(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 2017 fourth quarter and
year-end financial results and highlights:
- Fourth quarter revenue of $347 million was an increase of 15%
over the prior year comparative quarter.
- Fourth quarter net loss of $47 million ($0.16 per share)
compared with a net loss of $31 million ($0.10 per share) in the
fourth quarter of 2016. During the current quarter we
incurred an asset impairment charge for $15 million, related to our
Mexico contract drilling business, that after tax, increased our
net loss by $10 million and net loss per diluted share by
$0.03. In addition, because of changes in U.S. tax
regulations, we recorded a $16 million future tax expense ($0.05
per diluted share) in the quarter.
- Fourth quarter earnings before income taxes, loss on redemption
and repurchase of unsecured senior notes, finance charges, foreign
exchange, impairment of property, plant and equipment, gain on
re-measurement of property, plant and equipment and depreciation
and amortization, (adjusted EBITDA see “NON-GAAP MEASURES”) of $91
million was 40% higher than the fourth quarter of 2016.
- Full year revenue of $1,321 million was a 32% increase from
$1,003 million in 2016.
- Full year net loss of $132 million ($0.45 per share) compared
with a net loss of $156 million ($0.53 per share) in 2016.
- Full year adjusted EBITDA of $305 million was a 34% increase
from $228 million of adjusted EBITDA in 2016.
- Funds provided by operations (see “NON-GAAP MEASURES”) of $28
million in the fourth quarter and $184 for the full year
representing a 147% and 75% year-over-year increase,
respectively.
- During the fourth quarter we issued US$400 million of 7.125%
senior notes due 2026 and used the proceeds along with US$49
million of cash to repurchase all our outstanding US$372 million
2020 senior notes and US$70 million of our 2021 senior notes plus
redemption costs.
- Long-term debt net of cash as of December 31, 2017 was $1,665
million, a decrease of $126 million from December 31, 2016.
- Fourth quarter capital expenditures were $25 million, with full
year capital spending of $98 million.
- Exited 2017 with 63 active rigs in the U.S. representing a 62%
increase from where we entered the year.
Precision’s President and CEO Kevin Neveu
stated: “Precision’s strong financial performance in the fourth
quarter of 2017 is a result of our High Performance, High Value
strategy executed through Precision’s skilled crews,
high-efficiency Super Series drilling rigs, and our focus on cost
management. The strategic priorities we set for 2017 helped
direct our organization to gain market share, grow revenue and
margin, commercialize automation technologies, leverage fixed
costs, and generate cash to reduce debt.”
“As projected, Precision’s U.S. activity
recovered to peak 2017 levels during the fourth quarter with 63
active rigs by year end. Pricing momentum returned during the
fourth quarter with well-to-well and term contract renewals pricing
into higher day rates as customer demand for the most efficient
rigs remains strong. Precision’s Super Triple pad walking
rigs with long-reach horizontal capability are now pricing
US$10,000 per day higher than the lows in 2016. We have
signed 21 term contracts in the U.S. since the end of the third
quarter and have 65 rigs running today. With confirmed customer
contracts we expect our active rig count will move through 70 rigs
later this quarter.”
“In Canada, Precision remains well positioned in
the deep basins and heavy oil regions where our Super Triple and
Super Single fleets represent the rigs of choice for
high-efficiency drilling applications in each region. Rates
for these rigs have remained firm, and our continued efforts to
reduce cost with the benefit of our scale have underpinned our
financial results. While our current activity of 85 rigs is
slightly lower than expected, our deep basin and heavy oil activity
remains on track. We expect the spring break-up slowdown in
Canada will be customer spending driven rather than weather
related, and at this stage visibility for activity levels in the
second half of 2018 is limited. With relatively low exposure
to dry gas activity and leading market share in the most attractive
basins, we expect to leverage our scale and fleet investment to
generate strong free cash flow in 2018.”
“In Kuwait and Saudi Arabia our activity levels
are steady with eight rigs running today, and our operational
performance is excellent. We are actively bidding our four
idle rigs to opportunities in the Middle East region and plan to
grow our presence in the region only if financial returns
warrant. With recent Brent oil price strength, I would expect
more idle rig redeployment opportunities from what we have
experienced over the past few years.”
“Looking back at 2017, I am pleased with the
successes related to our strategic priorities. First, our High
Performance, High Value service offering delivered 99.6% and 99.0%
uptime in Canada and the U.S., respectively. Second, we
generated $184 million in funds provided by operations in 2017 with
$83 million in capital expenditures net of disposals and achieved a
16% reduction in general and administrative costs with a 64%
increase in North American activity levels when compared to
2016. We extended the maturity profile of our senior notes
and used US$49 million of cash to pay down long-term debt. Finally,
we progressed our technology initiatives utilizing our Super Series
rigs as the platform for technology deployment to the field.
We managed the field testing and confirmation of our rig automation
technologies throughout the year setting the stage for full
commercialization in 2018. We anticipate strong customer
adoption in process automation control (PAC) and directional
guidance system (DGS) technology in the coming twelve months.”
“For 2018, High Performance, High Value services
to safely help customers realize efficiency gains will continue to
be key for our field operations. Precision will further
enhance our Super Series fleet with PAC, walking systems, increased
pressure and hydraulic pumping capacity, and DGS offerings.
All growth and upgrade investments will be backed by customer
contracts with pricing that ensures attractive rates of return on
our investments. In 2017, we completed 29 rig upgrades at an
average of approximately $1.3 million per rig for pumping capacity
increases, PAC technology and walking systems. We currently
have 10-20 rig upgrades slated for 2018, all of which are under $3
million per rig and we expect to spend less than $34 million on
these upgrades. This approach will ensure we continue to
generate free cash flow and reduce our debt levels during the
year,” 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 December 31, |
|
|
Year ended December 31, |
|
(Stated
in thousands of Canadian dollars, except per share amounts) |
|
2017 |
|
|
2016 |
|
|
% Change |
|
|
2017 |
|
|
2016 |
|
|
% Change |
|
Revenue(1) |
|
|
347,187 |
|
|
|
302,653 |
|
|
|
14.7 |
|
|
|
1,321,224 |
|
|
|
1,003,233 |
|
|
|
31.7 |
|
Adjusted EBITDA(2) |
|
|
90,914 |
|
|
|
65,000 |
|
|
|
39.9 |
|
|
|
304,981 |
|
|
|
228,075 |
|
|
|
33.7 |
|
Adjusted EBITDA(2) % of
revenue |
|
|
26.2 |
% |
|
|
21.5 |
% |
|
|
|
|
|
|
23.1 |
% |
|
|
22.7 |
% |
|
|
|
|
Net loss |
|
|
(47,005 |
) |
|
|
(30,618 |
) |
|
|
53.5 |
|
|
|
(132,036 |
) |
|
|
(155,555 |
) |
|
|
(15.1 |
) |
Cash provided by (used
in) operations |
|
|
23,289 |
|
|
|
(27,846 |
) |
|
|
(183.6 |
) |
|
|
116,555 |
|
|
|
122,508 |
|
|
|
(4.9 |
) |
Funds provided by
operations(2) |
|
|
28,323 |
|
|
|
11,466 |
|
|
|
147.0 |
|
|
|
183,935 |
|
|
|
105,375 |
|
|
|
74.6 |
|
Capital spending: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expansion |
|
|
965 |
|
|
|
15,282 |
|
|
|
(93.7 |
) |
|
|
11,946 |
|
|
|
148,887 |
|
|
|
(92.0 |
) |
Upgrade |
|
|
2,984 |
|
|
|
13,527 |
|
|
|
(77.9 |
) |
|
|
37,086 |
|
|
|
19,862 |
|
|
|
86.7 |
|
Maintenance and infrastructure |
|
|
13,601 |
|
|
|
15,916 |
|
|
|
(14.5 |
) |
|
|
25,791 |
|
|
|
34,723 |
|
|
|
(25.7 |
) |
Intangibles |
|
|
7,405 |
|
|
|
- |
|
|
n/m |
|
|
|
23,179 |
|
|
|
- |
|
|
n/m |
|
Proceeds on sale |
|
|
(4,787 |
) |
|
|
(2,010 |
) |
|
|
138.2 |
|
|
|
(14,841 |
) |
|
|
(7,840 |
) |
|
|
89.3 |
|
Net capital
spending |
|
|
20,168 |
|
|
|
42,715 |
|
|
|
(52.8 |
) |
|
|
83,161 |
|
|
|
195,632 |
|
|
|
(57.5 |
) |
Loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
|
|
(0.16 |
) |
|
|
(0.10 |
) |
|
|
60.0 |
|
|
|
(0.45 |
) |
|
|
(0.53 |
) |
|
|
(15.1 |
) |
(1) Prior year comparatives
have changed to conform to current year presentation.
