(Canadian dollars except as indicated)
This news release contains “forward-looking
information and statements” within the meaning of applicable
securities laws. For a full disclosure of the forward-looking
information and statements and the risks to which they are subject,
see the “Cautionary Statement Regarding Forward-Looking Information
and Statements” later in this news release. This news release
contains references to Adjusted EBITDA, Covenant EBITDA, Operating
Earnings (Loss), Funds Provided by (Used in) Operations and Working
Capital. These terms do not have standardized meanings prescribed
under International Financial Reporting Standards (IFRS) and may
not be comparable to similar measures used by other companies, see
“Non-GAAP Measures” later in this news release.
Precision Drilling announces 2018 second quarter
financial results:
- Second quarter revenue of $331
million was an increase of 14% over the prior year comparative
quarter.
- Second quarter net loss of $47
million ($0.16 per share) compares to a net loss of $36 million
($0.12 per share) in the second quarter of 2017.
- Second quarter earnings before
income taxes, loss on repurchase and redemption of unsecured senior
notes, finance charges, foreign exchange and depreciation and
amortization (adjusted EBITDA see “NON-GAAP MEASURES”) of $62
million was 10% higher than the second quarter of 2017.
- Funds provided by operations (see
“NON-GAAP MEASURES”) in the second quarter of $50 million versus
funds used in operations of $15 million in the prior year
comparative quarter.
- Second quarter ending cash balance was $95 million.
- Second quarter capital expenditures were $37 million.
Precision’s President and CEO Kevin Neveu
stated: “Precision’s strong second quarter results were driven by
continued growth in North American activity, having achieved our
highest U.S. market share to date. Additionally, we captured higher
day rates and margins in both markets. We attribute our market
share gains and sequential rate increases to customers’ intense
focus on capital efficiency which leads them to contract the best
performing and most efficient drilling rigs and crews, lowering
total well-pad cost.”
“During the quarter, we activated eight rigs in
the U.S. and currently have 78 rigs running with visibility for
four to six additional activations in the coming weeks. We believe
customer focus on efficiency and cost may intensify, presenting
additional growth opportunities for Precision. With established
positions in all major U.S. shale plays and proven performance of
our Super Series rigs we are in a strong position to take advantage
of increased activity and customer capital reallocation. A similar
trend is evident in Canada where despite flat year-over-year
customer spending we already have 60 rigs active, surpassing last
year’s third quarter peak. We expect Precision’s year-over-year
growth in activity to continue through the third
quarter.”
“We continue to demonstrate positive momentum
with regard to our key strategic priorities for the year. First and
foremost, we have reached the low end of our stated 2018 debt
reduction range, reducing debt by $75 million year-to-date. Next,
our financial performance has improved year-over-year through
increased activity, pricing and margins in North America with
particular strength in the U.S. Lastly, as it relates to
technology, demand continues to improve for PAC (Process Automation
Control), DGS (Directional Guidance System), and Drilling
Performance Applications (Apps) with full commercialization
expected by year end. We are purchasing ten additional PAC systems
that will be deployed on our rigs in the second half of the year
bringing us to 31 Super Series rigs in the field with PAC.”
“In the U.S., our High Performance field results
are also showing up in our pricing and margins and I am pleased to
report both day rates and margins per day increased nearly US$1,200
quarter-over-quarter with no increase in daily operating costs. I
expect to see continued increases in our average rates and margins
throughout the second half of the year with continued strength in
pricing, further value capture from our technology initiatives and
continued fixed cost leverage. In Canada, Precision’s activity
levels increased 7% year-over-year outperforming the 3% increase in
industry drilling days. In addition, day rates excluding shortfall
revenue increased approximately $1,400 per day year-over-year
largely as a result of improved spot pricing. Since our last
earnings announcement Precision signed ten term contracts in the
U.S. and two term contracts in Canada, which coupled with our
activity increase and improved day rates, is a clear indication of
continued customer alignment with our High Performance, High Value
service offering.”
“Internationally, we previously announced our
newbuild rig contract in Kuwait strengthening our Middle East
footprint and increasing our Kuwait active rig count to six rigs by
the third quarter of 2019. We are adding this newbuild with no
increase in fixed costs, supported by sufficient scale in country.
In the Kingdom of Saudi Arabia, three rigs are currently active,
two of which roll off contract next month and we fully expect them
to be re-contracted. We are actively bidding our four idle rigs in
the Middle East and believe the prospects to activate these rigs
are improving.”
“Customer adoption of PAC is strengthening and
we have completed several analytical field case studies
demonstrating the system’s ability to consistently and repeatedly
deliver high quality wells while improving safety, performance and
efficiency of operations. Our DGS technology is also gaining
momentum having now drilled over two million feet to date utilizing
the software including over 70 wells in 2018. Additionally, we are
deploying revenue generating Apps on several rigs and currently
have 12 Apps in varying stages of commercial development showcasing
the open platform of our PAC system. Several Apps are
customer-built and supported by Precision’s PAC platform with
specific hosting agreements in place. We are pleased our technology
initiatives are beginning to impact our revenue and margins.”
“Our updated 2018 capital plan is approximately
$135 million. The $19 million increase from our previous update
includes spending for our newbuild award in Kuwait, completion of a
newbuild in the U.S., foreign exchange impact from a weaker
Canadian dollar, and a minor increase in upgrade capital spending.
With $95 million of cash on the balance sheet coupled with cash
flow in the second half of the year I fully expect to fund growth
and upgrade opportunities while reserving capacity to retire more
of our debt,” concluded Mr. Neveu.
SELECT FINANCIAL AND OPERATING
INFORMATION
Adjusted EBITDA and funds provided by (used in)
operations are Non-GAAP measures. See “NON-GAAP MEASURES.”
Financial Highlights
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars, except per share amounts) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue(1) |
|
330,716 |
|
|
|
290,860 |
|
|
|
13.7 |
|
|
|
731,722 |
|
|
|
659,533 |
|
|
|
10.9 |
|
Adjusted EBITDA(2) |
|
62,182 |
|
|
|
56,520 |
|
|
|
10.0 |
|
|
|
159,651 |
|
|
|
140,828 |
|
|
|
13.4 |
|
Net loss |
|
(47,217 |
) |
|
|
(36,130 |
) |
|
|
30.7 |
|
|
|
(65,294 |
) |
|
|
(58,744 |
) |
|
|
11.2 |
|
Cash provided by
operations |
|
129,695 |
|
|
|
2,739 |
|
|
|
4,635.1 |
|
|
|
167,884 |
|
|
|
36,509 |
|
|
|
359.8 |
|
Funds provided by (used
in) operations(2) |
|
50,225 |
|
|
|
(15,187 |
) |
|
|
(430.7 |
) |
|
|
154,251 |
|
|
|
70,472 |
|
|
|
118.9 |
|
Capital spending: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expansion |
|
15,786 |
|
|
|
4,852 |
|
|
|
225.4 |
|
|
|
16,471 |
|
|
|
8,644 |
|
|
|
90.5 |
|
Upgrade |
|
5,447 |
|
|
|
13,287 |
|
|
|
(59.0 |
) |
|
|
16,810 |
|
|
|
26,934 |
|
|
|
(37.6 |
) |
Maintenance and infrastructure |
|
13,091 |
|
|
|
2,997 |
|
|
|
336.8 |
|
|
|
23,334 |
|
|
|
5,981 |
|
|
|
290.1 |
|
Intangibles |
|
2,429 |
|
|
|
7,301 |
|
|
|
(66.7 |
) |
|
|
10,220 |
|
|
|
8,970 |
|
|
|
13.9 |
|
Proceeds on sale |
|
(2,630 |
) |
|
|
(3,563 |
) |
|
|
(26.2 |
) |
|
|
(8,680 |
) |
|
|
(5,781 |
) |
|
|
50.1 |
|
Net capital
spending |
|
34,123 |
|
|
|
24,874 |
|
|
|
37.2 |
|
|
|
58,155 |
|
|
|
44,748 |
|
|
|
30.0 |
|
Net loss per
share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
(0.16 |
) |
|
|
(0.12 |
) |
|
|
33.3 |
|
|
|
(0.22 |
) |
|
|
(0.20 |
) |
|
|
10.0 |
|
Diluted |
|
(0.16 |
) |
|
|
(0.12 |
) |
|
|
33.3 |
|
|
|
(0.22 |
) |
|
|
(0.20 |
) |
|
|
10.0 |
|
(1) Prior year comparatives have changed to
reflect a recast of certain amounts previously netted against
operating expense. See our 2017 Annual Report.(2) See
“NON-GAAP MEASURES”.
