(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 first quarter financial
results:
- First quarter revenue of $401 million was an increase of 9%
over the prior year comparative quarter.
- First quarter net loss of $18 million ($0.06 per share)
compares to a net loss of $23 million ($0.08 per share) in the
first quarter of 2017.
- First quarter earnings before income taxes, finance charges,
foreign exchange, and depreciation and amortization (adjusted
EBITDA see “NON-GAAP MEASURES”) of $97 million was 16% higher than
the first quarter of 2017.
- Funds provided by operations (see “NON-GAAP MEASURES”) in the
first quarter of $104 million was an increase of 21% over the prior
year comparative quarter.
- First quarter capital expenditures were $30 million.
Precision’s President and CEO Kevin Neveu
stated: “Strengthening commodity prices and a continued focus on
drilling efficiency drove strong demand for our services in the
first quarter of 2018. This was most apparent in the U.S.
where our rig count reached its highest level since early-2015 and
where we have demonstrated three sequential quarters of improved
average dayrates. As a result, our first quarter financial
performance exceeded our expectations and we continue to gain
visibility on additional rig activations, rig re-deployments,
upgrade opportunities and strengthening average dayrates. Our
customers are clearly focused on improving their capital
efficiency by utilizing the most efficient and productive drilling
rig assets to reduce well costs.”
“We recently set our three strategic priorities
for 2018 focused on debt reduction, enhanced financial performance
and deploying our technology offerings on a wide scale commercial
basis. Most notably, we restated a debt reduction target of $300
million to $500 million over the next three to four years and would
expect to retire $75 million to $125 million of debt in the current
year. During the first quarter we demonstrated progress on all
three goals, with improved cash from operations leveraging our
stable fixed costs, accumulating cash on the balance sheet and
making continued progress with our technology initiatives.”
“In the U.S., Precision continued to add rigs
and improve cash flow as the quarter progressed, reaching 70 active
rigs near the end of the quarter, as anticipated. Year-to-date we
have signed 18 contracts in the U.S. with leading edge rates for
our Super Triple AC rigs reaching the mid-$20’s. We currently have
71 active rigs and I am pleased to say every rig that re-priced in
the quarter including both well-to-well and term contracts were at
higher rates, indicative of the tightness of supply in Tier 1 rigs.
In the current environment, we expect average dayrates will
continue to strengthen and anticipate further rig additions
throughout 2018 driven by the efficiency and performance of our
Super Triple rigs and supported by the current WTI
environment.”
“In Canada, Precision generated solid first
quarter free cash flow and remains well positioned with a large
fleet of Super Triple rigs for the Deep Basin, meaningful scale and
only maintenance capital required for active rigs. Overall activity
levels in the quarter were down modestly year-over-year with
customers winding down drilling programs in early March, while
activity in our core operating areas of the Deep Basin, Montney and
Duvernay remained stable when compared to 2017. Our current
visibility suggests activity levels should continue to trend
relatively in-line with 2017. While the WCSB is not experiencing
the strong demand we see in the U.S., rates for our rigs remain
stable and we expect strong free cash flow generation for the
balance of the year. At this point, Precision has no plans to
redeploy Canadian rigs to the U.S.; however, this remains an option
should better opportunities develop in the U.S.”
“Internationally, we have eight active rigs all
under term contract. We continue to bid our four idle rigs in the
Middle East and expect to hear results of recent new-build Middle
East tenders later this year where we are optimistic for
success.”
“I am pleased with Precision’s year-to-date
progress across our technology offerings. Specifically, in 2018 we
have drilled the same number of wells using our Directional
Guidance System (DGS) as we drilled in all of 2017. Over 75% of
these jobs used a reduced crew compared to only 30% in 2017. We
have 21 rigs currently running in the field with Process Automation
Control (PAC) and have drilled 137 wells with this technology in
2018 compared to 154 in all of 2017. Customer adoption is
rising, and we expect to be running an additional five to ten
systems by year end, continuing full scale deployment and
commercialization. Additionally, we are deploying revenue
generating Drilling Performance Applications (Apps) on several rigs
including customer and Precision written applications.”
“As a result of increased demand in our U.S.
operations, we are increasing our projected capital spending by $22
million. Approximately half of the incremental spend is allocated
to expansion and upgrades to our drilling fleet, with the remainder
related to maintenance expenditures. I would like to reiterate that
upgrade and expansion capital is backed by customer contracts with
paybacks that meet internal hurdles. Reducing debt remains a top
priority and we will only fund the most attractive investment
opportunities while maintaining debt repayment progress targets,”
concluded Mr. Neveu.
SELECT FINANCIAL AND OPERATING
INFORMATION
Adjusted EBITDA and funds provided by operations
are Non-GAAP measures. See “NON-GAAP MEASURES.”