(2) See “NON-GAAP MEASURES”.n/m calculation
not meaningful.
Operating Highlights
|
|
Three Months Ended December 31, |
|
|
For the Year Ended December 31, |
|
|
|
2017 |
|
|
2016 |
|
|
% Change |
|
|
2017 |
|
|
2016 |
|
|
% Change |
|
Contract drilling rig
fleet |
|
|
256 |
|
|
|
255 |
|
|
|
0.4 |
|
|
|
256 |
|
|
|
255 |
|
|
|
0.4 |
|
Drilling rig
utilization days: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
4,938 |
|
|
|
4,672 |
|
|
|
5.7 |
|
|
|
18,883 |
|
|
|
12,722 |
|
|
|
48.4 |
|
U.S. |
|
|
5,365 |
|
|
|
3,570 |
|
|
|
50.3 |
|
|
|
20,479 |
|
|
|
11,343 |
|
|
|
80.5 |
|
International |
|
|
736 |
|
|
|
742 |
|
|
|
(0.8 |
) |
|
|
2,920 |
|
|
|
2,786 |
|
|
|
4.8 |
|
Revenue per utilization
day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada(1)(2) (Cdn$) |
|
|
23,457 |
|
|
|
23,298 |
|
|
|
0.7 |
|
|
|
21,143 |
|
|
|
24,509 |
|
|
|
(13.7 |
) |
U.S.(1)(3) (US$) |
|
|
20,226 |
|
|
|
21,292 |
|
|
|
(5.0 |
) |
|
|
19,861 |
|
|
|
26,145 |
|
|
|
(24.0 |
) |
International (US$) |
|
|
50,319 |
|
|
|
52,816 |
|
|
|
(4.7 |
) |
|
|
50,240 |
|
|
|
45,753 |
|
|
|
9.8 |
|
Operating cost per
utilization day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada(1)
(Cdn$) |
|
|
13,544 |
|
|
|
13,298 |
|
|
|
1.8 |
|
|
|
13,140 |
|
|
|
14,258 |
|
|
|
(7.8 |
) |
U.S.(1) (US$) |
|
|
13,647 |
|
|
|
14,349 |
|
|
|
(4.9 |
) |
|
|
13,846 |
|
|
|
15,547 |
|
|
|
(10.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service rig fleet |
|
|
210 |
|
|
|
207 |
|
|
|
1.4 |
|
|
|
210 |
|
|
|
207 |
|
|
|
1.4 |
|
Service rig operating
hours |
|
|
44,325 |
|
|
|
33,170 |
|
|
|
33.6 |
|
|
|
172,848 |
|
|
|
99,451 |
|
|
|
73.8 |
|
Revenue
per operating hour (Cdn$) |
|
|
644 |
|
|
|
629 |
|
|
|
2.4 |
|
|
|
637 |
|
|
|
646 |
|
|
|
(1.4 |
) |
(1) Prior year comparatives
have changed to conform to current year presentation.
(2) Includes lump sum revenue from contract
shortfall.(3) 2016 comparatives and periods ended
December 31, 2017 includes revenue from idle but contracted rig
days.
Financial Position
(Stated in thousands of Canadian dollars, except ratios) |
|
December 31,2017 |
|
|
December 31,2016 |
|
Working capital(1) |
|
|
232,121 |
|
|
|
230,874 |
|
Cash |
|
|
65,081 |
|
|
|
115,705 |
|
Long-term debt(2) |
|
|
1,730,437 |
|
|
|
1,906,934 |
|
Total long-term
financial liabilities |
|
|
1,754,059 |
|
|
|
1,946,742 |
|
Total assets |
|
|
3,892,931 |
|
|
|
4,324,214 |
|
Long-term
debt to long-term debt plus equity ratio(2) |
|
|
0.49 |
|
|
|
0.49 |
|
(1) See “NON-GAAP MEASURES”. (2) Net of unamortized
debt issue costs.
RECAST OF COMPARATIVE FINANCIAL INFORMATION
As discussed in our third quarter 2017 report we
changed our treatment of how certain amounts were historically
netted against operating expense. In addition, certain immaterial
reclassifications between operating and general and administrative
expenses have also been made in the comparative periods.
As a result of these reclassifications, we have
recast prior year’s comparative amounts as follows:
|
|
Three Months Ended December 31, 2016 |
|
|
For the Year Ended December 31, 2016 |
|
(Stated
in thousands of Canadian dollars) |
|
As previouslyreported |
|
|
Revenuerecast |
|
|
Expenserecast |
|
|
As recast |
|
|
As previouslyreported |
|
|
Revenuerecast |
|
|
Expenserecast |
|
|
As recast |
|
Revenue |
|
|
283,903 |
|
|
|
18,750 |
|
|
|
— |
|
|
|
302,653 |
|
|
|
951,411 |
|
|
|
51,822 |
|
|
|
— |
|
|
|
1,003,233 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
187,381 |
|
|
|
18,750 |
|
|
|
452 |
|
|
|
206,583 |
|
|
|
607,295 |
|
|
|
51,822 |
|
|
|
2,598 |
|
|
|
661,715 |
|
General
and administrative |
|
|
31,522 |
|
|
|
— |
|
|
|
(452 |
) |
|
|
31,070 |
|
|
|
110,287 |
|
|
|
— |
|
|
|
(2,598 |
) |
|
|
107,689 |
|
Restructuring |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
5,754 |
|
|
|
— |
|
|
|
— |
|
|
|
5,754 |
|
Adjusted
EBITDA(1) |
|
|
65,000 |
|
|
|
— |
|
|
|
— |
|
|
|
65,000 |
|
|
|
228,075 |
|
|
|
— |
|
|
|
— |
|
|
|
228,075 |
|
(1) See “NON-GAAP
MEASURES”.
Summary for the three months ended December 31,
2017
- Revenue this quarter was $347 million which is 15% higher than
the fourth quarter of 2016. The increase in revenue was
primarily the result of higher activity in our North American based
businesses partially offset by a decrease in average day rate in
our U.S. contract drilling business and no utilization in our
Mexico based contract drilling business. Compared with the
fourth quarter of 2016 our activity, as measured by drilling rig
utilization days, increased by 6% in Canada and 50% in the U.S. and
decreased by 1% internationally. Revenue from our Contract
Drilling Services and Completion and Production Services segments
both increased over the comparative prior year period by 13% and
32%, respectively.
- Adjusted EBITDA this quarter was $91 million, an increase of
$26 million from the fourth quarter of 2016. Our adjusted EBITDA as
a percentage of revenue was 26% this quarter, compared with 21% in
the fourth quarter of 2016. The increase in adjusted EBITDA as a
percent of revenue was mainly due to fixed costs spread over higher
activity in our North American businesses partially offset by lower
average pricing in our U.S. contract drilling business.
- Operating loss (see “NON-GAAP MEASURES”) this quarter was $19
million compared with an operating loss of $30 million in the
fourth quarter of 2016. Operating results this quarter were
positively impacted by increased activity in our North American
businesses, partially offset by lower average pricing in the U.S.
and a $15 million impairment charge to our property, plant and
equipment.
- General and administrative expenses this quarter were $22
million, $9 million lower than the fourth quarter of 2016.