Operating Highlights
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Contract drilling rig
fleet |
|
257 |
|
|
|
256 |
|
|
|
0.4 |
|
|
|
257 |
|
|
|
256 |
|
|
|
0.4 |
|
Drilling rig
utilization days: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
2,834 |
|
|
|
2,639 |
|
|
|
7.4 |
|
|
|
9,302 |
|
|
|
9,458 |
|
|
|
(1.6 |
) |
U.S. |
|
6,588 |
|
|
|
5,331 |
|
|
|
23.6 |
|
|
|
12,383 |
|
|
|
9,521 |
|
|
|
30.1 |
|
International |
|
728 |
|
|
|
728 |
|
|
|
- |
|
|
|
1,448 |
|
|
|
1,448 |
|
|
|
- |
|
Revenue per utilization
day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada(1)(2) (Cdn$) |
|
22,072 |
|
|
|
22,177 |
|
|
|
(0.5 |
) |
|
|
22,167 |
|
|
|
21,620 |
|
|
|
2.5 |
|
U.S.(1)(3) (US$) |
|
21,795 |
|
|
|
19,826 |
|
|
|
9.9 |
|
|
|
21,237 |
|
|
|
20,147 |
|
|
|
5.4 |
|
International (US$) |
|
49,832 |
|
|
|
49,679 |
|
|
|
0.3 |
|
|
|
49,935 |
|
|
|
50,054 |
|
|
|
(0.2 |
) |
Operating cost per
utilization day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
(Cdn$) |
|
16,712 |
|
|
|
16,368 |
|
|
|
2.1 |
|
|
|
14,361 |
|
|
|
13,815 |
|
|
|
4.0 |
|
U.S.
(US$) |
|
14,026 |
|
|
|
14,248 |
|
|
|
(1.6 |
) |
|
|
14,026 |
|
|
|
14,695 |
|
|
|
(4.6 |
) |
Service rig fleet |
|
210 |
|
|
|
210 |
|
|
|
- |
|
|
|
210 |
|
|
|
210 |
|
|
|
- |
|
Service rig operating
hours |
|
31,824 |
|
|
|
33,813 |
|
|
|
(5.9 |
) |
|
|
84,525 |
|
|
|
85,870 |
|
|
|
(1.6 |
) |
Revenue
per operating hour (Cdn$) |
|
676 |
|
|
|
629 |
|
|
|
7.5 |
|
|
|
691 |
|
|
|
633 |
|
|
|
9.2 |
|
(1) Prior year comparatives have changed to
reflect a recast of certain amounts previously netted against
operating expense. See our 2017 Annual Report.(2) Includes lump sum
revenue from contract shortfall for the six months ended June 30,
2018 and prior year comparatives.(3) 2017 comparative periods
include revenue from idle but contracted rig days.
Financial Position
(Stated in thousands of Canadian dollars, except ratios) |
June
30, 2018 |
|
|
December 31, 2017 |
|
Working capital(1) |
|
196,149 |
|
|
|
232,121 |
|
Cash |
|
94,669 |
|
|
|
65,081 |
|
Long-term debt(2) |
|
1,735,842 |
|
|
|
1,730,437 |
|
Total long-term
financial liabilities |
|
1,753,580 |
|
|
|
1,754,059 |
|
Total assets |
|
3,858,221 |
|
|
|
3,892,931 |
|
Long-term
debt to long-term debt plus equity ratio |
|
0.50 |
|
|
|
0.49 |
|
(1) See “NON-GAAP MEASURES”.(2) Net of unamortized
debt issue costs.
Summary for the three months ended June 30,
2018:
- Revenue this quarter was $331
million which is 14% higher than the second quarter of 2017. The
increase in revenue is primarily the result of higher activity in
our U.S. contract drilling business. Compared with the second
quarter of 2017 our activity for the quarter, as measured by
drilling rig utilization days, respectively increased 24% and 7% in
the U.S. and Canada, respectively, and remained consistent
internationally. Revenue from our Contract Drilling Services
segment increased over the comparative prior year period by 16%
while revenue in our Completion and Production Services segment was
down 6%.
- Adjusted EBITDA (see “NON-GAAP
MEASURES”) this quarter of $62 million is an increase of $6 million
from the second quarter of 2017. Our adjusted EBITDA as a
percentage of revenue was 19% this quarter in-line with the
comparative quarter of 2017. Adjusted EBITDA this quarter was
positively impacted by higher activity and day rates in the U.S.
offset by higher share-based incentive compensation from an
increase in the Corporation’s share price versus the comparative
prior year. Total share-based incentive compensation expensed in
the quarter was $10 million compared to a recovery of $3 million in
the second quarter of 2017. See discussion on share-based incentive
compensation under “Other Items” later in this report for
additional details.
- Operating loss (see “NON-GAAP
MEASURES”) this quarter was $26 million compared with an operating
loss of $39 million in the second quarter of 2017. Operating
results this quarter were positively impacted by the increase in
activity in our U.S. contract drilling business and lower
depreciation expense.
- General and administrative expenses
this quarter were $32 million, $12 million higher than the second
quarter of 2017. The increase is due to higher share-based
incentive compensation expense tied to the price of our common
shares partially offset by a strengthening of the Canadian dollar
on our U.S. dollar denominated costs.
- Net finance charges were $32
million, a decrease of $2 million compared with the second quarter
of 2017, primarily due to a reduction in interest expense related
to debt retired in 2017, the impact of the strengthening of the
Canadian dollar on our U.S. dollar denominated costs and higher
interest income in the current quarter.
- During the quarter we redeemed
US$50 million, and repurchased and cancelled US$8 million of our
previously outstanding unsecured senior notes incurring a loss of
$1 million.
- In Canada, average revenue per
utilization day for contract drilling rigs was $22,072 in the
second quarter compared to $22,177 in the second quarter of 2017.
Overall, shortfall payments received in the prior year comparative
quarter and a greater number of rigs on long-term contracts at
legacy pricing were largely offset by higher spot market day rates
in the current quarter. During the quarter, we did not recognize
any shortfall payments in revenue compared with $4 million in the
prior year comparative period. Excluding the impact of shortfall
payment revenue, average day rates were up 7%. In the U.S., revenue
per utilization day increased in the second quarter of 2018 to
US$21,795 from US$19,826 in the prior year second quarter. The
increase in the U.S. revenue rate was the result of higher spot
market day rates and higher turnkey revenue offset by lower revenue
from idle but contracted rigs and lower mobilization revenue.
During the quarter, we had turnkey revenue of US$10 million
compared with US$5 million in the 2017 comparative period and no
revenue from idle but contracted rigs in the current quarter versus
US$2 million in the comparative period. On a sequential basis,
revenue per utilization day excluding revenue from idle but
contracted rigs increased by US$1,192 due to higher fleet average
day rates and higher turnkey revenue when compared to the first
quarter of 2018.
- Average operating costs per
utilization day for drilling rigs in Canada increased to $16,712
compared with the prior year second quarter of $16,368. The
increase in average costs was due to larger average crew formations
with increased pad rig activity in the quarter. On a sequential
basis, operating costs per day increased by $3,381 compared to the
first quarter of 2018 due to lower fixed cost absorption from lower
activity with spring break-up. In the U.S., operating costs for the
quarter on a per day basis decreased to US$14,026 in 2018 compared
with US$14,248 in 2017 due to lower lump sum move costs and fixed
costs spread over a greater number of utilization days partially
offset by increased turnkey activity. On a sequential basis,
operating costs per day remain consistent with the first quarter of
2018.
- We realized revenue from
international contract drilling of US$36 million in the second
quarter of 2018, in-line with the prior year period. Average
revenue per utilization day in our international contract drilling
business was US$49,832, consistent with the comparable prior year
quarter.
- Directional drilling services
realized revenue of $7 million in the second quarter of 2018
compared with $12 million in the prior year period.
- Funds provided by operations (see
“NON-GAAP MEASURES”) in the second quarter of 2018 were $50
million, an increase of $65 million from the prior year comparative
quarter of funds used in operations of $15 million. The increase
was primarily the result of improved operating results, a $28
million tax refund received in the quarter and the timing of
interest paid.
- Capital expenditures were $37
million in the second quarter, an increase of $8 million over the
same period in 2017. Capital spending for the quarter included
$21 million for upgrade and expansion capital, $13 million for the
maintenance of existing assets and infrastructure spending and $3
million for intangibles related to a new ERP system.
Summary for the six months ended June 30,
2018:
- Revenue for the first half of 2018
was $732 million, an increase of 11% from the 2017 period.
- Operating loss (see “NON-GAAP
MEASURES”) was $16 million, a decrease of $36 million over the same
period in 2017. Operating loss was 2% of revenue in 2018 compared
with 8% of revenue in 2017. Operating results this year were
positively impacted by increased activity in our North American
businesses.
- General and administrative costs
were $61 million, an increase of $16 million from 2017. The
increase was due to higher share-based incentive compensation that
is tied to the price of our common shares (see “Other Items” later
in this report) partially offset by the strengthening of the
Canadian dollar on our U.S. dollar denominated costs.
- Net finance charges were $64
million, a decrease of $4 million from 2017 primarily due to a
reduction in interest expense related to debt retired in 2017 and
the effect of a stronger Canadian dollar on our U.S. dollar
denominated interest expense partially offset by higher interest
income earned in the comparative period.