Financial Highlights
|
|
Three months ended March 31, |
|
(Stated
in thousands of Canadian dollars, except per share amounts) |
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue(1) |
|
|
401,006 |
|
|
|
368,673 |
|
|
|
8.8 |
|
Adjusted EBITDA(2) |
|
|
97,469 |
|
|
|
84,308 |
|
|
|
15.6 |
|
Net loss |
|
|
(18,077 |
) |
|
|
(22,614 |
) |
|
|
(20.1 |
) |
Cash provided by
operations |
|
|
38,189 |
|
|
|
33,770 |
|
|
|
13.1 |
|
Funds provided by
operations(2) |
|
|
104,026 |
|
|
|
85,659 |
|
|
|
21.4 |
|
Capital spending: |
|
|
|
|
|
|
|
|
|
|
|
|
Expansion |
|
|
685 |
|
|
|
3,792 |
|
|
|
(81.9 |
) |
Upgrade |
|
|
11,363 |
|
|
|
13,647 |
|
|
|
(16.7 |
) |
Maintenance and infrastructure |
|
|
10,243 |
|
|
|
2,984 |
|
|
|
243.3 |
|
Intangibles |
|
|
7,791 |
|
|
|
1,669 |
|
|
|
366.8 |
|
Proceeds on sale |
|
|
(6,050 |
) |
|
|
(2,218 |
) |
|
|
172.8 |
|
Net capital
spending |
|
|
24,032 |
|
|
|
19,874 |
|
|
|
20.9 |
|
Net loss per
share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
(0.06 |
) |
|
|
(0.08 |
) |
|
|
(25.0 |
) |
Diluted |
|
|
(0.06 |
) |
|
|
(0.08 |
) |
|
|
(25.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 March 31, |
|
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Contract drilling rig
fleet |
|
|
256 |
|
|
|
255 |
|
|
|
0.4 |
|
Drilling rig
utilization days: |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
6,468 |
|
|
|
6,819 |
|
|
|
(5.1 |
) |
U.S. |
|
|
5,795 |
|
|
|
4,190 |
|
|
|
38.3 |
|
International |
|
|
720 |
|
|
|
720 |
|
|
|
- |
|
Revenue per utilization
day: |
|
|
|
|
|
|
|
|
|
|
|
|
Canada(1)(2) (Cdn$) |
|
|
22,209 |
|
|
|
21,405 |
|
|
|
3.8 |
|
U.S.(1)(3) (US$) |
|
|
20,603 |
|
|
|
20,555 |
|
|
|
0.2 |
|
International (US$) |
|
|
50,038 |
|
|
|
50,434 |
|
|
|
(0.8 |
) |
Operating cost per
utilization day: |
|
|
|
|
|
|
|
|
|
|
|
|
Canada
(Cdn$) |
|
|
13,331 |
|
|
|
12,828 |
|
|
|
3.9 |
|
U.S.
(US$) |
|
|
14,026 |
|
|
|
15,264 |
|
|
|
(8.1 |
) |
Service rig fleet |
|
|
210 |
|
|
|
210 |
|
|
|
- |
|
Service rig operating
hours |
|
|
52,701 |
|
|
|
52,057 |
|
|
|
1.2 |
|
Revenue
per operating hour (Cdn$) |
|
|
700 |
|
|
|
636 |
|
|
|
10.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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.(3) 2017 comparative includes revenue from
idle but contracted rig days.
Financial Position
(Stated in thousands of Canadian dollars, except ratios) |
|
March 31, 2018 |
|
|
December 31, 2017 |
|
Working capital(1) |
|
|
270,173 |
|
|
|
232,121 |
|
Cash |
|
|
81,873 |
|
|
|
65,081 |
|
Long-term debt(2) |
|
|
1,776,763 |
|
|
|
1,730,437 |
|
Total long-term
financial liabilities |
|
|
1,792,810 |
|
|
|
1,754,059 |
|
Total assets |
|
|
3,929,703 |
|
|
|
3,892,931 |
|
Long-term
debt to long-term debt plus equity ratio(2) |
|
|
0.50 |
|
|
|
0.49 |
|
|
|
|
|
|
|
|
|
|
(1) See “NON-GAAP MEASURES”.
(2) Net of unamortized debt issue costs.
Summary for the three months ended March 31,
2018:
- Revenue this quarter was $401 million which is 9% higher than
the first quarter of 2017. The increase in revenue is primarily the
result of higher activity in our U.S. contract drilling business.
Compared with the first quarter of 2017 our activity for the
quarter, as measured by drilling rig utilization days, increased
38% in the U.S. and decreased 5% in Canada and remained consistent
internationally. Revenue from our Contract Drilling Services and
Completion and Production Services segments both increased over the
comparative prior year period by 9% and 8%, respectively.
- Adjusted EBITDA this quarter of $97 million is an increase of
$13 million from the first quarter of 2017. Our adjusted EBITDA as
a percentage of revenue was 24% this quarter, compared with 23% in
the first quarter of 2017. The increase in adjusted EBITDA as a
percent of revenue was mainly due to higher average day rates in
Canada, fixed costs spread over higher activity in the U.S. and
lower average daily operating costs in the U.S. and International.