The decrease is due to lower share-based compensation expense that
is tied to our common shares and the effect of a strengthening
Canadian dollar on our U.S. dollar denominated costs. As at
December 31, 2017 we have a total share-based incentive
compensation liability of $22 million compared with $24 million at
September 30, 2017 with no payments in the quarter.
- Under International Financial Reporting Standards, we are
required to assess the carrying value of assets in our cash
generating units (CGUs) containing goodwill annually and when
indicators of impairment exist. As a result of no activity in
2017, we completed an impairment test for our Mexico contract
drilling CGU as at December 31, 2017. The test involves
determining a value in use based on a multi-year discounted cash
flow using assumptions on expected future results. The
resulting value in use is then compared to the carrying value of
the CGU. As a result of this test it was determined that
property, plant and equipment in our Mexico contract drilling
business was impaired by US$12 million.
- Net finance charges were $38 million, a decrease of $4 million
compared with the fourth quarter of 2016 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 2016.
- During the quarter we redeemed US$442 million of our previously
outstanding senior notes incurring a loss on redemption of $9
million.
- In Canada, average revenue per utilization day for contract
drilling rigs increased in the fourth quarter of 2017 to $23,457
from $23,298 in the prior year fourth quarter as we had higher spot
market dayrates partially offset by fewer rigs working under legacy
contracts. During the quarter, we recognized $12.6 million in
revenue associated with contract shortfall payments in Canada which
was an increase of $1.3 million from the prior year period. Of the
$12.6 million in shortfall revenue recorded in the fourth quarter
of 2017, $3.4 million would have been earned within the quarter. On
a quarter-over-quarter basis, revenue per utilization day in Canada
increased by $3,477 as a result of higher shortfall payments and
higher boiler revenue when compared to the third quarter of 2017.
In the U.S., revenue per utilization day decreased in the fourth
quarter of 2017 to US$20,226 from US$21,292 in the prior year
fourth quarter. The decrease in the U.S. revenue rate was the
result of long-term contracts ending and rigs contracting at lower
spot market rates, lower revenue from idle but contracted rigs
partially offset by higher turnkey activity in the current quarter.
During the quarter, we had turnkey revenue of US$3 million compared
with no revenue in the 2016 comparative period and had US$1 million
in revenue from idle but contracted rigs in the current quarter
versus US$5 million in the comparative period. On a sequential
basis, revenue per utilization day excluding revenue from idle but
contracted rigs increased by US$1,012 due to higher fleet average
day rates and higher turnkey revenue when compared to the third
quarter of 2017.
- Average operating costs per utilization day for drilling rigs
in Canada increased to $13,544 compared with the prior year fourth
quarter of $13,298. The increase in average costs was due to timing
of equipment certifications. On a sequential basis, operating costs
per day decreased by $112 compared to the third 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$13,647 in 2017
compared with US$14,349 in 2016 due to fixed costs spread over
higher utilization, lower lump sum move costs partially offset by
turnkey work and higher repair costs for rig activations. On a
sequential basis, operating costs per day increased by US$1,056
compared to the third quarter of 2017 due to increased turnkey
work, higher repair costs for rig activations and higher lump sum
move costs.
- Average operating margin per utilization day excluding revenue
from idle but contracted rigs and shortfall revenue in the fourth
quarter of 2017 increased by $3,341 in Canada and was relatively
unchanged in the U.S. when compared to the third quarter of 2017.
In Canada, the increase was a result of higher fixed cost
absorption, higher boiler revenue and higher spot market day
rates.
- We realized revenue from international contract drilling of
US$37 million in the fourth quarter of 2017, a US$2 million
decrease over the prior year period. The decrease was due to
a reduction in activity in our Mexico operations and lump sum
demobilization revenue received in Mexico and early mobilization
payments in Kuwait in the fourth quarter of 2016 partially offset
by increased activity in Kuwait, as the two rigs we added in the
fourth quarter of 2016 were operational for the full year in 2017.
Average revenue per utilization day in our international contract
drilling business was US$50,319 a decrease of 5% over the
comparable prior year quarter primarily due to demobilization and
mobilization revenue received in the fourth quarter of 2016.
- Directional drilling services realized revenue of $4 million in
the fourth quarter of 2017 compared with $9 million in the prior
year period.
- Funds provided by operations in the fourth quarter of 2017 were
$28 million, an increase of $17 million from the prior year
comparative quarter. The increase was primarily the result of
improved operating results.
- Capital expenditures for the purchase of property, plant and
equipment were $25 million in the fourth quarter, a decrease of $20
million over the same period in 2016. Capital spending for
the quarter included $1 million for expansion capital, $3 million
for upgrade capital, $14 million for the maintenance of existing
assets and infrastructure and $7 million for
intangibles.
Summary for the year ended December 31,
2017:
- Revenue for 2017 was $1,321 million, an increase of 32% from
the 2016 period.
- Operating loss (see “NON-GAAP MEASURES”) was $88 million, a
decrease of $68 million over the same period in 2016. Operating
loss was 7% of revenue in 2017 compared to 16% of revenue in 2016.
Operating results this year were positively impacted by increased
activity in our North American businesses partially offset by lower
average pricing in our U.S. contract drilling division.
- General and administrative costs were $90 million, a decrease
of $18 million from 2016. The decrease was due to lower share-based
incentive compensation that is tied to the price of our common
shares, fixed cost reductions implemented through the downturn and
the effect of a strengthening Canadian dollar on our U.S. dollar
denominated costs.
- Net finance charges were $138 million, a decrease of $8 million
from 2016 primarily due to a reduction in interest expense related
to debt retired in 2016 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 2017
were $184 million, an increase of $79 million from the prior year
comparative period of $105 million.
- Capital expenditures for the purchase of property, plant and
equipment were $98 million in 2017, a decrease of $105 million over
the same period in 2016. Capital spending for 2017 included $12
million for expansion capital, $37 million for upgrade capital, $26
million for the maintenance of existing assets and infrastructure
and $23 million for intangibles.
STRATEGY
Precision’s strategic priorities for 2017 were as follows:
- Deliver High Performance, High Value service offering
in an improving demand environment while demonstrating fixed cost
leverage – In the U.S., our activity levels increased by
81% in 2017 versus 2016. In Canada, we began the year with 50
active rigs and reached a seasonal peak of 91 rigs. Year-over-year
in 2017 our utilization days were up 64% across our North American
drilling operations and was achieved without any material increase
in fixed costs. In 2017 we were able to reduce our annual general
and administrative costs by 16% and improve EBITDA margins. In
addition, we are upgrading our existing ERP system to increase
operating efficiencies, improve our fixed cost leverage and
position the organization to better handle the increased data flows
associated with our business.
- Commercialize rig automation and efficiency-driven
technologies across our Super Series fleet – Beta-style
field trials utilizing rig automation technologies, including
Process Automation Control (PAC), Directional Guidance System (DGS)
and High Speed Downhole Data are ongoing, and we expect to progress
the commercialization of these automation features during 2018. In
2017, we drilled 154 wells utilizing PAC technology which is
installed on 20 Super Triple Rigs. Year-to-date in 2018 we have
drilled an additional 50 wells utilizing PAC technology. In
addition, we have drilled a total of 173 wells including 57 wells
in 2017 and 25 wells year-to-date in 2018 utilizing DGS.
- Maintain strict financial discipline in pursuing growth
opportunities with a focus on free cash flow and
debt reduction – Effectively all upgrade capital spending
was supported by take-or-pay term contracts priced at a level that
allows for attractive rates of return. Precision reduced 2017
capital expenditures by approximately $40 million from planned
levels as a result of lower industry activity than expected with
the reduction relating primarily to upgrade and maintenance
capital. The reduction was consistent with our focus on free cash
flow to drive debt reduction. In 2017, we generated funds from
operations of $184 million (see “NON-GAAP MEASURES) while spending
$83 million on capital expenditures net of dispositions.