- Funds provided by operations (see
“NON-GAAP MEASURES”) in the first half of 2018 were $154 million,
an increase of $84 million from the prior year comparative period
of $70 million.
- Capital expenditures for the
purchase of property, plant and equipment were $67 million for the
first half of 2018, an increase of $16 million over the same period
in 2017. Capital spending for 2018 to date includes $33 million for
upgrade and expansion capital, $23 million for the maintenance of
existing assets and infrastructure and $10 million for intangibles
related to a new ERP system.
STRATEGY
Precision’s strategic priorities for 2018 are as
follows:
- Reduce debt by generating
free cash flow while continuing to fund only the
most attractive investment opportunities – we generated
$154 million in funds provided by operations (see “NON-GAAP
MEASURES”) in the first half of 2018, representing an $84 million
increase over the prior year comparative period. Utilizing cash
generated in the second quarter, we reduced debt by $75 million
through a partial redemption of our 2021 unsecured senior notes and
open market debt repurchases of our 2021 and 2024 notes. We
communicated a firm goal to reduce debt by $75 to $125 million in
2018 and have successfully achieved the low end of that range in
the first half of this year. In addition, we ended the second
quarter with $95 million of cash on the balance sheet.
- Reinforce Precision’s High
Performance competitive advantage by deploying Process Automation
Controls (PAC), Directional Guidance Systems (DGS) and Drilling
Performance Apps (Apps) on a wide scale basis – year to
date in 2018 we have drilled over 70 wells using our DGS compared
to 58 wells in all of 2017. In addition, approximately 60% of these
jobs used a reduced crew compared to only 30% in 2017. We have 21
rigs currently running in the field with PAC and have drilled
approximately 230 wells with this technology in 2018 compared to
154 in all of 2017. Earlier this year we also equipped our
training rigs in Nisku and Houston with PAC technology. Customer
adoption is rising, and we expect to be running a total of 31
systems by year end, continuing full scale deployment and
commercialization. Additionally, we are deploying revenue
generating Apps on several rigs and currently have 12 Apps in
varying stages of commercial development showcasing the open
platform of our PAC system. Several Apps are customer-built and
supported by Precision’s PAC platform with specific hosting
agreements in place.
- Enhance financial
performance through higher utilization and improved operating
margins – in the first half of 2018 overall utilization
days are 13% higher than the prior year comparative period while
average operating margins (revenue less operating costs) are up
32%, 12% and 4% in our U.S., international and Canada contract
drilling businesses, respectively.
OUTLOOK
For the second quarter of 2018, the average West
Texas Intermediate price of oil was 41% higher than the prior year
comparative period while the average Henry Hub gas price was 3%
lower and the average AECO price was 55% lower.
|
Three months ended June
30, |
|
|
Year ended December 31, |
|
2018 |
|
|
2017 |
|
|
2017 |
Average oil and
natural gas prices |
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
West
Texas Intermediate (per barrel) (US$) |
|
67.91 |
|
|
|
48.33 |
|
|
|
50.95 |
Natural
gas |
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
AECO (per
MMBtu) (CDN$) |
|
1.20 |
|
|
|
2.69 |
|
|
|
2.16 |
United
States |
|
|
|
|
|
|
|
|
|
|
Henry Hub (per MMBtu) (US$) |
|
2.86 |
|
|
|
2.94 |
|
|
|
2.98 |
Contracts
Year to date in 2018 we have entered into 38
term contracts. The following chart outlines the average number of
drilling rigs by quarter that we had under contract for 2017, the
first two quarters of 2018 and the average number of drilling rigs
by quarter we have under contract for 2018 as of July 25, 2018.
|
|
Average for the quarter ended 2017 |
|
|
Average for the quarter ended 2018 |
|
|
|
Mar. 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
|
Dec. 31 |
|
|
Mar. 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
|
Dec. 31 |
|
Average rigs
under term contract as at July 25,
2018: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
27 |
|
|
|
23 |
|
|
|
19 |
|
|
|
12 |
|
|
|
8 |
|
|
|
9 |
|
|
|
9 |
|
|
|
9 |
|
U.S. |
|
|
26 |
|
|
|
33 |
|
|
|
31 |
|
|
|
27 |
|
|
|
36 |
|
|
|
48 |
|
|
|
47 |
|
|
|
35 |
|
International |
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
7 |
|
|
|
6 |
|
Total |
|
|
61 |
|
|
|
64 |
|
|
|
58 |
|
|
|
47 |
|
|
|
52 |
|
|
|
65 |
|
|
|
63 |
|
|
|
50 |
|
The following chart outlines the average number
of drilling rigs that we had under contract for 2017 and the
average number of rigs we have under contract for 2018 as of July
25, 2018.
|
|
Average for the year ended |
|
|
|
2017 |
|
|
2018 |
|
Average rigs
under term contract as at July 25,
2018: |
|
|
|
|
|
|
|
|
Canada |
|
|
20 |
|
|
|
9 |
|
U.S. |
|
|
29 |
|
|
|
42 |
|
International |
|
|
8 |
|
|
|
7 |
|
Total |
|
|
57 |
|
|
|
58 |
|
In Canada, term contracted rigs normally
generate 250 utilization days per year because of the seasonal
nature of well site access. In most regions in the U.S. and
internationally, term contracts normally generate 365 utilization
days per year.
Drilling Activity
The following chart outlines the average number
of drilling rigs that we had working or moving by quarter for the
periods noted.
|
Average for the quarter ended 2017 |
|
|
2018 |
|
|
Mar. 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
|
Dec. 31 |
|
|
Mar. 31 |
|
|
June 30 |
|
Average Precision
active rig count: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
76 |
|
|
|
29 |
|
|
|
49 |
|
|
|
54 |
|
|
|
72 |
|
|
|
31 |
|
U.S. |
|
47 |
|
|
|
59 |
|
|
|
61 |
|
|
|
58 |
|
|
|
64 |
|
|
|
72 |
|
International |
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
Total |
|
131 |
|
|
|
96 |
|
|
|
118 |
|
|
|
120 |
|
|
|
144 |
|
|
|
111 |
|
For the first half of 2018, drilling activity
has increased relative to this time last year in the U.S. and is
down slightly in Canada. According to industry sources, as of July
20, 2018, the U.S. active land drilling rig count was up
approximately 11% from the same point last year and the Canadian
active land drilling rig count was down approximately 2%. To date
in 2018, approximately 63% of the Canadian industry’s active rigs
and 81% of the U.S. industry’s active rigs were drilling for oil
targets, compared with 53% for Canada and 80% for the U.S. at the
same time last year.
Industry Conditions
We expect Tier 1 rigs to remain the preferred
rigs of customers globally. The economic value created by the
significant drilling and mobility efficiencies delivered by the
most advanced XY pad walking rigs has been highlighted and widely
accepted by our customers. The trend to longer-reach horizontal
completions and importance of the rig delivering these complex
wells consistently and efficiently has been well established by the
industry. We expect demand for leading edge high efficiency Tier 1
rigs will continue to strengthen, as drilling rig capability has
been a key economic facilitator of horizontal/unconventional
resource exploitation. Development and field application of
drilling equipment process automation coupled with closed loop
drilling controls and de-manning of rigs will continue this
technical evolution while creating further cost efficiencies and
performance value for customers.
Capital Spending
Capital spending in 2018 is expected to be $135
million and includes $72 million for sustaining and infrastructure,
$48 million for upgrade and expansion and $15 million on
intangibles related to a new ERP system. We expect that the $135
million will be split $113 million in the Contract Drilling
Services segment, $6 million in the Completion and Production
Services segment and $16 million to the Corporate segment.
SEGMENTED FINANCIAL RESULTS
Precision’s operations are reported in two
segments: Contract Drilling Services, which includes the drilling
rig, directional drilling, oilfield supply and manufacturing
divisions; and Completion and Production Services, which includes
the service rig, snubbing, rental, camp and catering and wastewater
treatment divisions.
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Drilling Services |
|
304,353 |
|
|
|
262,458 |
|
|
|
16.0 |
|
|
|
657,155 |
|
|
|
586,388 |
|
|
|
12.1 |
|
Completion and Production Services |
|
27,706 |
|
|
|
29,381 |
|
|
|
(5.7 |
) |
|
|
77,748 |
|
|
|
75,730 |
|
|
|
2.7 |
|
Inter-segment eliminations |
|
(1,343 |
) |
|
|
(979 |
) |
|
|
37.2 |
|
|
|
(3,181 |
) |
|
|
(2,585 |
) |
|
|
23.1 |
|
|
|
330,716 |
|
|
|
290,860 |
|
|
|
13.7 |
|
|
|
731,722 |
|
|
|
659,533 |
|
|
|
10.9 |
|
Adjusted
EBITDA:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Drilling Services |
|
83,441 |
|
|
|
67,031 |
|
|
|
24.5 |
|
|
|
194,407 |
|
|
|
160,696 |
|
|
|
21.0 |
|
Completion and Production Services |
|
(1,402 |
) |
|
|
336 |
|
|
|
(517.3 |
) |
|
|
3,242 |
|
|
|
4,923 |
|
|
|
(34.1 |
) |
Corporate and other |
|
(19,857 |
) |
|
|
(10,847 |
) |
|
|
83.1 |
|
|
|
(37,998 |
) |
|
|
(24,791 |
) |
|
|
53.3 |
|
|
|
62,182 |
|
|
|
56,520 |
|
|
|
10.0 |
|
|
|
159,651 |
|
|
|
140,828 |
|
|
|
13.4 |
|
(1) Prior year comparatives have changed to reflect a
recast of certain amounts previously netted against operating
expense. See our 2017 Annual Report.(2) See “NON-GAAP
MEASURES”.