- Operating earnings (see “NON-GAAP MEASURES”) this quarter were
$10 million compared with an operating loss of $13 million in the
first quarter of 2017. Operating earnings 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 $29
million, $4 million higher than the first quarter of 2017. The
increase is due to higher share-based compensation expense tied to
our common shares partially offset by a strengthening of the
Canadian dollar on our U.S. dollar denominated costs. As at March
31, 2018 we have a total share-based incentive compensation
liability of $16 million compared with $22 million at December 31,
2017 with $13 million paid in the quarter.
- Net finance charges were $32 million, a decrease of $1 million
compared with the first quarter of 2017, primarily due to a
reduction in interest expense related to debt retired in 2017 and
the strengthening Canadian dollar impact on our U.S. dollar
denominated costs partially offset by lower interest income in the
current quarter.
- In Canada, average revenue per utilization day for contract
drilling rigs increased in the first quarter of 2018 to $22,209
from $21,405 in the prior year first quarter as higher spot market
day rates more than offset fewer rigs working under higher priced
legacy contracts. During the quarter, we recognized $10 million in
revenue associated with contract shortfall payments in Canada which
was an increase of $1 million from the prior year period. In the
U.S., revenue per utilization day increased in the first quarter of
2018 to US$20,603 from US$20,555 in the prior year first quarter.
The increase in the U.S. revenue rate was the result of higher spot
market day rates and higher turnkey revenue offset by rig mix,
lower mobilization revenue and lower revenue from idle but
contracted rigs. During the quarter, we had turnkey revenue of US$7
million compared with US$1 million in the 2017 comparative period
and no revenue from idle but contracted rigs in the current quarter
versus US$3 million in the comparative period. On a sequential
basis, revenue per utilization day excluding revenue from idle but
contracted rigs increased by US$566 due to higher fleet average day
rates and higher turnkey revenue when compared to the fourth
quarter of 2017.
- Average operating costs per utilization day for drilling rigs
in Canada increased to $13,331 compared with the prior year first
quarter of $12,828. The increase in average costs was due to larger
average crew formations and the timing of equipment certifications.
On a sequential basis, operating costs per day decreased by $213
compared to the fourth quarter of 2017 due to improved fixed cost
absorption. In the U.S., operating costs for the quarter on a per
day basis decreased to US$14,026 in 2018 compared with US$15,264 in
2017 due to lower lump sum move costs and fixed costs spread over a
greater number of utilization days partially offset by turnkey
work. On a sequential basis, operating costs per day increased by
US$379 compared to the fourth quarter of 2017 due to increased
turnkey work.
- We realized revenue from international contract drilling of
US$36 million in the first quarter of 2018, in-line with the prior
year period. Average revenue per utilization day in our
international contract drilling business was US$50,038 in-line with
the comparable prior year quarter.
- Directional drilling services realized revenue of $9 million in
the first quarter of 2018 compared with $13 million in the prior
year period.
- Funds provided by operations in the first quarter of 2018 were
$104 million, an increase of $18 million from the prior year
comparative quarter of $86 million. The increase was primarily the
result of improved operating results.
- Capital expenditures were $30 million in the first quarter, an
increase of $8 million over the same period in 2017. Capital
spending for the quarter included $12 million for upgrade and
expansion capital upgrade and expansion capital, $10 million for
the maintenance of existing assets and infrastructure spending and
$8 million for intangibles.
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 $104 million in funds from
operations (see “NON-GAAP MEASURES”) representing a 21% increase
over the prior year comparative period.
- Reinforce Precision’s High Performance competitive
advantage by deploying PAC, DGS and Apps on a wide scale
basis – year to date in 2018 we have drilled 57 wells
using our DGS which is the same number of wells as we drilled in
all of 2017. In addition, over 75% of these jobs used a reduced
crew compared to only 30% in 2017. We have 21 rigs currently
running in the field with PAC and have drilled 137 wells with this
technology in 2018 compared to 154 in all of 2017. Earlier
this year we also equipped our training rigs in Nisku and Houston
with PAC technology. Customer adoption is rising, and we expect to
be running an additional five to ten systems by year end,
continuing full scale deployment and commercialization.
Additionally, we are deploying revenue generating Apps on several
rigs including both customer and Precision written applications.
- Enhance financial performance through higher
utilization and improved operating margins – overall
utilization days are 11% higher than the prior year comparative
period while average operating margins (revenue less operating
costs) are up 24%, 17% and 4% in our U.S., international and Canada
contract drilling businesses respectively.
OUTLOOK
For the first quarter of 2018, the average West
Texas Intermediate price of oil was 21% higher than the prior year
comparative period while the average Henry Hub gas price was 7%
lower and the average AECO price was 22% lower.