OUTLOOK
For the fourth quarter of 2017, the average West
Texas Intermediate price of oil was 13% higher than the prior year
comparative period while the average Henry Hub natural gas price
was 4% lower. The average AECO price was 44% lower than the prior
year comparative period because of infrastructure constraints
partially due to planned maintenance, and high storage levels.
|
|
Three months ended December 31, |
|
|
Year ended December 31, |
|
|
|
2017 |
|
|
2016 |
|
|
2017 |
|
2016 |
|
Average oil and
natural gas prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
West
Texas Intermediate (per barrel) (US$) |
|
|
55.45 |
|
|
|
49.21 |
|
|
50.95 |
|
|
43.30 |
|
Natural
gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO (per
MMBtu) (Cdn$) |
|
|
1.67 |
|
|
|
2.96 |
|
|
2.16 |
|
|
2.14 |
|
United
States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub (per MMBtu) (US$) |
|
|
2.86 |
|
|
|
2.99 |
|
|
2.98 |
|
|
2.48 |
|
Contracts
The following chart outlines the average number
of drilling rigs by quarter that we had under contract for 2017 and
the average number of drilling rigs by quarter we have under
contract for 2018 as at February 14, 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 February 14,
2018: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
27 |
|
|
|
23 |
|
|
|
19 |
|
|
|
12 |
|
|
|
8 |
|
|
|
6 |
|
|
|
6 |
|
|
|
6 |
|
U.S. |
|
|
26 |
|
|
|
33 |
|
|
|
31 |
|
|
|
27 |
|
|
|
34 |
|
|
|
34 |
|
|
|
24 |
|
|
|
13 |
|
International |
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
7 |
|
|
|
6 |
|
Total |
|
|
61 |
|
|
|
64 |
|
|
|
58 |
|
|
|
47 |
|
|
|
50 |
|
|
|
48 |
|
|
|
37 |
|
|
|
25 |
|
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 at
February 14, 2018.
|
|
Average for the year ended |
|
|
|
2017 |
|
|
2018 |
|
Average rigs
under term contract as at February 14,
2018: |
|
|
|
|
|
|
|
|
Canada |
|
|
20 |
|
|
|
7 |
|
U.S. |
|
|
29 |
|
|
|
26 |
|
International |
|
|
8 |
|
|
|
7 |
|
Total |
|
|
57 |
|
|
|
40 |
|
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. During 2017 we added 29 term contracts with
durations of six months or longer.
Drilling Activity
The following chart outlines the average number
of drilling rigs that we had working or moving by quarter for the
periods noted.
|
|
2016 |
|
|
2017 |
|
Quarter
ended |
|
December 31 |
|
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
Average Precision
active rig count: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
51 |
|
|
|
76 |
|
|
|
29 |
|
|
|
49 |
|
|
|
54 |
|
U.S. |
|
|
39 |
|
|
|
47 |
|
|
|
59 |
|
|
|
61 |
|
|
|
58 |
|
International |
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
Total |
|
|
98 |
|
|
|
131 |
|
|
|
96 |
|
|
|
118 |
|
|
|
120 |
|
To start 2018, drilling activity has increased
relative to this time last year in the U.S. and is largely flat in
Canada. According to industry sources, as of February 9,
2018, the U.S. active land drilling rig count was up approximately
33% from the same point last year and the Canadian active land
drilling rig count was down approximately 8%. In the U.S.,
the trend towards oil-directed drilling continues. To date in 2018,
approximately 66% of the Canadian industry’s active rigs and 80% of
the U.S. industry’s active rigs were drilling for oil targets,
compared with 55% for Canada and 79% 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. Day rates for our AC Super Triples have rebounded
fairly dramatically 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.
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 the importance of the rig delivering
these complex wells consistently and efficiently has been well
established by the industry. We expect that demand for
leading edge high efficiency Tier 1 rigs will continue to
strengthen, as the 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 the rigs will continue this technical evolution while
creating further cost efficiencies and performance value for
customers and further differentiating the specific capabilities of
the leading-edge Tier 1 rigs and those rig contractors capable of
widely deploying those technologies.
Capital Spending
Capital spending in 2018 is expected to be $94 million:
- The 2018 capital expenditure plan includes $45 million for
sustaining and infrastructure, $34 million to upgrade existing rigs
and $15 million on intangibles. We expect that the $94 million will
be split $74 million in the Contract Drilling Services segment, $5
million in the Completion and Production Services segment and $15
million in the Corporate segment.
SEGMENTED FINANCIAL RESULTS
Precision’s operations are reported in two
segments: the Contract Drilling Services segment, which includes
the drilling rig, directional drilling, oilfield supply and
manufacturing divisions; and the Completion and Production Services
segment, which includes the service rig, snubbing, rental, camp and
catering and water treatment divisions.
|
|
Three months ended December 31, |
|
|
Year ended December 31, |
|
(Stated
in thousands of Canadian dollars) |
|
2017 |
|
|
2016 |
|
|
% Change |
|
|
2017 |
|
|
2016 |
|
|
% Change |
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Drilling Services(1) |
|
|
308,973 |
|
|
|
273,669 |
|
|
|
12.9 |
|
|
|
1,173,930 |
|
|
|
907,821 |
|
|
|
29.3 |
|
Completion and Production Services |
|
|
40,600 |
|
|
|
30,706 |
|
|
|
32.2 |
|
|
|
154,146 |
|
|
|
100,049 |
|
|
|
54.1 |
|
Inter-segment eliminations |
|
|
(2,386 |
) |
|
|
(1,722 |
) |
|
|
38.6 |
|
|
|
(6,852 |
) |
|
|
(4,637 |
) |
|
|
47.8 |
|
|
|
|
347,187 |
|
|
|
302,653 |
|
|
|
14.7 |
|
|
|
1,321,224 |
|
|
|
1,003,233 |
|
|
|
31.7 |
|
Adjusted
EBITDA:(2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
Drilling Services |
|
|
100,280 |
|
|
|
86,351 |
|
|
|
16.1 |
|
|
|
342,970 |
|
|
|
296,651 |
|
|
|
15.6 |
|
Completion and Production Services |
|
|
2,714 |
|
|
|
390 |
|
|
|
595.9 |
|
|
|
11,888 |
|
|
|
(3,649 |
) |
|
|
(425.8 |
) |
Corporate and other |
|
|
(12,080 |
) |
|
|
(21,741 |
) |
|
|
(44.4 |
) |
|
|
(49,877 |
) |
|
|
(64,927 |
) |
|
|
(23.2 |
) |
|
|
|
90,914 |
|
|
|
65,000 |
|
|
|
39.9 |
|
|
|
304,981 |
|
|
|
228,075 |
|
|
|
33.7 |
|
(1) Prior year comparatives
have changed to conform to current year presentation.
(2) See “NON-GAAP MEASURES”.
SEGMENT REVIEW OF CONTRACT DRILLING
SERVICES
|
|
Three months ended December 31, |
|
|
Year ended December 31, |
|
(Stated
in thousands of Canadian dollars, except where noted) |
|
2017 |
|
|
2016 |
|
|
% Change |
|
|
2017 |
|
|
2016 |
|
|
% Change |
|
Revenue(1) |
|
|
308,973 |
|
|
|
273,669 |
|
|
|
12.9 |
|
|
|
1,173,930 |
|
|
|
907,821 |
|
|
|
29.3 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating(1) |
|
|
200,615 |
|
|
|
180,125 |
|
|
|
11.4 |
|
|
|
798,655 |
|
|
|
574,104 |
|
|
|
39.1 |
|
General
and administrative(1) |
|
|
8,078 |
|
|
|
7,193 |
|
|
|
12.3 |
|
|
|
32,305 |
|
|
|
34,026 |
|
|
|
(5.1 |
) |
Restructuring |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
3,040 |
|
|
|
(100.0 |
) |
Adjusted EBITDA(2) |
|
|
100,280 |
|
|
|
86,351 |
|
|
|
16.1 |
|
|
|
342,970 |
|
|
|
296,651 |
|
|
|
15.6 |
|
Depreciation |
|
|
82,680 |
|
|
|
90,671 |
|
|
|
(8.8 |
) |
|
|
334,587 |
|
|
|
348,005 |
|
|
|
(3.9 |
) |
Impairment of property, plant and equipment |
|
|
15,313 |
|
|
|
— |
|
|
n/m |
|
|
|
15,313 |
|
|
|
— |
|
|
n/m |
|
Operating
earnings (loss)(2) |
|
|
2,287 |
|
|
|
(4,320 |
) |
|
|
(152.9 |
) |
|
|
(6,930 |
) |
|
|
(51,354 |
) |
|
|
(86.5 |
) |
Operating
earnings (loss) as a percentage of revenue |
|
|
0.7 |
% |
|
|
(1.6 |
%) |
|
|
|
|
|
|
(0.6 |
%) |
|
|
(5.7 |
%) |
|
|
|
|
(1) Prior year comparatives
have changed to conform to current year
presentation.(2) See “NON-GAAP MEASURES”.n/m
calculation not meaningful.