SEGMENT REVIEW OF CONTRACT DRILLING
SERVICES
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars, except where noted) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue(1) |
|
304,353 |
|
|
|
262,458 |
|
|
|
16.0 |
|
|
|
657,155 |
|
|
|
586,388 |
|
|
|
12.1 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating(1) |
|
211,008 |
|
|
|
188,080 |
|
|
|
12.2 |
|
|
|
444,156 |
|
|
|
408,897 |
|
|
|
8.6 |
|
General and administrative |
|
9,904 |
|
|
|
7,347 |
|
|
|
34.8 |
|
|
|
18,592 |
|
|
|
16,795 |
|
|
|
10.7 |
|
Adjusted EBITDA(2) |
|
83,441 |
|
|
|
67,031 |
|
|
|
24.5 |
|
|
|
194,407 |
|
|
|
160,696 |
|
|
|
21.0 |
|
Depreciation |
|
80,179 |
|
|
|
85,065 |
|
|
|
(5.7 |
) |
|
|
157,879 |
|
|
|
171,254 |
|
|
|
(7.8 |
) |
Operating
earnings (loss)(2) |
|
3,262 |
|
|
|
(18,034 |
) |
|
|
(118.1 |
) |
|
|
36,528 |
|
|
|
(10,558 |
) |
|
|
(446.0 |
) |
Operating
earnings (loss)(2) as a percentage of revenue |
|
1.1 |
% |
|
|
(6.9 |
)% |
|
|
|
|
|
|
5.6 |
% |
|
|
(1.8 |
)% |
|
|
|
|
(1) Prior year comparatives have changed to
reflect a recast of certain amounts previously netted against
operating expense. See our 2017 Annual Report.(2) See “NON-GAAP
MEASURES”.
|
|
Three months ended June 30, |
|
Canadian
onshore drilling statistics:(1) |
|
2018 |
|
|
2017 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Number of
drilling rigs (end of period) |
|
|
135 |
|
|
|
618 |
|
|
|
136 |
|
|
|
634 |
|
Drilling
rig operating days (spud to release) |
|
|
2,526 |
|
|
|
9,536 |
|
|
|
2,358 |
|
|
|
9,252 |
|
Drilling
rig operating day utilization |
|
|
21 |
% |
|
|
17 |
% |
|
|
19 |
% |
|
|
16 |
% |
Number of
wells drilled |
|
|
227 |
|
|
|
903 |
|
|
|
267 |
|
|
|
1,024 |
|
Average
days per well |
|
|
11.1 |
|
|
|
10.6 |
|
|
|
8.8 |
|
|
|
9.0 |
|
Number of
metres drilled (000s) |
|
|
731 |
|
|
|
2,756 |
|
|
|
758 |
|
|
|
2,928 |
|
Average
metres per well |
|
|
3,218 |
|
|
|
3,052 |
|
|
|
2,839 |
|
|
|
2,859 |
|
Average metres per day |
|
|
289 |
|
|
|
289 |
|
|
|
321 |
|
|
|
316 |
|
|
|
Six months ended June 30, |
|
Canadian
onshore drilling statistics:(1) |
|
2018 |
|
|
2017 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Number of
drilling rigs (end of period) |
|
|
135 |
|
|
|
618 |
|
|
|
136 |
|
|
|
634 |
|
Drilling
rig operating days (spud to release) |
|
|
8,180 |
|
|
|
32,381 |
|
|
|
8,400 |
|
|
|
32,756 |
|
Drilling
rig operating day utilization |
|
|
34 |
% |
|
|
29 |
% |
|
|
34 |
% |
|
|
28 |
% |
Number of
wells drilled |
|
|
742 |
|
|
|
3,133 |
|
|
|
831 |
|
|
|
3,308 |
|
Average
days per well |
|
|
11.0 |
|
|
|
10.3 |
|
|
|
10.1 |
|
|
|
9.9 |
|
Number of
metres drilled (000s) |
|
|
2,228 |
|
|
|
9,201 |
|
|
|
2,229 |
|
|
|
9,088 |
|
Average
metres per well |
|
|
3,003 |
|
|
|
2,937 |
|
|
|
2,682 |
|
|
|
2,747 |
|
Average metres per day |
|
|
272 |
|
|
|
284 |
|
|
|
265 |
|
|
|
277 |
|
(1) Canadian operations only.(2) Canadian
Association of Oilwell Drilling Contractors (“CAODC”), and
Precision – excludes non-CAODC rigs and non-reporting CAODC
members.
United
States onshore drilling statistics:(1) |
2018 |
|
|
2017 |
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Average number of
active land rigs for quarters ended: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31 |
|
64 |
|
|
|
951 |
|
|
|
47 |
|
|
|
722 |
|
June 30 |
|
72 |
|
|
|
1,021 |
|
|
|
59 |
|
|
|
874 |
|
Year to date average |
|
68 |
|
|
|
986 |
|
|
|
53 |
|
|
|
798 |
|
(1) United States lower 48 operations only.(2)
Baker Hughes rig counts.
Revenue from Contract Drilling Services was $304
million this quarter, or 16% higher than the second quarter of
2017, while adjusted EBITDA increased by 24% to $83 million. The
increase in revenue was primarily due to higher utilization days in
the United States. During the quarter we did not recognize any
shortfall payments in our Canadian contract drilling business
compared with $4 million in the prior year comparative period. In
the U.S. we recognized turnkey revenue of US$10 million compared
with US$5 million in the comparative period and we did not
recognize any idle but contracted revenue compared with US$2
million in the comparative quarter of 2017.
Drilling rig utilization days in Canada
(drilling days plus move days) were 2,834 during the second quarter
of 2018, an increase of 7% compared to 2017 primarily due to
increased Deep Basin activity with several customers working pad
rigs through spring break-up. Drilling rig utilization days in the
U.S. were 6,588, or 24% higher than the same quarter of 2017 as our
U.S. activity was up with higher industry activity. Drilling rig
utilization days in our international business were 728, in-line
with the same quarter of 2017.
Compared with the same quarter in 2017, drilling
rig revenue per utilization day in Canada was in-line with last
year as increases in spot market rates in the current quarter
offset lower shortfall revenue and a higher number of rigs under
long-term contract in the prior period. Drilling rig revenue per
utilization day for the quarter in the U.S. was up 10% compared to
prior year as higher average day rates and higher turnkey revenue
were partially offset by lower lump sum move revenue and lower idle
but contract revenue. International revenue per utilization day was
in-line with the prior year comparative period.
In Canada, 8% of our utilization days in the
quarter were generated from rigs under term contract, compared with
31% in the second quarter of 2017. In the U.S., 67% of utilization
days were generated from rigs under term contract as compared with
57% in the second quarter of 2017.
Operating costs were 69% of revenue for the
quarter which was two percentage points lower than the prior year
period. On a per utilization day basis, operating costs for the
drilling rig division in Canada were slightly higher than the prior
year period primarily driven by larger average crew sizes
associated with increased pad rig activity in the quarter. In the
U.S., operating costs for the quarter on a per day basis were
slightly lower than the prior year period primarily due to higher
lump sum move costs in the prior period and the impact of fixed
costs spread over higher activity partially offset by higher costs
associated with turnkey activity.
Depreciation expense in the quarter was 6% lower
than in the second quarter of 2017. The decrease in depreciation
expense was primarily due to the strengthening of the Canadian
dollar on our U.S. dollar denominated costs and a lower capital
asset base as assets become fully depreciated.