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
|
Year ended December 31, |
|
|
|
2018 |
|
|
2017 |
|
|
2017 |
|
Average oil and
natural gas prices |
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
West
Texas Intermediate (per barrel) (US$) |
|
|
62.95 |
|
|
|
52.00 |
|
|
|
50.95 |
|
Natural
gas |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
AECO (per
MMBtu) (CDN$) |
|
|
2.05 |
|
|
|
2.63 |
|
|
|
2.16 |
|
United
States |
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub (per MMBtu) (US$) |
|
|
2.86 |
|
|
|
3.07 |
|
|
|
2.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
Year to date in 2018 we have entered into 19
term contracts. The following chart outlines the average number of
drilling rigs by quarter that we had under contract for 2017, the
first quarter of 2018 and the average number of drilling rigs by
quarter we have under contract for 2018 as of April 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 April 25,
2018: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
27 |
|
|
|
23 |
|
|
|
19 |
|
|
|
12 |
|
|
|
8 |
|
|
|
6 |
|
|
|
6 |
|
|
|
6 |
|
U.S. |
|
|
26 |
|
|
|
33 |
|
|
|
31 |
|
|
|
27 |
|
|
|
36 |
|
|
|
47 |
|
|
|
38 |
|
|
|
24 |
|
International |
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
7 |
|
|
|
6 |
|
Total |
|
|
61 |
|
|
|
64 |
|
|
|
58 |
|
|
|
47 |
|
|
|
52 |
|
|
|
61 |
|
|
|
51 |
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 April
25, 2018.
|
|
|
|
|
|
Average for the year ended |
|
|
|
2017 |
|
|
2018 |
|
Average rigs
under term contract as at April 25,
2018: |
|
|
|
|
|
|
|
|
Canada |
|
|
20 |
|
|
|
7 |
|
U.S. |
|
|
29 |
|
|
|
36 |
|
International |
|
|
8 |
|
|
|
7 |
|
Total |
|
|
57 |
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
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 |
|
Average Precision
active rig count: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
76 |
|
|
|
29 |
|
|
|
49 |
|
|
|
54 |
|
|
|
72 |
|
U.S. |
|
|
47 |
|
|
|
59 |
|
|
|
61 |
|
|
|
58 |
|
|
|
64 |
|
International |
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
Total |
|
|
131 |
|
|
|
96 |
|
|
|
118 |
|
|
|
120 |
|
|
|
144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
To start 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 April 20, 2018,
the U.S. active land drilling rig count was up approximately 19%
from the same point last year and the Canadian active land drilling
rig count was down approximately 8%. In North America, the trend
towards oil-directed drilling continues. To date in 2018,
approximately 64% 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.
Tier 1 Rig Demand
With improved commodity prices and increasing
activity levels, last year we were able to increase prices on spot
market rigs across most of our fleet. Should commodity prices
continue to improve, we expect sequential improvements in pricing
in the U.S. Our AC Super Triple rig dayrates have increased
substantially in the context of historical price movements and are
now pricing US$10,000 per day higher than the lows in 2016.
We expect day rate stability across Canada with
particular strength in the Deep Basin in Canada; however, leading
edge rates are not expected to be as high as those in the U.S.
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 $116 million and
includes $57 million for sustaining and infrastructure, $45 million
for upgrade and expansion and $14 million on intangibles. We expect
that the $116 million will be split $97 million in the Contract
Drilling Services segment, $5 million in the Completion and
Production Services segment and $14 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 March 31, |
|
(Stated
in thousands of Canadian dollars) |
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Drilling Services |
|
|
352,802 |
|
|
|
323,930 |
|
|
|
8.9 |
|
Completion and Production Services |
|
|
50,042 |
|
|
|
46,349 |
|
|
|
8.0 |
|
Inter-segment eliminations |
|
|
(1,838 |
) |
|
|
(1,606 |
) |
|
|
14.4 |
|
|
|
|
401,006 |
|
|
|
368,673 |
|
|
|
8.8 |
|
Adjusted
EBITDA:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Drilling Services |
|
|
110,966 |
|
|
|
93,665 |
|
|
|
18.5 |
|
Completion and Production Services |
|
|
4,644 |
|
|
|
4,587 |
|
|
|
1.2 |
|
Corporate and other |
|
|
(18,141 |
) |
|
|
(13,944 |
) |
|
|
30.1 |
|
|
|
|
97,469 |
|
|
|
84,308 |
|
|
|
15.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 March 31, |
|
(Stated
in thousands of Canadian dollars, except where noted) |
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue(1) |
|
|
352,802 |
|
|
|
323,930 |
|
|
|
8.9 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating(1) |
|
|
233,148 |
|
|
|
220,817 |
|
|
|
5.6 |
|
General and administrative |
|
|
8,688 |
|
|
|
9,448 |
|
|
|
(8.0 |
) |
Adjusted EBITDA(2) |
|
|
110,966 |
|
|
|
93,665 |
|
|
|
18.5 |
|
Depreciation |
|
|
77,700 |
|
|
|
86,189 |
|
|
|
(9.8 |
) |
Operating
earnings(2) |
|
|
33,266 |
|
|
|
7,476 |
|
|
|
345.0 |
|
Operating
earnings as a percentage of revenue |
|
|
9.4 |
% |
|
|
2.3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 March 31, |
|
Canadian
onshore drilling statistics:(1) |
|
2018 |
|
|
2017 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Number of
drilling rigs (end of period) |
|
|
136 |
|
|
|
620 |
|
|
|
135 |
|
|
|
641 |
|
Drilling
rig operating days (spud to release) |
|
|
5,654 |
|
|
|
22,845 |
|
|
|
6,041 |
|
|
|
23,323 |
|
Drilling
rig operating day utilization |
|
|
47 |
% |
|
|
41 |
% |
|
|
50 |
% |
|
|
41 |
% |
Number of
wells drilled |
|
|
515 |
|
|
|
2,203 |
|
|
|
564 |
|
|
|
2,284 |
|
Average
days per well |
|
|
11.0 |
|
|
|
10.4 |
|
|
|
10.7 |
|
|
|
10.2 |
|
Number of
metres drilled (000s) |
|
|
1,498 |
|
|
|
6,365 |
|
|
|
1,471 |
|
|
|
6,160 |
|
Average
metres per well |
|
|
2,908 |
|
|
|
2,889 |
|
|
|
2,608 |
|
|
|
2,697 |
|
Average metres per day |
|
|
265 |
|
|
|
279 |
|
|
|
243 |
|
|
|
264 |
|
(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 |
|
(1) United States lower 48
operations only.(2) Baker Hughes rig counts.