|
|
Three Months Ended December 31, |
|
Canadian
onshore drilling statistics:(1) |
|
2017 |
|
|
2016 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Number of
drilling rigs (end of period) |
|
|
136 |
|
|
|
627 |
|
|
|
135 |
|
|
|
668 |
|
Drilling
rig operating days (spud to release) |
|
|
4,298 |
|
|
|
16,249 |
|
|
|
4,090 |
|
|
|
14,281 |
|
Drilling
rig operating day utilization |
|
|
35 |
% |
|
|
29 |
% |
|
|
33 |
% |
|
|
23 |
% |
Number of
wells drilled |
|
|
447 |
|
|
|
1,674 |
|
|
|
355 |
|
|
|
1,473 |
|
Average
days per well |
|
|
9.6 |
|
|
|
9.7 |
|
|
|
11.5 |
|
|
|
9.7 |
|
Number of
metres drilled (000s) |
|
|
1,245 |
|
|
|
4,780 |
|
|
|
932 |
|
|
|
4,023 |
|
Average
metres per well |
|
|
2,786 |
|
|
|
2,855 |
|
|
|
2,625 |
|
|
|
2,731 |
|
Average metres per day |
|
|
290 |
|
|
|
294 |
|
|
|
228 |
|
|
|
282 |
|
|
|
For the Year Ended December 31, |
|
Canadian
onshore drilling statistics:(1) |
|
2017 |
|
|
2016 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Number of
drilling rigs (end of period) |
|
|
136 |
|
|
|
627 |
|
|
|
135 |
|
|
|
668 |
|
Drilling
rig operating days (spud to release) |
|
|
16,696 |
|
|
|
66,138 |
|
|
|
11,273 |
|
|
|
42,391 |
|
Drilling
rig operating day utilization |
|
|
34 |
% |
|
|
29 |
% |
|
|
22 |
% |
|
|
17 |
% |
Number of
wells drilled |
|
|
1,729 |
|
|
|
6,959 |
|
|
|
962 |
|
|
|
3,963 |
|
Average
days per well |
|
|
9.7 |
|
|
|
9.5 |
|
|
|
11.7 |
|
|
|
10.7 |
|
Number of
metres drilled (000s) |
|
|
4,597 |
|
|
|
19,047 |
|
|
|
2,548 |
|
|
|
10,351 |
|
Average
metres per well |
|
|
2,659 |
|
|
|
2,737 |
|
|
|
2,649 |
|
|
|
2,612 |
|
Average metres per day |
|
|
275 |
|
|
|
288 |
|
|
|
226 |
|
|
|
244 |
|
(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) |
|
2017 |
|
|
2016 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Average number of
active land rigs for quarters ended: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31 |
|
|
47 |
|
|
|
722 |
|
|
|
32 |
|
|
|
516 |
|
June
30 |
|
|
59 |
|
|
|
874 |
|
|
|
24 |
|
|
|
397 |
|
September
30 |
|
|
61 |
|
|
|
927 |
|
|
|
29 |
|
|
|
465 |
|
December 31 |
|
|
58 |
|
|
|
902 |
|
|
|
39 |
|
|
|
567 |
|
Year to
date average |
|
|
56 |
|
|
|
856 |
|
|
|
31 |
|
|
|
486 |
|
(1) United States lower 48
operations only. (2) Baker Hughes rig counts.
Revenue from Contract Drilling Services was $309
million this quarter, or 13% higher than the fourth quarter of
2016, while adjusted EBITDA increased by 16% to $100 million.
The increase in revenue was primarily due to higher
utilization days in Canada and the U.S. During the quarter, we
recognized $12.6 million in revenue associated with contract
shortfall payments in Canada which was an increase of $1.3 million
from the prior year period. Of the $12.6 million in shortfall
revenue recorded in the fourth quarter of 2017, $3.4 million would
have been earned within the quarter. During the quarter in the U.S.
we recognized idle but contracted revenue of US$1 million compared
with US$5 million in the comparative period and current period
turnkey revenue of US$3 million with no revenue in the comparative
quarter of 2016.
Drilling rig utilization days in Canada
(drilling days plus move days) were 4,938 during the fourth quarter
of 2017, an increase of 6% compared to 2016 primarily due to the
increase in industry activity resulting from higher oil
prices. Drilling rig utilization days in the U.S. were 5,365,
or 50% higher than the same quarter of 2016 as U.S. activity was up
with higher industry activity. Drilling rig utilization days
in our international businesses were 736 or 1% lower than the same
quarter of 2016 due to no activity in Mexico in the fourth quarter
of 2017.
Compared with the same quarter in 2016, drilling
rig revenue per utilization day was up 1% in Canada due to higher
average spot market rates partially offset by fewer legacy
contracts. Drilling rig revenue per utilization day for the
quarter in the U.S. and international were each down 5% from the
prior comparative period. The decrease in the U.S. average
rate was due to long-term contracts ending and rigs being
re-contracted at lower spot market rates, lower idle but contracted
revenue partially offset by an increase in turnkey activity in the
current quarter and strengthening spot market rates. International
revenue per utilization day was down due to demobilization revenue
received in Mexico in the fourth quarter of 2016.
In Canada, 13% of our utilization days in the
quarter were generated from rigs under term contract, compared with
35% in the fourth quarter of 2016. In the U.S., 55% of
utilization days were generated from rigs under term contract as
compared with 56% in the fourth quarter of 2016.
Operating costs were 65% of revenue for the
quarter which was in line with 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 due to timing of equipment 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 fixed costs spread over
higher utilization and lower lump sum move cost partially offset by
turnkey work and higher repair costs for rig activations. Both
Canada and U.S. operating costs benefited from cost saving
initiatives taken in 2015 and 2016.
Depreciation expense in the quarter was 9% lower
than in the fourth quarter of 2016.
SEGMENT REVIEW OF COMPLETION AND PRODUCTION
SERVICES
|
|
Three months ended December 31, |
|
|
Year ended December 31, |
|
(Stated
in thousands of Canadian dollars, except where noted) |
|
2017 |
|
|
2016 |
|
|
% Change |
|
|
2017 |
|
|
2016 |
|
|
% Change |
|
Revenue |
|
|
40,600 |
|
|
|
30,706 |
|
|
|
32.2 |
|
|
|
154,146 |
|
|
|
100,049 |
|
|
|
54.1 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating(1) |
|
|
35,595 |
|
|
|
28,180 |
|
|
|
26.3 |
|
|
|
134,368 |
|
|
|
92,248 |
|
|
|
45.7 |
|
General
and administrative(1) |
|
|
2,291 |
|
|
|
2,136 |
|
|
|
7.3 |
|
|
|
7,890 |
|
|
|
9,429 |
|
|
|
(16.3 |
) |
Restructuring |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,021 |
|
|
|
— |
|
Adjusted EBITDA(2) |
|
|
2,714 |
|
|
|
390 |
|
|
|
595.9 |
|
|
|
11,888 |
|
|
|
(3,649 |
) |
|
|
(425.8 |
) |
Depreciation |
|
|
8,410 |
|
|
|
8,735 |
|
|
|
(3.7 |
) |
|
|
29,638 |
|
|
|
29,272 |
|
|
|
1.3 |
|
Gain on re-measurement of property, plant and equipment |
|
|
— |
|
|
|
(7,605 |
) |
|
|
— |
|
|
|
— |
|
|
|
(7,605 |
) |
|
|
— |
|
Operating
loss(2) |
|
|
(5,696 |
) |
|
|
(740 |
) |
|
|
669.7 |
|
|
|
(17,750 |
) |
|
|
(25,316 |
) |
|
|
(29.9 |
) |
Operating
loss as a percentage of revenue |
|
|
(14.0 |
%) |
|
|
(2.4 |
%) |
|
|
|
|
|
|
(11.5 |
%) |
|
|
(25.3 |
%) |
|
|
|
|
Well servicing
statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
service rigs (end of period) |
|
|
210 |
|
|
|
207 |
|
|
|
1.4 |
|
|
|
210 |
|
|
|
207 |
|
|
|
1.4 |
|
Service
rig operating hours |
|
|
44,325 |
|
|
|
33,170 |
|
|
|
33.6 |
|
|
|
172,848 |
|
|
|
99,451 |
|
|
|
73.8 |
|
Service
rig operating hour utilization |
|
|
23 |
% |
|
|
21 |
% |
|
|
|
|
|
|
23 |
% |
|
|
17 |
% |
|
|
|
|
Service rig revenue per operating hour |
|
|
644 |
|
|
|
629 |
|
|
|
2.4 |
|
|
|
637 |
|
|
|
646 |
|
|
|
(1.4 |
) |
(1) Certain expenses in the prior year comparative have been
reclassified to conform to current year presentation.(2) See
“NON-GAAP MEASURES”.