SEGMENT REVIEW OF COMPLETION AND PRODUCTION
SERVICES
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars, except where noted) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue |
|
27,706 |
|
|
|
29,381 |
|
|
|
(5.7 |
) |
|
|
77,748 |
|
|
|
75,730 |
|
|
|
2.7 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
26,814 |
|
|
|
27,231 |
|
|
|
(1.5 |
) |
|
|
70,078 |
|
|
|
67,099 |
|
|
|
4.4 |
|
General and administrative |
|
2,294 |
|
|
|
1,814 |
|
|
|
26.5 |
|
|
|
4,428 |
|
|
|
3,708 |
|
|
|
19.4 |
|
Adjusted EBITDA(1) |
|
(1,402 |
) |
|
|
336 |
|
|
|
(517.3 |
) |
|
|
3,242 |
|
|
|
4,923 |
|
|
|
(34.1 |
) |
Depreciation |
|
5,012 |
|
|
|
7,094 |
|
|
|
(29.3 |
) |
|
|
11,887 |
|
|
|
14,497 |
|
|
|
(18.0 |
) |
Operating
loss(1) |
|
(6,414 |
) |
|
|
(6,758 |
) |
|
|
(5.1 |
) |
|
|
(8,645 |
) |
|
|
(9,574 |
) |
|
|
(9.7 |
) |
Operating
loss(1) as a percentage of revenue |
|
(23.2 |
)% |
|
|
(23.0 |
)% |
|
|
|
|
|
|
(11.1 |
)% |
|
|
(12.6 |
)% |
|
|
|
|
Well servicing
statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
service rigs (end of period) |
|
210 |
|
|
|
210 |
|
|
|
- |
|
|
|
210 |
|
|
|
210 |
|
|
|
- |
|
Service
rig operating hours |
|
31,824 |
|
|
|
33,813 |
|
|
|
(5.9 |
) |
|
|
84,525 |
|
|
|
85,870 |
|
|
|
(1.6 |
) |
Service
rig operating hour utilization |
|
17 |
% |
|
|
18 |
% |
|
|
(5.6 |
) |
|
|
22 |
% |
|
|
23 |
% |
|
|
(4.3 |
) |
Service rig revenue per operating hour |
|
676 |
|
|
|
629 |
|
|
|
7.5 |
|
|
|
691 |
|
|
|
633 |
|
|
|
9.2 |
|
(1) See “NON-GAAP MEASURES”.
Revenue from Completion and Production Services
was down $2 million or 6% compared with the second quarter of 2017
due to lower activity in our Canadian well servicing and rental
businesses partially offset by higher camp activity. Our service
rig operating hours in the quarter were down 6% from the second
quarter of 2017 while rates increased an average of 7%.
Approximately 98% of our second quarter Canadian service rig
activity was oil related.
During the quarter, Completion and Production
Services generated 88% of its revenue from Canadian operations and
12% from U.S. operations compared with the second quarter of 2017
where 86% of revenue was generated in Canada and 14% in the
U.S.
Average service rig revenue per operating hour
in the quarter was $676 or $47 higher than the second quarter of
2017. The increase was primarily the result of increased costs
passed through to the customer.
Adjusted EBITDA was lower than the second
quarter of 2017 primarily due to reorganization costs of $1 million
incurred in the current quarter.
Operating costs as a percentage of revenue was
97% compared with the prior year comparative quarter of 93%.
Depreciation in the quarter was $2 million lower
than the prior year comparative period. The lower depreciation is
due to a lower asset base as assets become fully depreciated.
SEGMENT REVIEW OF CORPORATE AND
OTHER
Our Corporate and Other segment provides support
functions to our operating segments. The Corporate and Other
segment had an adjusted EBITDA loss of $20 million, a $9 million
increase compared with the second quarter of 2017 primarily due to
higher share-based incentive compensation.
OTHER ITEMS
Share-based Incentive Compensation
Plans
We have several cash-settled share-based
incentive plans for non-management directors, officers, and other
eligible employees. The fair values of the amounts payable under
these plans are recognized as an expense with a corresponding
increase in liabilities over the period that the participant
becomes entitled to payment. The recorded liability is
re-established at the end of each reporting period until settlement
with the resultant change to fair value of the liability recognized
in net earnings (loss) for the period.
We also have two equity-settled share-based
incentive plans. Under the Executive Performance Share plan, which
commenced in May 2017, the fair value of the PSUs granted is
calculated at the date of grant using a Monte Carlo simulation, and
that value is recorded as compensation expense over the grant's
vesting period with an offset to contributed surplus. Upon
redemption of the PSUs into common shares, the associated amount is
reclassified from contributed surplus to shareholders' capital. The
share option plan is treated similarly, except that the fair value
of the share purchased options granted are valued using the
Black-Scholes option pricing model and consideration paid by
employees upon exercise of the equity purchase options are
recognized in share capital.
A summary of the amounts expensed (recovered)
under these plans during the reporting periods are as follows:
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars) |
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Cash settled
share-based incentive plans |
|
7,681 |
|
|
|
(4,452 |
) |
|
|
15,471 |
|
|
|
(2,314 |
) |
Equity settled
share-based incentive plans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Executive
PSU |
|
1,696 |
|
|
|
821 |
|
|
|
2,749 |
|
|
|
821 |
|
Stock option plan |
|
901 |
|
|
|
587 |
|
|
|
1,718 |
|
|
|
1,720 |
|
Total
share-based incentive compensation plan expense |
|
10,278 |
|
|
|
(3,044 |
) |
|
|
19,938 |
|
|
|
227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
3,305 |
|
|
|
(944 |
) |
|
|
6,801 |
|
|
|
434 |
|
General and Administrative |
|
6,973 |
|
|
|
(2,100 |
) |
|
|
13,137 |
|
|
|
(207 |
) |
|
|
10,278 |
|
|
|
(3,044 |
) |
|
|
19,938 |
|
|
|
227 |
|
Cash settled shared-based compensation expense
increased $12 million in the current quarter to $8 million compared
to a recovery of $4 million in the same quarter in 2017. The
increase is primarily due to the increasing share price experienced
in the current quarter compared to a declining share price in the
comparative 2017 period.
Executive PSU share-based incentive compensation
expense for the quarter was $2 million compared to $1 million in
the same quarter in 2017. This increase is a result of the plan
being implemented part way through the second quarter in 2017 and
from additional grants in 2018.
Financing Charges
Net financial charges for the quarter were $32
million, a decrease of $2 million compared with the second quarter
of 2017 primarily because of a stronger Canadian dollar on our U.S.
dollar denominated interest expense, reduction in interest expense
related to debt retired in 2017 and higher interest income in the
current period.
Loss on Repurchase and Redemption of
Unsecured Senior Notes
During the quarter we redeemed US$50 million of
our 6.5% unsecured senior notes due 2021 and repurchased and
cancelled US$3 million principal amount of our 2021 notes and US$5
million principal amount of our 2024 notes incurring a net loss of
$1 million.
Income Tax
Income tax expense for the quarter was a
recovery of $13 million compared with a recovery of $37 million in
the same quarter in 2017. The recoveries are due to negative pretax
earnings.
LIQUIDITY AND CAPITAL
RESOURCES
The oilfield services business is inherently
cyclical in nature. To manage this, we focus on maintaining a
strong balance sheet so we have the financial flexibility we need
to continue to manage our growth and cash flow, regardless of where
we are in the business cycle. We maintain a variable operating cost
structure so we can be responsive to changes in demand.
Our maintenance capital expenditures are tightly
governed by and highly responsive to activity levels with
additional cost savings leverage provided through our internal
manufacturing and supply divisions. Term contracts on expansion
capital for new-build rig programs provide more certainty of future
revenues and return on our capital investments.
Liquidity
Amount |
|
Availability |
|
Used for |
|
Maturity |
Senior facility (secured) |
|
|
|
|
|
|
US$500
million (extendible, revolvingterm credit facility with US$250
million(1) accordion feature) |
|
Undrawn,
except US$28 million inoutstanding letters of credit |
|
General
corporate purposes |
|
November
21, 2021 |
Operating facilities (secured) |
|
|
|
|
|
|
$40
million |
|
Undrawn,
except $29 million inoutstanding letters of credit |
|
Letters
of credit and generalcorporate purposes |
|
|
US$15
million |
|
Undrawn |
|
Short
term working capitalrequirements |
|
|
Demand letter of credit facility (secured) |
|
|
|
|
|
|
US$30
million |
|
Undrawn,
except US$13 million inoutstanding letters of credit |
|
Letters
of credit |
|
|
Unsecured senior notes (unsecured) |
|
|
|
|
|
|
US$196
million – 6.5% |
|
Fully
drawn |
|
Capital
expenditures and generalcorporate purposes |
|
December
15, 2021 |
US$350
million – 7.75% |
|
Fully
drawn |
|
Debt
redemption and repurchases |
|
December
15, 2023 |
US$395
million – 5.25% |
|
Fully
drawn |
|
Capital
expenditures and generalcorporate purposes |
|
November
15, 2024 |
US$400
million – 7.125% |
|
Fully
drawn |
|
Debt
redemption and repurchases |
|
January
15, 2026 |
(1) Increases to US$300 million at the end of the covenant
relief period of March 31, 2019.
As at June 30, 2018, we had $1,762 million
outstanding under our unsecured senior notes. The current blended
cash interest cost of our debt is approximately 6.6%.