Revenue from Contract Drilling Services was $353
million this quarter, or 9% higher than the first quarter of 2017,
while adjusted EBITDA increased by 18% to $111 million. The
increase in revenue was primarily due to higher utilization days in
the U.S. During the quarter we recognized $10 million in shortfall
payments in our Canadian contract drilling business, which was $1
million higher than in the prior year. During the quarter in the
U.S. we recognized turnkey revenue of US$7 million compared with
US$1 million in the comparative period and we did not recognize any
idle but contracted revenue compared with US$3 million in the
comparative quarter of 2017.
Drilling rig utilization days in Canada
(drilling days plus move days) were 6,468 during the first quarter
of 2018, a decrease of 5% compared to 2017 primarily due to a
decrease in industry activity resulting from lower natural gas
prices. Drilling rig utilization days in the U.S. were 5,795, or
38% 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 720, in-line with the same quarter
of 2017.
Compared with the same quarter in 2017, drilling
rig revenue per utilization day was up 4% in Canada due to an
increase in spot market rates. Drilling rig revenue per utilization
day for the quarter in the U.S. was in-line with the prior year as
higher average day rates and higher turnkey revenue were 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 first quarter of 2017. In the U.S., 58% of utilization
days were generated from rigs under term contract as compared with
54% in the first quarter of 2017.
Operating costs were 66% of revenue for the
quarter which was 2 percentage points lower than the prior year
period. On a per utilization day basis, operating costs for the
drilling rig division in Canada were higher than the prior year
period primarily because of larger average crew sizes and higher
repairs and maintenance costs related to the timing of
certifications. In the U.S., operating costs for the quarter on a
per day basis were 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 10%
lower than in the first 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 March 31, |
|
(Stated
in thousands of Canadian dollars, except where noted) |
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue |
|
|
50,042 |
|
|
|
46,349 |
|
|
|
8.0 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
43,264 |
|
|
|
39,868 |
|
|
|
8.5 |
|
General and administrative |
|
|
2,134 |
|
|
|
1,894 |
|
|
|
12.7 |
|
Adjusted EBITDA(1) |
|
|
4,644 |
|
|
|
4,587 |
|
|
|
1.2 |
|
Depreciation |
|
|
6,875 |
|
|
|
7,403 |
|
|
|
(7.1 |
) |
Operating
loss(1) |
|
|
(2,231 |
) |
|
|
(2,816 |
) |
|
|
(20.8 |
) |
Operating
loss as a percentage of revenue |
|
|
(4.5 |
)% |
|
|
(6.1 |
)% |
|
|
|
|
Well servicing
statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
Number of
service rigs (end of period) |
|
|
210 |
|
|
|
210 |
|
|
|
- |
|
Service
rig operating hours |
|
|
52,701 |
|
|
|
52,057 |
|
|
|
1.2 |
|
Service
rig operating hour utilization |
|
|
28 |
% |
|
|
28 |
% |
|
|
- |
|
Service rig revenue per operating hour |
|
|
700 |
|
|
|
636 |
|
|
|
10.1 |
|
(1) See “NON-GAAP MEASURES”.
Revenue from Completion and Production Services
was up $4 million or 8% compared with the first quarter of 2017 due
to higher activity in our Canada well servicing and our camp and
catering businesses partially offset by lower activity in our
rental business where we sold certain U.S. assets. Our well
servicing activity in the quarter was up 1% from the first quarter
of 2017 while rates increased an average of 10%. Approximately 97%
of our first quarter Canadian service rig activity was oil
related.