Revenue from Completion and Production Services
was up $10 million or 32% compared with the fourth quarter of 2016
due to higher activity levels. As oil prices have recovered,
customers have increased spending and activity in well completion
and production programs. Our well servicing activity in the
quarter was up 34% from the fourth quarter of 2016 as a result of
improved industry activity levels and a larger fleet following the
acquisition of service rigs late in the fourth quarter of
2016. Approximately 96% of our fourth quarter Canadian
service rig activity was oil related.
During the quarter, Completion and Production
Services generated 92% of its revenue from Canadian operations and
8% from U.S. operations compared with the fourth quarter of 2016 of
88% from Canada and 12% from U.S. operations.
Average service rig revenue per operating hour
in the quarter was $644 or $15 higher than the fourth quarter of
2016. The increase was primarily the result of increased
labour costs which were passed through to the customer.
Adjusted EBITDA was $2 million higher than the
fourth quarter of 2016 due to increased activity in the
segment.
Operating costs as a percentage of revenue
decreased to 88% in the fourth quarter of 2017, from 92% in the
fourth quarter of 2016. The decrease is the result of the
impact of fixed costs spread across greater activity combined with
our reduced cost structure.
While we were successful in 2017 in reducing our
fixed costs, margins in our Completion and Production Services have
been challenged primarily due to intense pricing pressure, repair
and maintenance as well as labor costs associated with service rig
reactivations.
Depreciation in the quarter was $8 million in
line with the previous year comparative period.
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 $12 million a decrease of
$10 million compared with the fourth quarter of 2016 primarily due
to lower share-based incentive compensation.
OTHER ITEMS
Net financial charges for the quarter were $38
million, a decrease of $4 million compared with the fourth quarter
of 2016 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 2016.
During the quarter, we redeemed and repurchased
US$442 million of our previously outstanding senior notes incurring
a loss of $9 million. For the quarter, we incurred a foreign
exchange gain of $2 million in line with the fourth quarter of
2016.
Income tax expense for the quarter was a
recovery of $17 million compared with a recovery of $51 million in
the same quarter in 2016. The recoveries are due to negative pretax
earnings in the fourth quarter of 2017 offset by a $16 million
charge to future tax expense as a result of tax changes implemented
in the U.S.
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 apply a disciplined approach to managing and
tracking results of our operations to keep costs down. We maintain
a variable 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$21 million inoutstanding letters of credit |
|
General corporate purposes |
|
November 21, 2021 |
Operating facilities (secured) |
|
|
|
|
|
|
$40 million |
|
Undrawn,
except $21 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 |
|
|
Senior notes (unsecured) |
|
|
|
|
|
|
US$249 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$400 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.
On November 21, 2017 we agreed with our lending
group to the following amendments to our senior credit
facility:
- Reduce the Covenant EBITDA (see “NON-GAAP MEASURES”), as
defined in the credit agreement, to interest expense coverage ratio
to greater than 2.0:1 for the periods ending June 30, September 30,
and December 31, 2018 and March 31, 2019 reverting to 2.5:1
thereafter;
- Reduced the size of the facility to US$500 million;
- Extend the maturity date of the facility to November 21, 2021
subject to certain spring forward provisions if junior debt is not
refinanced in a timely manner;
- Amend certain negative covenants, to among other things, permit
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., and;
- Amend the negative covenant with respect to distributions to
permit distributions after March 31, 2019 subject to a pro forma
consolidated senior net leverage covenant ratio of less than or
equal to 1.75:1.
On November 22, 2017 we issued
US$400 million of 7.125% senior notes due in 2026 in a private
offering. The Notes are guaranteed on a senior unsecured basis by
current and future U.S. and Canadian subsidiaries that also
guarantee our Senior Credit Facility and certain other
indebtedness. The Notes were issued to redeem and repurchase
existing debt.
On November 22, 2017 we repurchased, pursuant to
an early tender offer, US$310 million of our 6.625% unsecured
senior notes due 2020 and US$70 million of our 6.5% unsecured
senior notes due 2021 for combined US$387 million plus accrued and
unpaid interest incurring a loss on the repurchase of US$6
million.
On December 7, 2017 we redeemed our
remaining outstanding 6.625% unsecured senior notes due 2020 for
US$62 million plus accrued and unpaid interest incurring a
loss on redemption of US$1 million.
As at December 31, 2017 we had $1,759 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 December 31, 2017 our consolidated senior debt
to Covenant EBITDA ratio was negative 0.12:1.
Effective November 21, 2017, 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 periods ending December 31, 2017 and 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 December 31, 2017 our
senior credit facility consolidated Covenant EBITDA to consolidated
interest expense ratio was 2.22:1.
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 ratio test 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 test 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.
At December 31, 2017, we were in compliance with
the covenants of the senior credit facility.
Senior Notes
The senior notes require that we comply with
financial covenants including an incurrence based consolidated
interest coverage ratio test of consolidated cashflow, 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 December 31, 2017, our senior notes
consolidated interest coverage ratio was 2.16:1.
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 because 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 endedDecember 31, |
|
|
Year ended December 31, |
|
(Stated
in thousands) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
Weighted average shares
outstanding – basic |
|
|
293,239 |
|
|
|
293,239 |
|
|
|
293,239 |
|
|
|
293,133 |
|
Effect of
stock options and other equity compensation plans |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Weighted
average shares outstanding – diluted |
|
|
293,239 |
|
|
|
293,239 |
|
|
|
293,239 |
|
|
|
293,133 |
|
QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per share
amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
Quarters
ended |
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
Revenue(1) |
|
|
368,673 |
|
|
|
290,860 |
|
|
|
314,504 |
|
|
|
347,187 |
|
Adjusted EBITDA(2) |
|
|
84,308 |
|
|
|
56,520 |
|
|
|
73,239 |
|
|
|
90,914 |
|
Net loss: |
|
|
(22,614 |
) |
|
|
(36,130 |
) |
|
|
(26,287 |
) |
|
|
(47,005 |
) |
Per basic
and diluted share |
|
|
(0.08 |
) |
|
|
(0.12 |
) |
|
|
(0.09 |
) |
|
|
(0.16 |
) |
Funds provided by (used
in) operations(2) |
|
|
85,659 |
|
|
|
(15,187 |
) |
|
|
85,140 |
|
|
|
28,323 |
|
Cash
provided by operations |
|
|
33,770 |
|
|
|
2,739 |
|
|
|
56,757 |
|
|
|
23,289 |
|
(Stated in thousands of Canadian dollars, except per share
amounts) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 |
|
Quarters
ended |
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
|
December 31 |
|
Revenue(1) |
|
|
316,505 |
|
|
|
170,407 |
|
|
|
213,668 |
|
|
|
302,653 |
|
Adjusted EBITDA(2) |
|
|
99,264 |
|
|
|
22,400 |
|
|
|
41,411 |
|
|
|
65,000 |
|
Net loss: |
|
|
(19,883 |
) |
|
|
(57,677 |
) |
|
|
(47,377 |
) |
|
|
(30,618 |
) |
Per basic
and diluted share |
|
|
(0.07 |
) |
|
|
(0.20 |
) |
|
|
(0.16 |
) |
|
|
(0.10 |
) |
Funds provided by (used
in) operations(2) |
|
|
93,593 |
|
|
|
(31,372 |
) |
|
|
31,688 |
|
|
|
11,466 |
|
Cash
provided by operations |
|
|
112,174 |
|
|
|
20,665 |
|
|
|
17,515 |
|
|
|
(27,846 |
) |
(1) Prior period comparatives have changed to conform to current
year presentation. (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 2016 Annual Report and there have been no material
changes to our critical accounting judgments and estimates during
the three months and the year ended December 31, 2017.