Covenants
Following is a listing of our currently
applicable financial covenants and the calculations as at June 30,
2018.
|
Covenant |
|
As at June 30, 2018 |
|
Senior
Facility |
|
|
|
|
|
Consolidated senior debt to consolidated Covenant EBITDA(1) |
<
2.50 |
|
|
0.08 |
|
Consolidated Covenant EBITDA to consolidated interest expense |
>
2.00 |
|
|
2.98 |
|
Unsecured
Senior Notes |
|
|
|
|
|
Consolidated interest coverage ratio |
> 2.00 |
|
|
2.39 |
|
(1) For purposes of calculating the leverage ratio consolidated
senior debt only includes secured indebtedness.
At June 30, 2018, we were in compliance with the
covenants of our senior credit facility and unsecured senior
notes.
Senior Facility
The senior credit facility requires that we
comply with certain covenants including a leverage ratio of
consolidated senior debt to consolidated Covenant EBITDA (see
“NON-GAAP MEASURES”) of less than 2.5:1. For purposes of
calculating the leverage ratio consolidated senior debt only
includes secured indebtedness.
Under the senior credit facility, we are
required to maintain a ratio of consolidated Covenant EBITDA to
consolidated interest expense for the most recent four consecutive
quarters, of greater than 2.0:1 for the periods ending June 30,
September 30, and December 31, 2018 and March 31, 2019. For periods
ending after March 31, 2019 the ratio reverts to 2.5:1.
The senior credit facility prevents us from
making distributions prior to April 1, 2019, after which,
distributions are subject to a pro forma consolidated senior net
leverage covenant of less than or equal to 1.75:1. The senior
credit facility also limits the redemption and repurchase of junior
debt subject to a pro forma consolidated senior net leverage
covenant ratio of less than or equal to 1.75:1.
In addition, the senior credit facility contains
certain covenants that place restrictions on our ability to incur
or assume additional indebtedness; dispose of assets; pay
dividends, undertake share redemptions or other distributions;
change our primary business; incur liens on assets; engage in
transactions with affiliates; enter into mergers, consolidations or
amalgamations; and enter into speculative swap agreements.
Unsecured Senior Notes
The senior notes require that we comply with
financial covenants including an incurrence based consolidated
interest coverage ratio test of consolidated cash flow, as defined
in the senior note agreements, to consolidated interest expense of
greater than 2.0:1 for the most recent four consecutive fiscal
quarters. In the event that our consolidated interest coverage
ratio is less than 2.0:1 for the most recent four consecutive
fiscal quarters the senior notes restrict our ability to incur
additional indebtedness.
The senior notes contain a restricted payments
covenant that limits our ability to make payments in the nature of
dividends, distributions and for repurchases from shareholders.
This restricted payment basket grows from a starting point of
October 1, 2010 for the 2021 and 2024 senior notes, from October 1,
2016 for the 2023 senior notes and October 1, 2017 for the 2026
senior notes by, among other things, 50% of consolidated cumulative
net earnings and decreases by 100% of consolidated cumulative net
losses, as defined in the note agreements, and payments made to
shareholders. Beginning with the December 31, 2015 calculation the
governing net restricted payments basket was negative and as of
that date we were no longer able to declare and make dividend
payments until such time as the restricted payments baskets once
again become positive. For further information, please see the
senior note indentures which are available on SEDAR and EDGAR.
In addition, the senior notes contain certain
covenants that limit our ability, and the ability of certain
subsidiaries, to incur additional indebtedness and issue preferred
shares; create liens; create or permit to exist restrictions on our
ability or certain subsidiaries to make certain payments and
distributions; engage in amalgamations, mergers or consolidations;
make certain dispositions and engage in transactions with
affiliates.
Hedge of investments in foreign operations
We utilize foreign currency long-term debt to
hedge our exposure to changes in the carrying values of our net
investment in certain foreign operations as a result of changes in
foreign exchange rates.
We have designated our U.S. dollar denominated
long-term debt as a net investment hedge in our U.S. operations and
other foreign operations that have a U.S. dollar functional
currency. To be accounted for as a hedge, the foreign currency
denominated long-term debt must be designated and documented as
such and must be effective at inception and on an ongoing basis. We
recognize the effective amount of this hedge (net of tax) in other
comprehensive income. We recognize ineffective amounts (if any) in
net earnings (loss).
Average shares outstanding
The following table reconciles the weighted
average shares outstanding used in computing basic and diluted net
loss per share:
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands) |
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Weighted average shares
outstanding – basic |
|
293,471 |
|
|
|
293,239 |
|
|
|
293,355 |
|
|
|
293,239 |
|
Effect of
stock options and other equity compensation plans |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Weighted
average shares outstanding – diluted |
|
293,471 |
|
|
|
293,239 |
|
|
|
293,355 |
|
|
|
293,239 |
|
QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per share
amounts) |
|
2017 |
|
|
2018 |
|
Quarters
ended |
|
September 30 |
|
|
December 31 |
|
|
March 31 |
|
|
June 30 |
|
Revenue(1) |
|
|
314,504 |
|
|
|
347,187 |
|
|
|
401,006 |
|
|
|
330,716 |
|
Adjusted EBITDA(2) |
|
|
73,239 |
|
|
|
90,914 |
|
|
|
97,469 |
|
|
|
62,182 |
|
Net loss |
|
|
(26,287 |
) |
|
|
(47,005 |
) |
|
|
(18,077 |
) |
|
|
(47,217 |
) |
Net loss per basic and
diluted share |
|
|
(0.09 |
) |
|
|
(0.16 |
) |
|
|
(0.06 |
) |
|
|
(0.16 |
) |
Funds provided by (used
in) operations(2) |
|
|
85,140 |
|
|
|
28,323 |
|
|
|
104,026 |
|
|
|
50,225 |
|
Cash
provided by (used in) operations |
|
|
56,757 |
|
|
|
23,289 |
|
|
|
38,189 |
|
|
|
129,695 |
|
(Stated in thousands of Canadian dollars, except per share
amounts) |
|
2016 |
|
|
2017 |
|
Quarters
ended |
|
September 30 |
|
|
December 31 |
|
|
March 31 |
|
|
June 30 |
|
Revenue(1) |
|
|
213,668 |
|
|
|
302,653 |
|
|
|
368,673 |
|
|
|
290,860 |
|
Adjusted EBITDA(2) |
|
|
41,411 |
|
|
|
65,000 |
|
|
|
84,308 |
|
|
|
56,520 |
|
Net loss |
|
|
(47,377 |
) |
|
|
(30,618 |
) |
|
|
(22,614 |
) |
|
|
(36,130 |
) |
Net loss per basic and
diluted share |
|
|
(0.16 |
) |
|
|
(0.10 |
) |
|
|
(0.08 |
) |
|
|
(0.12 |
) |
Funds provided by (used
in) operations(2) |
|
|
31,688 |
|
|
|
11,466 |
|
|
|
85,659 |
|
|
|
(15,187 |
) |
Cash
provided by (used in) operations |
|
|
17,515 |
|
|
|
(27,846 |
) |
|
|
33,770 |
|
|
|
2,739 |
|
(1) Prior year comparatives have changed to
reflect a recast of certain amounts previously netted against
operating expense. See our 2017 Annual Report.(2) See “NON-GAAP
MEASURES”.
CRITICAL ACCOUNTING JUDGEMENTS AND
ESTIMATES
Because of the nature of our business, we are
required to make judgments and estimates in preparing our
Consolidated Interim Financial Statements that could materially
affect the amounts recognized. Our judgments and estimates are
based on our past experiences and assumptions we believe are
reasonable in the circumstances. The critical judgments and
estimates used in preparing the Interim Financial Statements are
described in our 2017 Annual Report and there have been no material
changes to our critical accounting judgments and estimates during
the three and six-month periods ended June 30, 2018 except for
those impacted by the adoption of new accounting standards.
NON-GAAP MEASURES
In this press release we reference non-GAAP
(Generally Accepted Accounting Principles) measures. Adjusted
EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided
by (Used in) Operations and Working Capital are terms used by us to
assess performance as we believe they provide useful supplemental
information to investors. These terms do not have standardized
meanings prescribed under International Financial Reporting
Standards (IFRS) and may not be comparable to
similar measures used by other companies.
Adjusted EBITDA
We believe that adjusted EBITDA (earnings before
income taxes, loss on repurchase and redemption of unsecured senior
notes, finance charges, foreign exchange, and depreciation and
amortization), as reported in the Interim Consolidated Statement of
Loss, is a useful measure, because it gives an indication of the
results from our principal business activities prior to
consideration of how our activities are financed and the impact of
foreign exchange, taxation and depreciation and amortization
charges.
Covenant EBITDA
Covenant EBITDA, as defined in our senior credit
facility agreement, is used in determining the Corporation’s
compliance with its covenants. Covenant EBITDA differs from
Adjusted EBITDA by the exclusion of bad debt expense, restructuring
costs and certain foreign exchange amounts.
Operating Earnings (Loss)
We believe that operating earnings (loss), as
reported in the Interim Consolidated Statements of Loss, is a
useful measure because it provides an indication of the results of
our principal business activities before consideration of how those
activities are financed and the impact of foreign exchange and
taxation.