During the quarter, Completion and Production
Services generated 94% of its revenue from Canadian operations and
6% from U.S. operations compared with the first quarter of 2017 of
91% from Canada and 9% from U.S. operations.
Average service rig revenue per operating hour
in the quarter was $700 or $64 higher than the first quarter of
2017. The increase was primarily the result of rig mix and higher
costs associated with increased northern work which were passed
through to the customer.
Adjusted EBITDA was in-line with the first
quarter of 2017 as increased revenue was the result of the recovery
of increased costs in our Canada well servicing business.
Operating costs as a percentage of revenue was
in-line with the prior year comparative quarter at 86%.
Depreciation in the quarter was $1 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 $18 million a $4 million
greater loss compared with the first quarter of 2017 primarily due
to higher share-based incentive compensation.
OTHER ITEMS
Net financial charges for the quarter were $32
million, a decrease of $1 million compared with the first quarter
of 2017 primarily because of a stronger Canadian dollar on our U.S.
dollar denominated interest expense and a reduction in interest
expense related to debt retired in 2017 partially offset by lower
interest income in the current period.
Income tax expense for the quarter was a
recovery of $5 million compared with a recovery of $23 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, revolving term credit facility with US$250
million(1) accordion feature) |
|
Undrawn,
except US$21 million in outstanding letters of credit |
|
General
corporate purposes |
|
November
21, 2021 |
Operating facilities (secured) |
|
|
|
|
|
|
$40
million |
|
Undrawn,
except $21 million in outstanding letters of credit |
|
Letters
of credit and general corporate purposes |
|
|
US$15
million |
|
Undrawn |
|
Short
term working capital requirements |
|
|
Demand letter of credit facility (secured) |
|
|
|
|
|
|
US$30
million |
|
Undrawn,
except US$13 million inoutstanding letters of credit |
|
Letters
of credit |
|
|
Senior notes (unsecured) |
|
|
|
|
|
|
US$249
million – 6.5% |
|
Fully
drawn |
|
Capital
expenditures and general corporate purposes |
|
December
15, 2021 |
US$350
million – 7.75% |
|
Fully
drawn |
|
Debt
redemption and repurchases |
|
December
15, 2023 |
US$400
million – 5.25% |
|
Fully
drawn |
|
Capital
expenditures and general corporate 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 March 31, 2018 we had $1,804 million outstanding under our
senior unsecured notes. The current blended cash interest cost of
our debt is approximately 6.6%
Covenants
Senior Facility
The senior credit facility requires that we
comply with certain covenants including a leverage ratio of
consolidated senior debt to 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. As at March 31, 2018 our consolidated senior debt to
Covenant EBITDA ratio was 0.08:1.
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 1.5:1 for the period ending March 31,
2018 and 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. As at March 31,
2018 our senior credit facility consolidated Covenant EBITDA to
consolidated interest expense ratio was 2.34:1.
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.
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. As at March 31, 2018, our senior notes
consolidated interest coverage ratio was 2.29:1.
The senior notes contain a restricted payments
covenant that limits our ability to make payments in the nature of
dividends, distributions and 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 cumulative net earnings and
decreases by 100% of 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 March 31, |
|
(Stated
in thousands) |
|
2018 |
|
|
2017 |
|
Weighted average shares
outstanding – basic |
|
|
293,239 |
|
|
|
293,239 |
|
Effect of
stock options and other equity compensation plans |
|
|
— |
|
|
|
— |
|
Weighted
average shares outstanding – diluted |
|
|
293,239 |
|
|
|
293,239 |
|
|
|
|
|
|
|
|
|
|
QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per share
amounts) |
|
2017 |
|
|
2018 |
|
Quarters
ended |
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
|
March 31 |
|
Revenue |
|
|
290,860 |
|
|
|
314,504 |
|
|
|
347,187 |
|
|
|
401,006 |
|
Adjusted EBITDA(1) |
|
|
56,520 |
|
|
|
73,239 |
|
|
|
90,914 |
|
|
|
97,469 |
|
Net loss |
|
|
(36,130 |
) |
|
|
(26,287 |
) |
|
|
(47,005 |
) |
|
|
(18,077 |
) |
Net loss per basic and
diluted share |
|
|
(0.12 |
) |
|
|
(0.09 |
) |
|
|
(0.16 |
) |
|
|
(0.06 |
) |
Funds provided by (used
in) operations(1) |
|
|
(15,187 |
) |
|
|
85,140 |
|
|
|
28,323 |
|
|
|
104,026 |
|
Cash
provided by operations |
|
|
2,739 |
|
|
|
56,757 |
|
|
|
23,289 |
|
|
|
38,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in thousands of Canadian dollars, except per share
amounts) |
|
2016 |
|
|
2017 |
|
Quarters
ended |
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
|
March 31 |
|
Revenue |
|
|
170,407 |
|
|
|
213,668 |
|
|
|
302,653 |
|
|
|
368,673 |
|
Adjusted EBITDA(1) |
|
|
22,400 |
|
|
|
41,411 |
|
|
|
65,000 |
|
|
|
84,308 |
|
Net loss |
|
|
(57,677 |
) |
|
|
(47,377 |
) |
|
|
(30,618 |
) |
|
|
(22,614 |
) |
Net loss per basic and
diluted share |
|
|
(0.20 |
) |
|
|
(0.16 |
) |
|
|
(0.10 |
) |
|
|
(0.08 |
) |
Funds provided by (used
in) operations(1) |
|
|
(31,372 |
) |
|
|
31,688 |
|
|
|
11,466 |
|
|
|
85,659 |
|
Cash
provided by (used in) operations |
|
|
20,665 |
|
|
|
17,515 |
|
|
|
(27,846 |
) |
|
|
33,770 |
|
(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 months ended March 31, 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, 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, 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) |
|
March 31,2018 |
|
|
December 31,2017 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
81,873 |
|
|
$ |
65,081 |
|
Accounts
receivable |
|
|
355,396 |
|
|
|
322,585 |
|
Income tax
recoverable |
|
|
28,854 |
|
|
|
29,449 |
|
Inventory |
|
|
26,787 |
|
|
|
24,631 |
|
Total current
assets |
|
|
492,910 |
|
|
|
441,746 |
|
Non-current
assets: |
|
|
|
|
|
|
|
|
Income tax
recoverable |
|
|
2,314 |
|
|
|
2,256 |
|
Deferred tax
assets |
|
|
41,962 |
|
|
|
41,822 |
|
Property, plant
and equipment |
|
|
3,151,344 |
|
|
|
3,173,824 |
|
Intangibles |
|
|
35,156 |
|
|
|
28,116 |
|
Goodwill |
|
|
206,017 |
|
|
|
205,167 |
|
Total
non-current assets |
|
|
3,436,793 |
|
|
|
3,451,185 |
|
Total
assets |
|
$ |
3,929,703 |
|
|
$ |
3,892,931 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
|
|
|
|
|
Current
liabilities: |
|
|
|
|
|
|
|
|
Accounts payable
and accrued liabilities |
|
$ |
222,737 |
|
|
$ |
209,625 |
|
Non-current
liabilities: |
|
|
|
|
|
|
|
|
Share based
compensation |
|
|
6,212 |
|
|
|
13,536 |
|
Provisions and
other |
|
|
9,835 |
|
|
|
10,086 |
|
Long-term
debt |
|
|
1,776,763 |
|
|
|
1,730,437 |
|
Deferred tax liability |
|
|
111,748 |
|
|
|
118,911 |
|
Total non-current
liabilities |
|
|
1,904,558 |
|
|
|
1,872,970 |
|
Shareholders’
equity: |
|
|
|
|
|
|
|
|
Shareholders’
capital |
|
|
2,319,293 |
|
|
|
2,319,293 |
|
Contributed
surplus |
|
|
45,907 |
|
|
|
44,037 |
|
Deficit |
|
|
(702,681 |
) |
|
|
(684,604 |
) |
Accumulated other comprehensive income |
|
|
139,889 |
|
|
|
131,610 |
|
Total
shareholders’ equity |
|
|
1,802,408 |
|
|
|
1,810,336 |
|
Total
liabilities and shareholders’ equity |
|
$ |
3,929,703 |
|
|
$ |
3,892,931 |
|
|
|
|
|
|
|
|
|
|
INTERIM CONSOLIDATED STATEMENTS OF LOSS
(UNAUDITED)
|
|
|
|
|
|
Three months ended March 31, |
|
(Stated
in thousands of Canadian dollars, except per share amounts) |
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
(recast) |
|
Revenue |
|
$ |
401,006 |
|
|
$ |
368,673 |
|
Expenses: |
|
|
|
|
|
|
|
|
Operating |
|
|
274,574 |
|
|
|
259,079 |
|
General and administrative |
|
|
28,963 |
|
|
|
25,286 |
|
Earnings before income
taxes, finance charges, foreign exchange and depreciation and
amortization |
|
|
97,469 |
|
|
|
84,308 |
|
Depreciation and amortization |
|
|
87,308 |
|
|
|
97,163 |
|
Operating earnings
(loss) |
|
|
10,161 |
|
|
|
(12,855 |
) |
Foreign exchange |
|
|
1,215 |
|
|
|
47 |