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, loss on repurchase of unsecured senior notes,
financing charges, foreign exchange, impairment of property, plant
and equipment, gain on re-measurement of property, plant and
equipment 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 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 and our scheduled ERP
upgrade;
- anticipated activity levels in 2018;
- anticipated demand for Tier 1 rigs; and
- the average number of term contracts in place for 2018 and
2019.
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 and natural gas 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;
- change in tax legislation; 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, 2016, 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 results 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) |
|
December 31,2017 |
|
|
December 31,2016 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
65,081 |
|
|
$ |
115,705 |
|
Accounts
receivable |
|
|
322,585 |
|
|
|
293,682 |
|
Income
tax recoverable |
|
|
29,449 |
|
|
|
38,087 |
|
Inventory |
|
|
24,631 |
|
|
|
24,136 |
|
Total current
assets |
|
|
441,746 |
|
|
|
471,610 |
|
Non-current
assets: |
|
|
|
|
|
|
|
|
Income
tax recoverable |
|
|
2,256 |
|
|
|
— |
|
Deferred
tax assets |
|
|
41,822 |
|
|
|
— |
|
Property,
plant and equipment |
|
|
3,173,824 |
|
|
|
3,641,889 |
|
Intangibles |
|
|
28,116 |
|
|
|
3,316 |
|
Goodwill |
|
|
205,167 |
|
|
|
207,399 |
|
Total
non-current assets |
|
|
3,451,185 |
|
|
|
3,852,604 |
|
Total
assets |
|
$ |
3,892,931 |
|
|
$ |
4,324,214 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
EQUITY |
|
|
|
|
|
|
|
|
Current
liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
209,625 |
|
|
$ |
240,736 |
|
Total current
liabilities |
|
|
209,625 |
|
|
|
240,736 |
|
Non-current
liabilities: |
|
|
|
|
|
|
|
|
Share
based compensation |
|
|
13,536 |
|
|
|
27,387 |
|
Provisions and other |
|
|
10,086 |
|
|
|
12,421 |
|
Long-term
debt |
|
|
1,730,437 |
|
|
|
1,906,934 |
|
Deferred tax liabilities |
|
|
118,911 |
|
|
|
174,618 |
|
Total non-current
liabilities |
|
|
1,872,970 |
|
|
|
2,121,360 |
|
Shareholders’
equity: |
|
|
|
|
|
|
|
|
Shareholders’ capital |
|
|
2,319,293 |
|
|
|
2,319,293 |
|
Contributed surplus |
|
|
44,037 |
|
|
|
38,937 |
|
Deficit |
|
|
(684,604 |
) |
|
|
(552,568 |
) |
Accumulated other comprehensive income |
|
|
131,610 |
|
|
|
156,456 |
|
Total
shareholders’ equity |
|
|
1,810,336 |
|
|
|
1,962,118 |
|
Total
liabilities and shareholders’ equity |
|
$ |
3,892,931 |
|
|
$ |
4,324,214 |
|
INTERIM CONSOLIDATED STATEMENTS OF LOSS
(UNAUDITED)
|
|
Three Months Ended December 31, |
|
|
Years Ended December 31, |
|
(Stated
in thousands of Canadian dollars, except pershare
amounts) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
|
|
|
|
|
|
(recast) |
|
|
|
|
|
|
(recast) |
|
Revenue |
|
$ |
347,187 |
|
|
$ |
302,653 |
|
|
$ |
1,321,224 |
|
|
$ |
1,003,233 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
233,824 |
|
|
|
206,583 |
|
|
|
926,171 |
|
|
|
661,715 |
|
General
and administrative |
|
|
22,449 |
|
|
|
31,070 |
|
|
|
90,072 |
|
|
|
107,689 |
|
Restructuring |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
5,754 |
|
Earnings before income
taxes, loss on redemption and repurchase of unsecured senior
notes, finance charges, foreign exchange, gain on
re-measurement of property, plant and equipment, impairment
of property, plant and equipment and depreciation and
amortization |
|
|
90,914 |
|
|
|
65,000 |
|
|
|
304,981 |
|
|
|
228,075 |
|
Depreciation and
amortization |
|
|
94,229 |
|
|
|
102,801 |
|
|
|
377,746 |
|
|
|
391,659 |
|
Impairment of property,
plant and equipment |
|
|
15,313 |
|
|
|
— |
|
|
|
15,313 |
|
|
|
— |
|
Gain on
re-measurement of property, plant and equipment |
|
|
— |
|
|
|
(7,605 |
) |
|
|
— |
|
|
|
(7,605 |
) |
Operating loss |
|
|
(18,628 |
) |
|
|
(30,196 |
) |
|
|
(88,078 |
) |
|
|
(155,979 |
) |
Foreign exchange |
|
|
(1,534 |
) |
|
|
(925 |
) |
|
|
(2,970 |
) |
|
|
6,008 |
|
Finance charges |
|
|
38,196 |
|
|
|
42,289 |
|
|
|
137,928 |
|
|
|
146,360 |
|
Loss on
redemption and repurchase of unsecured senior notes |
|
|
9,021 |
|
|
|
10,220 |
|
|
|
9,021 |
|
|
|
239 |
|
Loss before income
taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes: |
|
|
(64,311 |
) |
|
|
(81,780 |
) |
|
|
(232,057 |
) |
|
|
(308,586 |
) |
Current |
|
|
(1,670 |
) |
|
|
(6,837 |
) |
|
|
(1,331 |
) |
|
|
(31,195 |
) |
Deferred |
|
|
(15,636 |
) |
|
|
(44,325 |
) |
|
|
(98,690 |
) |
|
|
(121,836 |
) |
|
|
|
(17,306 |
) |
|
|
(51,162 |
) |
|
|
(100,021 |
) |
|
|
(153,031 |
) |
Net
loss |
|
$ |
(47,005 |
) |
|
$ |
(30,618 |
) |
|
$ |
(132,036 |
) |
|
$ |
(155,555 |
) |
Net loss per
share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(0.16 |
) |
|
$ |
(0.10 |
) |
|
$ |
(0.45 |
) |
|
$ |
(0.53 |
) |
Diluted |
|
$ |
(0.16 |
) |
|
$ |
(0.10 |
) |
|
$ |
(0.45 |
) |
|
$ |
(0.53 |
) |
INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(UNAUDITED)
|
|
Three Months Ended December 31, |
|
|
Years Ended December 31, |
|
(Stated
in thousands of Canadian dollars) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
Net loss |
|
$ |
(47,005 |
) |
|
$ |
(30,618 |
) |
|
$ |
(132,036 |
) |
|
$ |
(155,555 |
) |
Unrealized gain (loss)
on translation of assets and liabilities of operations
denominated in foreign currency |
|
|
9,146 |
|
|
|
53,488 |
|
|
|
(146,545 |
) |
|
|
(76,608 |
) |
Foreign
exchange gain (loss) on net investment hedge with U.S.