Funds Provided By (Used In)
Operations
We believe that funds provided by (used in)
operations, as reported in the Interim Consolidated Statements of
Cash Flow, is a useful measure because it provides an indication of
the funds our principal business activities generate prior to
consideration of working capital, which is primarily made up of
highly liquid balances.
Working Capital
We define working capital as current assets less
current liabilities as reported on the Interim Consolidated
Statement of Financial Position.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING
INFORMATION AND STATEMENTS
Certain statements contained in this report,
including statements that contain words such as "could", "should",
"can", "anticipate", "estimate", "intend", "plan", "expect",
"believe", "will", "may", "continue", "project", "potential" and
similar expressions and statements relating to matters that are not
historical facts constitute "forward-looking information" within
the meaning of applicable Canadian securities legislation and
"forward-looking statements" within the meaning of the "safe
harbor" provisions of the United States Private Securities
Litigation Reform Act of 1995 (collectively, "forward-looking
information and statements").
In particular, forward looking information and
statements include, but are not limited to, the following:
- our strategic priorities for
2018;
- our capital expenditure plans for
2018;
- anticipated activity levels in 2018
and our scheduled infrastructure projects;
- anticipated demand for Tier 1 rigs;
and
- the average number of term
contracts in place for 2018.
These forward-looking information and statements
are based on certain assumptions and analysis made by Precision in
light of our experience and our perception of historical trends,
current conditions, expected future developments and other factors
we believe are appropriate under the circumstances. These include,
among other things:
- the fluctuation in oil prices may pressure customers into
reducing or limiting their drilling budgets;
- the status of current negotiations with our customers and
vendors;
- customer focus on safety performance;
- existing term contracts are neither renewed nor terminated
prematurely;
- our ability to deliver rigs to customers on a timely basis;
and
- the general stability of the economic and political
environments in the jurisdictions where we operate.
Undue reliance should not be placed on
forward-looking information and statements. Whether actual results,
performance or achievements will conform to our expectations and
predictions is subject to a number of known and unknown risks and
uncertainties which could cause actual results to differ materially
from our expectations. Such risks and uncertainties include, but
are not limited to:
- volatility in the price and demand for oil and natural
gas;
- fluctuations in the demand for contract drilling, well
servicing and ancillary oilfield services;
- our customers’ inability to obtain adequate credit or financing
to support their drilling and production activity;
- changes in drilling and well servicing technology which could
reduce demand for certain rigs or put us at a competitive
disadvantage;
- shortages, delays and interruptions in the delivery of
equipment supplies and other key inputs;
- the effects of seasonal and weather conditions on operations
and facilities;
- the availability of qualified personnel and management;
- a decline in our safety performance which could result in lower
demand for our services;
- changes in environmental laws and regulations such as increased
regulation of hydraulic fracturing or restrictions on the burning
of fossil fuels and greenhouse gas emissions, which could have an
adverse impact on the demand for oil and gas;
- terrorism, social, civil and political unrest in the foreign
jurisdictions where we operate;
- fluctuations in foreign exchange, interest rates and tax rates;
and
- other unforeseen conditions which could impact the use of
services supplied by Precision and Precision’s ability to respond
to such conditions.
Readers are cautioned that the forgoing list of
risk factors is not exhaustive. Additional information on these and
other factors that could affect our business, operations or
financial results are included in reports on file with applicable
securities regulatory authorities, including but not limited to
Precision’s Annual Information Form for the year ended December 31,
2017, which may be accessed on Precision’s SEDAR profile at
www.sedar.com or under Precision’s EDGAR profile at www.sec.gov.
The forward-looking information and statements contained in this
news release are made as of the date hereof and Precision
undertakes no obligation to update publicly or revise any
forward-looking statements or information, whether as a result of
new information, future events or otherwise, except as required by
law.
INTERIM CONSOLIDATED STATEMENTS OF
FINANCIAL POSITION (UNAUDITED)
(Stated in thousands of Canadian dollars) |
|
June 30,2018 |
|
|
December 31,2017 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
94,669 |
|
|
$ |
65,081 |
|
Accounts
receivable |
|
|
314,970 |
|
|
|
322,585 |
|
Income tax
recoverable |
|
|
952 |
|
|
|
29,449 |
|
Inventory |
|
|
33,784 |
|
|
|
24,631 |
|
Total current
assets |
|
|
444,375 |
|
|
|
441,746 |
|
Non-current
assets: |
|
|
|
|
|
|
|
|
Income tax
recoverable |
|
|
2,358 |
|
|
|
2,256 |
|
Deferred tax
assets |
|
|
38,024 |
|
|
|
41,822 |
|
Property, plant and
equipment |
|
|
3,130,686 |
|
|
|
3,173,824 |
|
Intangibles |
|
|
36,129 |
|
|
|
28,116 |
|
Goodwill |
|
|
206,649 |
|
|
|
205,167 |
|
Total
non-current assets |
|
|
3,413,846 |
|
|
|
3,451,185 |
|
Total
assets |
|
$ |
3,858,221 |
|
|
$ |
3,892,931 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
|
|
|
|
|
Current
liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and
accrued liabilities |
|
$ |
248,226 |
|
|
$ |
209,625 |
|
Non-current
liabilities: |
|
|
|
|
|
|
|
|
Share based
compensation |
|
|
7,841 |
|
|
|
13,536 |
|
Provisions and
other |
|
|
9,897 |
|
|
|
10,086 |
|
Long-term debt |
|
|
1,735,842 |
|
|
|
1,730,437 |
|
Deferred
tax liability |
|
|
90,350 |
|
|
|
118,911 |
|
Total non-current
liabilities |
|
|
1,843,930 |
|
|
|
1,872,970 |
|
Shareholders’
equity: |
|
|
|
|
|
|
|
|
Shareholders’
capital |
|
|
2,321,902 |
|
|
|
2,319,293 |
|
Contributed
surplus |
|
|
47,695 |
|
|
|
44,037 |
|
Deficit |
|
|
(749,898 |
) |
|
|
(684,604 |
) |
Accumulated other comprehensive income |
|
|
146,366 |
|
|
|
131,610 |
|
Total
shareholders’ equity |
|
|
1,766,065 |
|
|
|
1,810,336 |
|
Total
liabilities and shareholders’ equity |
|
$ |
3,858,221 |
|
|
$ |
3,892,931 |
|
INTERIM CONSOLIDATED STATEMENTS OF LOSS
(UNAUDITED)
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars, except per share amounts) |
|
2018 |
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
330,716 |
|
$ |
290,860 |
|
|
$ |
731,722 |
|
|
$ |
659,533 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
236,479 |
|
|
214,332 |
|
|
|
511,053 |
|
|
|
473,411 |
|
General
and administrative |
|
|
32,055 |
|
|
20,008 |
|
|
|
61,018 |
|
|
|
45,294 |
|
Earnings before income
taxes, loss on repurchase and redemption of unsecured
senior notes, finance charges, foreign exchange and
depreciation and amortization |
|
|
62,182 |
|
|
56,520 |
|
|
|
159,651 |
|
|
|
140,828 |
|
Depreciation and amortization |
|
|
88,621 |
|
|
95,799 |
|
|
|
175,929 |
|
|
|
192,962 |
|
Operating loss |
|
|
(26,439 |
) |
|
(39,279 |
) |
|
|
(16,278 |
) |
|
|
(52,134 |
) |
Foreign exchange |
|
|
556 |
|
|
(798 |
) |
|
|
1,771 |
|
|
|
(751 |
) |
Finance charges |
|
|
32,103 |
|
|
34,532 |
|
|
|
63,782 |
|
|
|
67,514 |
|
Loss on
repurchase and redemption of unsecured senior notes |
|
|
1,176 |
|
|
— |
|
|
|
1,176 |
|
|
|
— |
|
Loss before income
taxes |
|
|
(60,274 |
) |
|
(73,013 |
) |
|
|
(83,007 |
) |
|
|
(118,897 |
) |
Income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
3,599 |
|
|
(640 |
) |
|
|
5,165 |
|
|
|
250 |
|
Deferred |
|
|
(16,656 |
) |
|
(36,243 |
) |
|
|
(22,878 |
) |
|
|
(60,403 |
) |
|
|
|
(13,057 |
) |
|
(36,883 |
) |
|
|
(17,713 |
) |
|
|
(60,153 |
) |
Net
loss |
|
$ |
(47,217 |
) |
$ |
(36,130 |
) |
|
$ |
(65,294 |
) |
|
|
(58,744 |
) |
Net loss per
share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.16 |
) |
$ |
(0.12 |
) |
|
$ |
(0.22 |
) |
|
$ |
(0.20 |
) |
Diluted |
|
$ |
(0.16 |
) |
$ |
(0.12 |
) |
|
$ |
(0.22 |
) |
|
$ |
(0.20 |
) |
INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(UNAUDITED)
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Net loss |
|
$ |
(47,217 |
) |
|
$ |
(36,130 |
) |
|
$ |
(65,294 |
) |
|
$ |
(58,744 |
) |
Unrealized gain (loss)
on translation of assets and liabilities of operations
denominated in foreign currency |
|
|
39,592 |
|
|
|
(57,408 |
) |
|
|
93,326 |
|
|
|
(75,962 |
) |
Foreign
exchange gain (loss) on net investment hedge with U.S.