|
Finance
charges |
|
|
31,679 |
|
|
|
32,982 |
|
Loss before income
taxes |
|
|
(22,733 |
) |
|
|
(45,884 |
) |
Income taxes: |
|
|
|
|
|
|
|
|
Current |
|
|
1,566 |
|
|
|
890 |
|
Deferred |
|
|
(6,222 |
) |
|
|
(24,160 |
) |
|
|
|
(4,656 |
) |
|
|
(23,270 |
) |
Net
loss |
|
$ |
(18,077 |
) |
|
$ |
(22,614 |
) |
Net loss per
share: |
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.06 |
) |
|
$ |
(0.08 |
) |
Diluted |
|
$ |
(0.06 |
) |
|
$ |
(0.08 |
) |
|
|
|
|
|
|
|
|
|
INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(UNAUDITED)
|
|
|
|
|
|
Three months ended March 31, |
|
(Stated
in thousands of Canadian dollars) |
|
2018 |
|
|
2017 |
|
Net loss |
|
$ |
(18,077 |
) |
|
$ |
(22,614 |
) |
Unrealized gain (loss)
on translation of assets and liabilities of
operations denominated in foreign currency |
|
|
53,734 |
|
|
|
(18,554 |
) |
Foreign
exchange gain (loss) on net investment hedge with
U.S. denominated debt, net of tax |
|
|
(45,455 |
) |
|
|
15,124 |
|
Comprehensive loss |
|
$ |
(9,798 |
) |
|
$ |
(26,044 |
) |
|
|
|
|
|
|
|
|
|
INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW
(UNAUDITED)
|
|
Three months ended March 31, |
|
(Stated
in thousands of Canadian dollars) |
|
2018 |
|
|
2017 |
|
Cash provided by (used
in): |
|
|
|
|
|
|
|
|
Operations: |
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(18,077 |
) |
|
$ |
(22,614 |
) |
Adjustments
for: |
|
|
|
|
|
|
|
|
Long-term
compensation plans |
|
|
7,899 |
|
|
|
2,933 |
|
Depreciation and
amortization |
|
|
87,308 |
|
|
|
97,163 |
|
Foreign
exchange |
|
|
1,448 |
|
|
|
48 |
|
Finance
charges |
|
|
31,679 |
|
|
|
32,982 |
|
Income
taxes |
|
|
(4,656 |
) |
|
|
(23,270 |
) |
Other |
|
|
(916 |
) |
|
|
(170 |
) |
Income taxes
paid |
|
|
(324 |
) |
|
|
(1,050 |
) |
Income taxes
recovered |
|
|
36 |
|
|
|
332 |
|
Interest
paid |
|
|
(500 |
) |
|
|
(1,908 |
) |
Interest received |
|
|
129 |
|
|
|
1,213 |
|
Funds provided by
operations |
|
|
104,026 |
|
|
|
85,659 |
|
Changes
in non-cash working capital balances |
|
|
(65,837 |
) |
|
|
(51,889 |
) |
|
|
|
38,189 |
|
|
|
33,770 |
|
Investments: |
|
|
|
|
|
|
|
|
Purchase of
property, plant and equipment |
|
|
(22,291 |
) |
|
|
(20,423 |
) |
Purchase of
intangibles |
|
|
(7,791 |
) |
|
|
(1,669 |
) |
Proceeds on sale
of property, plant and equipment |
|
|
6,050 |
|
|
|
2,218 |
|
Changes
in non-cash working capital balances |
|
|
172 |
|
|
|
(8,391 |
) |
|
|
|
(23,860 |
) |
|
|
(28,265 |
) |
Financing: |
|
|
|
|
|
|
|
|
Debt issue costs |
|
|
— |
|
|
|
(341 |
) |
|
|
|
— |
|
|
|
(341 |
) |
Effect of
exchange rate changes on cash and cash equivalents |
|
|
2,463 |
|
|
|
(289 |
) |
Increase in cash and
cash equivalents |
|
|
16,792 |
|
|
|
4,875 |
|
Cash and
cash equivalents, beginning of period |
|
|
65,081 |
|
|
|
115,705 |
|
Cash and
cash equivalents, end of period |
|
$ |
81,873 |
|
|
$ |
120,580 |
|
|
|
|
|
|
|
|
|
|
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 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(18,077 |
) |
|
|
(18,077 |
) |
Other comprehensive
income for the period |
|
|
— |
|
|
|
— |
|
|
|
8,279 |
|
|
|
— |
|
|
|
8,279 |
|
Share
based compensation expense |
|
|
— |
|
|
|
1,870 |
|
|
|
— |
|
|
|
— |
|
|
|
1,870 |
|
Balance at March 31, 2018 |
|
$ |
2,319,293 |
|
|
$ |
45,907 |
|
|
$ |
139,889 |
|
|
$ |
(702,681 |
) |
|
$ |
1,802,408 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(22,614 |
) |
|
|
(22,614 |
) |
Other comprehensive
loss for the period |
|
|
— |
|
|
|
— |
|
|
|
(3,430 |
) |
|
|
— |
|
|
|
(3,430 |
) |
Share
based compensation expense |
|
|
— |
|
|
|
1,133 |
|
|
|
— |
|
|
|
— |
|
|
|
1,133 |
|
Balance
at March 31, 2017 |
|
$ |
2,319,293 |
|
|
$ |
40,070 |
|
|
$ |
153,026 |
|
|
$ |
(575,182 |
) |
|
$ |
1,937,207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FIRST 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, April 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 May 2, 2018 by dialing 1-855-859-2056 or
404-537-3406, pass code 3587299.
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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