denominated debt, net of tax |
|
|
(10,383 |
) |
|
|
(37,570 |
) |
|
|
121,699 |
|
|
|
66,963 |
|
Comprehensive loss |
|
$ |
(48,242 |
) |
|
$ |
(14,700 |
) |
|
$ |
(156,882 |
) |
|
$ |
(165,200 |
) |
INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW
(UNAUDITED)
|
|
Three Months Ended December 31, |
|
|
Years Ended December 31, |
|
(Stated
in thousands of Canadian dollars) |
|
2017 |
|
|
2016 |
|
|
2017 |
|
|
2016 |
|
Cash provided by (used
in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
loss |
|
$ |
(47,005 |
) |
|
$ |
(30,618 |
) |
|
$ |
(132,036 |
) |
|
$ |
(155,555 |
) |
Adjustments for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
compensation plans |
|
|
2,519 |
|
|
|
12,241 |
|
|
|
6,795 |
|
|
|
28,313 |
|
Depreciation and amortization |
|
|
94,229 |
|
|
|
102,801 |
|
|
|
377,746 |
|
|
|
391,659 |
|
Impairment of property, plant and equipment |
|
|
15,313 |
|
|
|
— |
|
|
|
15,313 |
|
|
|
— |
|
Gain on
re-measurement of property, plant and equipment |
|
|
— |
|
|
|
(7,605 |
) |
|
|
— |
|
|
|
(7,605 |
) |
Loss on
redemption and repurchase of unsecured senior notes |
|
|
9,021 |
|
|
|
10,220 |
|
|
|
9,021 |
|
|
|
239 |
|
Foreign
exchange |
|
|
(1,280 |
) |
|
|
(2,183 |
) |
|
|
(2,873 |
) |
|
|
6,791 |
|
Finance
charges |
|
|
38,196 |
|
|
|
42,289 |
|
|
|
137,928 |
|
|
|
146,360 |
|
Income
taxes |
|
|
(17,306 |
) |
|
|
(51,162 |
) |
|
|
(100,021 |
) |
|
|
(153,031 |
) |
Other |
|
|
(1,320 |
) |
|
|
(2,454 |
) |
|
|
(2,025 |
) |
|
|
(1,889 |
) |
Income
taxes paid |
|
|
(345 |
) |
|
|
(1,518 |
) |
|
|
(3,645 |
) |
|
|
(14,605 |
) |
Income
taxes recovered |
|
|
- |
|
|
|
192 |
|
|
|
11,932 |
|
|
|
795 |
|
Interest
paid |
|
|
(63,929 |
) |
|
|
(61,381 |
) |
|
|
(136,065 |
) |
|
|
(139,575 |
) |
Interest received |
|
|
230 |
|
|
|
644 |
|
|
|
1,865 |
|
|
|
3,478 |
|
Funds provided by
operations |
|
|
28,323 |
|
|
|
11,466 |
|
|
|
183,935 |
|
|
|
105,375 |
|
Changes
in non-cash working capital balances |
|
|
(5,034 |
) |
|
|
(39,312 |
) |
|
|
(67,380 |
) |
|
|
17,133 |
|
|
|
|
23,289 |
|
|
|
(27,846 |
) |
|
|
116,555 |
|
|
|
122,508 |
|
Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase
of property, plant and equipment |
|
|
(17,550 |
) |
|
|
(44,725 |
) |
|
|
(74,823 |
) |
|
|
(203,472 |
) |
Purchase
of intangibles |
|
|
(7,405 |
) |
|
|
— |
|
|
|
(23,179 |
) |
|
|
— |
|
Proceeds
on sale of property, plant and equipment |
|
|
4,787 |
|
|
|
2,010 |
|
|
|
14,841 |
|
|
|
7,840 |
|
Business
acquisition, net of cash acquired |
|
|
— |
|
|
|
(12,200 |
) |
|
|
— |
|
|
|
(12,200 |
) |
Income
taxes recovered |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,917 |
|
Changes in non-cash working capital balances |
|
|
2,727 |
|
|
|
880 |
|
|
|
(7,989 |
) |
|
|
(9,010 |
) |
|
|
|
(17,441 |
) |
|
|
(54,035 |
) |
|
|
(91,150 |
) |
|
|
(213,925 |
) |
Financing: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemption and repurchase of unsecured senior notes |
|
|
(571,975 |
) |
|
|
(613,379 |
) |
|
|
(571,975 |
) |
|
|
(677,704 |
) |
Debt
issue costs |
|
|
(9,196 |
) |
|
|
(10,752 |
) |
|
|
(9,196 |
) |
|
|
(10,752 |
) |
Debt
amendment fees |
|
|
(1,452 |
) |
|
|
— |
|
|
|
(1,793 |
) |
|
|
(1,214 |
) |
Increase
in long-term debt |
|
|
509,180 |
|
|
|
469,420 |
|
|
|
509,180 |
|
|
|
469,420 |
|
Issuance of common shares on the exercise of options |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,926 |
|
|
|
|
(73,443 |
) |
|
|
(154,711 |
) |
|
|
(73,784 |
) |
|
|
(218,324 |
) |
Effect of
exchange rate changes on cash andcash equivalents |
|
|
934 |
|
|
|
103 |
|
|
|
(2,245 |
) |
|
|
(19,313 |
) |
Decrease in cash and
cash equivalents |
|
|
(66,661 |
) |
|
|
(236,489 |
) |
|
|
(50,624 |
) |
|
|
(329,054 |
) |
Cash and
cash equivalents, beginning of period |
|
|
131,742 |
|
|
|
352,194 |
|
|
|
115,705 |
|
|
|
444,759 |
|
Cash and
cash equivalents, end of period |
|
$ |
65,081 |
|
|
$ |
115,705 |
|
|
$ |
65,081 |
|
|
$ |
115,705 |
|
INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(UNAUDITED)
(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 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(132,036 |
) |
|
|
(132,036 |
) |
Other comprehensive
loss for the period |
|
|
— |
|
|
|
— |
|
|
|
(24,846 |
) |
|
|
— |
|
|
|
(24,846 |
) |
Share
based compensation expense |
|
|
— |
|
|
|
5,100 |
|
|
|
— |
|
|
|
— |
|
|
|
5,100 |
|
Balance at December 31, 2017 |
|
$ |
2,319,293 |
|
|
$ |
44,037 |
|
|
$ |
131,610 |
|
|
$ |
(684,604 |
) |
|
$ |
1,810,336 |
|
(Stated in thousands of Canadian dollars) |
|
Shareholders’capital |
|
|
Contributedsurplus |
|
|
Accumulatedothercomprehensiveincome |
|
|
Deficit |
|
|
Totalequity |
|
Balance at January 1,
2016 |
|
$ |
2,316,321 |
|
|
$ |
35,800 |
|
|
$ |
166,101 |
|
|
$ |
(397,013 |
) |
|
$ |
2,121,209 |
|
Net loss for the
period |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(155,555 |
) |
|
|
(155,555 |
) |
Other comprehensive
loss for the period |
|
|
— |
|
|
|
— |
|
|
|
(9,645 |
) |
|
|
— |
|
|
|
(9,645 |
) |
Share options
exercised |
|
|
2,972 |
|
|
|
(1,046 |
) |
|
|
— |
|
|
|
— |
|
|
|
1,926 |
|
Share
based compensation expense |
|
|
— |
|
|
|
4,183 |
|
|
|
— |
|
|
|
— |
|
|
|
4,183 |
|
Balance
at December 31, 2016 |
|
$ |
2,319,293 |
|
|
$ |
38,937 |
|
|
$ |
156,456 |
|
|
$ |
(552,568 |
) |
|
$ |
1,962,118 |
|
FOURTH QUARTER 2017 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, February 15, 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 February 20, 2018 by dialing 1-855-859-2056 or
404-537-3406, pass code 9053499.
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, CFASenior Vice President and Chief
Financial Officer713.435.6111
Ashley Connolly, CFAManager, Investor
Relations403.716.4725
800, 525 - 8th Avenue S.W.Calgary, Alberta,
Canada T2P 1G1Website: www.precisiondrilling.com
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