denominated debt, net of tax |
|
|
(33,115 |
) |
|
|
48,901 |
|
|
|
(78,570 |
) |
|
|
64,025 |
|
Comprehensive loss |
|
$ |
(40,740 |
) |
|
$ |
(44,637 |
) |
|
$ |
(50,538 |
) |
|
$ |
(70,681 |
) |
INTERIM CONSOLIDATED STATEMENTS OF CASH
FLOW (UNAUDITED)
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(Stated
in thousands of Canadian dollars) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Cash provided by (used
in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(47,217 |
) |
|
$ |
(36,130 |
) |
|
$ |
(65,294 |
) |
|
$ |
(58,744 |
) |
Adjustments for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term compensation
plans |
|
|
6,027 |
|
|
|
(602 |
) |
|
|
13,926 |
|
|
|
2,331 |
|
Depreciation and
amortization |
|
|
88,621 |
|
|
|
95,799 |
|
|
|
175,929 |
|
|
|
192,962 |
|
Foreign exchange |
|
|
(15 |
) |
|
|
(1,402 |
) |
|
|
1,433 |
|
|
|
(1,354 |
) |
Finance charges |
|
|
32,103 |
|
|
|
34,532 |
|
|
|
63,782 |
|
|
|
67,514 |
|
Income taxes |
|
|
(13,057 |
) |
|
|
(36,883 |
) |
|
|
(17,713 |
) |
|
|
(60,153 |
) |
Other |
|
|
(217 |
) |
|
|
(607 |
) |
|
|
(1,133 |
) |
|
|
(777 |
) |
Loss on repurchase and
redemption of unsecured senior notes |
|
|
1,176 |
|
|
|
— |
|
|
|
1,176 |
|
|
|
— |
|
Income taxes paid |
|
|
(3,282 |
) |
|
|
(1,711 |
) |
|
|
(3,606 |
) |
|
|
(2,761 |
) |
Income taxes
recovered |
|
|
27,551 |
|
|
|
— |
|
|
|
27,587 |
|
|
|
332 |
|
Interest paid |
|
|
(42,021 |
) |
|
|
(68,351 |
) |
|
|
(42,521 |
) |
|
|
(70,259 |
) |
Interest
received |
|
|
556 |
|
|
|
168 |
|
|
|
685 |
|
|
|
1,381 |
|
Funds provided by (used
in) operations |
|
|
50,225 |
|
|
|
(15,187 |
) |
|
|
154,251 |
|
|
|
70,472 |
|
Changes
in non-cash working capital balances |
|
|
79,470 |
|
|
|
17,926 |
|
|
|
13,633 |
|
|
|
(33,963 |
) |
|
|
|
129,695 |
|
|
|
2,739 |
|
|
|
167,884 |
|
|
|
36,509 |
|
Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property,
plant and equipment |
|
|
(34,324 |
) |
|
|
(21,136 |
) |
|
|
(56,615 |
) |
|
|
(41,559 |
) |
Purchase of
intangibles |
|
|
(2,429 |
) |
|
|
(7,301 |
) |
|
|
(10,220 |
) |
|
|
(8,970 |
) |
Proceeds on sale of
property, plant and equipment |
|
|
2,630 |
|
|
|
3,563 |
|
|
|
8,680 |
|
|
|
5,781 |
|
Changes
in non-cash working capital balances |
|
|
(8,204 |
) |
|
|
(2,175 |
) |
|
|
(8,032 |
) |
|
|
(10,566 |
) |
|
|
|
(42,327 |
) |
|
|
(27,049 |
) |
|
|
(66,187 |
) |
|
|
(55,314 |
) |
Financing: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt amendment
fees |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(341 |
) |
Redemption and
repayment of unsecured senior notes |
|
|
(76,657 |
) |
|
|
— |
|
|
|
(76,657 |
) |
|
|
— |
|
|
|
|
(76,657 |
) |
|
|
— |
|
|
|
(76,657 |
) |
|
|
(341 |
) |
Effect of
exchange rate changes on cash and cash equivalents |
|
|
2,085 |
|
|
|
(1,206 |
) |
|
|
4,548 |
|
|
|
(1,495 |
) |
Increase (decrease) in
cash and cash equivalents |
|
|
12,796 |
|
|
|
(25,516 |
) |
|
|
29,588 |
|
|
|
(20,641 |
) |
Cash and
cash equivalents, beginning of period |
|
|
81,873 |
|
|
|
120,580 |
|
|
|
65,081 |
|
|
|
115,705 |
|
Cash and
cash equivalents, end of period |
|
$ |
94,669 |
|
|
$ |
95,064 |
|
|
$ |
94,669 |
|
|
$ |
95,064 |
|
INTERIM CONSOLIDATED STATEMENTS OF
CHANGES IN EQUITY (UNAUDITED)
(Stated in thousands of Canadian dollars) |
|
Shareholders’capital |
|
|
Contributedsurplus |
|
|
Accumulatedothercomprehensiveincome |
|
|
Deficit |
|
|
Totalequity |
|
Balance at January 1,
2018 |
|
$ |
2,319,293 |
|
|
$ |
44,037 |
|
|
$ |
131,610 |
|
|
$ |
(684,604 |
) |
|
$ |
1,810,336 |
|
Net loss for the
period |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(65,294 |
) |
|
|
(65,294 |
) |
Other comprehensive
income for the period |
|
|
— |
|
|
|
— |
|
|
|
14,756 |
|
|
|
— |
|
|
|
14,756 |
|
Shares issued on
redemption non-management directors' DSUs |
|
|
2,609 |
|
|
|
(809 |
) |
|
|
— |
|
|
|
— |
|
|
|
1,800 |
|
Share
based compensation expense |
|
|
— |
|
|
|
4,467 |
|
|
|
— |
|
|
|
— |
|
|
|
4,467 |
|
Balance at June 30, 2018 |
|
$ |
2,321,902 |
|
|
$ |
47,695 |
|
|
$ |
146,366 |
|
|
$ |
(749,898 |
) |
|
$ |
1,766,065 |
|
(Stated in thousands of Canadian dollars) |
|
Shareholders’capital |
|
|
Contributedsurplus |
|
|
Accumulatedothercomprehensiveincome |
|
|
Deficit |
|
|
Totalequity |
|
Balance at January 1,
2017 |
|
$ |
2,319,293 |
|
|
$ |
38,937 |
|
|
$ |
156,456 |
|
|
$ |
(552,568 |
) |
|
$ |
1,962,118 |
|
Net loss for the
period |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(58,744 |
) |
|
|
(58,744 |
) |
Other comprehensive
loss for the period |
|
|
— |
|
|
|
— |
|
|
|
(11,937 |
) |
|
|
— |
|
|
|
(11,937 |
) |
Share
based compensation expense |
|
|
— |
|
|
|
2,541 |
|
|
|
— |
|
|
|
— |
|
|
|
2,541 |
|
Balance
at June 30, 2017 |
|
$ |
2,319,293 |
|
|
$ |
41,478 |
|
|
$ |
144,519 |
|
|
$ |
(611,312 |
) |
|
$ |
1,893,978 |
|
SECOND QUARTER 2018 EARNINGS CONFERENCE CALL AND
WEBCAST
Precision Drilling Corporation has scheduled a
conference call and webcast to begin promptly at 12:00 noon MT
(2:00 p.m. ET) on Thursday, July 26, 2018.
The conference call dial in numbers are
1-844-515-9176 or 614-999-9312.
A live webcast of the conference call will be
accessible on Precision’s website at www.precisiondrilling.com by
selecting “Investor Relations”, then “Webcasts &
Presentations”. Shortly after the live webcast, an archived version
will be available for approximately 60 days.
An archived recording of the conference call
will be available approximately one hour after the completion of
the call until July 31, 2018 by dialing 1-855-859-2056 or
404-537-3406, pass code 1184468.
About Precision
Precision is a leading provider of safe and High
Performance, High Value services to the oil and gas industry.
Precision provides customers with access to an extensive fleet of
contract drilling rigs, directional drilling services, well service
and snubbing rigs, camps, rental equipment, and water treatment
units backed by a comprehensive mix of technical support services
and skilled, experienced personnel.
Precision is headquartered in Calgary, Alberta,
Canada. Precision is listed on the Toronto Stock Exchange under the
trading symbol “PD” and on the New York Stock Exchange under the
trading symbol “PDS”.
For further information, please contact:
Carey Ford, Senior Vice President and Chief
Financial Officer713.435.6111
Ashley Connolly, Manager, Investor
Relations403.716.4725
800, 525 - 8th Avenue S.W.Calgary, Alberta,
Canada T2P 1G1Website: www.precisiondrilling.com
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