press 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.
SOURCE Western Energy Services Corp.