(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 third quarter financial
results:
- Revenue of $382 million was an increase of 22% over the prior
year comparative quarter.
- Net loss of $31 million ($0.10 per share) compares to a net
loss of $26 million ($0.09 per share) in the third quarter of
2017.
- Earnings before income taxes, loss on repurchase and redemption
of unsecured senior notes, finance charges, foreign exchange and
depreciation and amortization (adjusted EBITDA see “NON-GAAP
MEASURES”) of $81 million was 11% higher than the third quarter of
2017.
- Funds provided by operations (see “NON-GAAP MEASURES”) of $64
million versus $85 million in the prior year comparative
quarter.
- Third quarter ending cash balance was $110 million, up $45
million from December 31, 2017.
- Third quarter capital expenditures were $29 million.
On October 5, we announced that we had entered
into an arrangement agreement with Trinidad Drilling Limited
(Trinidad) pursuant to which Precision agreed to acquire all the
issued and outstanding common shares of Trinidad on the basis of
0.445 common shares of Precision for each outstanding Trinidad
share. The aggregate transaction value is approximately $1,028
million, based on Precision’s share price as of October 4, 2018 and
including the assumption of approximately $477 million in Trinidad
net debt as of June 30, 2018. Upon completion of the transaction,
existing holders of Trinidad shares will collectively own 29.1% of
Precision. The transaction provides for payment of a non-completion
fee of $20 million by Trinidad in certain circumstances if the
transaction is not completed.
Precision’s President and CEO Kevin Neveu
stated: “During the third quarter Precision remained firmly on
track to deliver on our three key priorities for 2018: enhancing
financial performance through higher utilization and improved
margins; generating free cash flow for reducing total debt levels;
and commercializing advanced rig technologies. Although third
quarter weather-related delays in Canada, rig reactivation costs
associated with seven rigs in the U.S., and other one-time
transaction costs negatively impacted period cashflows, our team’s
persistent focus on cash management delivered an increased cash
balance and increased total liquidity for the third consecutive
quarter.”
“Our cash generating potential and liquidity
position remain strong. We expect to achieve the upper range of our
debt reduction target for 2018 and will continue our long-term debt
reduction program, reducing total debt, including debt repayments
earlier this year, by $300 million to $500 million before the end
of 2021.”
“We stand behind our Board-supported agreement
to combine with Trinidad and remain firm that our offer of 29.1
percent of Precision shares to the Trinidad shareholders is fair,
offering far more value creation upside than other available
options. We believe the combined company will create
significant value for both Precision and Trinidad shareholders with
immediate cost synergies and strong strategic fit.
Additionally, the incremental free cash flow generating potential
of this combination will support Precision’s ongoing long-term debt
reduction targets with potential to accelerate our stated
timeline. The combined platform, particularly the 61 Trinidad
high specification AC rigs and enhanced U.S. and international
exposure, improves our fixed cost leverage and market presence in
those key markets. We are in the process of completing required
regulatory filings and will provide updates as new information
becomes available.”
“In the U.S., despite recent capital markets
volatility, market indications for High Performance rig demand in
2019 are promising as development drilling in unconventional basins
continues to shift to the most technically capable and
operationally efficient rigs, benefiting Precision with our Super
Series fleet. Current customer demand for Precision’s Super Triple
rigs is hitting levels not experienced since 2014 and our
leading-edge day rates are trending above US$25,000 per day with
customers increasingly willing to sign longer term contracts.
Precision signed 13 term contracts in the U.S. this quarter and
five term contracts in October pointing to continued strong demand
for our Super Triple rigs. All 18 of these term contracts were
priced higher, with increases ranging from a few hundred dollars
per day to more than $5,000 per day. Third quarter activity was
slightly lower than expected averaging 76 rigs, but with recent rig
activations we have 80 rigs running today, our highest activity
level since 2014 and our strongest market share since we entered
the U.S. a decade ago. During the quarter we incurred increased
costs related to reactivation and restocking of rigs, totaling US$3
million to US$5 million that we do not expect to incur in the
fourth quarter. Several of the rigs reactivated had not been active
since 2015. These costs added to our daily operating costs and
negatively impacted field margins.”
“Our Canadian business continues to generate
strong free cash flow with a High Performance fleet and limited
capital requirements and we expect to continue on this path into
2019. We currently have 58 active rigs with quarter-to-date
activity largely tracking 2017 levels. While there are well-founded
concerns regarding commodity price differentials in the WCSB, early
indications from our customers suggest a winter drilling season
in-line with last year and strong demand in Deep Basin liquids
plays. The demand for our Super Triples is leading to longer
term customer contract commitments, with five term contracts signed
year-to-date including two during the quarter, compared to zero in
all of 2017. We are encouraged with the positive final investment
decision from LNG Canada and believe Precision is well-positioned
to benefit from incremental high spec rig demand and generally
improving natural gas fundamentals.”
“Internationally, we have eight rigs working
under contract, five in Kuwait and three in Saudi Arabia. Two of
the three Saudi Arabia rigs were recently contracted through the
end of the year and negotiations are well underway for multi-year
extension. Construction of our sixth Kuwait rig remains on time and
on budget for mid-2019 deployment and we are realizing the scale
benefits of a world-class drilling operation in country. We are
actively tendering our four idle rigs in the Middle East region as
we continue to seek increased scale in Saudi Arabia.”
“Our technology initiatives are progressing well
toward our 2018 commercialization target. We now have 25 Process
Automation Control (PAC) systems deployed in the field,
demonstrating to our customers the system’s ability to deliver
consistent and repeatable, high-quality wells while improving
safety, performance and operational efficiency. PAC has been
successfully utilized to automate drilling routines on
approximately 290 wells this year and system utilization is
increasing as we continue to “field harden” the technology.
Precision, its partners, customers and several third parties have
15 drilling performance applications (Apps) under development with
several Apps in field trials. Our progress and customer interest in
Apps is well ahead of our initial expectations. Our
optimization team is now fully equipped to run analytics on live
streaming data giving drillers the required insights on 16 distinct
activities to help optimize the drilling process in real-time. Our
Directional Guidance System (DGS) technology is also making a
difference having drilled over two and a half million feet to date
on over 100 wells in 2018, all enabled by DGS software. Our
customers are very encouraged with the results and prospects of
each of these technologies and we expect increasing revenue and
margin impact in 2019,” 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 September
30, |
|
Nine months ended September
30, |
(Stated in thousands of Canadian dollars,
except per share amounts) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue |
|
382,457 |
|
|
|
314,504 |
|
|
|
21.6 |
|
|
|
1,114,179 |
|
|
|
974,037 |
|
|
|
14.4 |
|
Adjusted EBITDA(1) |
|
80,988 |
|
|
|
73,239 |
|
|
|
10.6 |
|
|
|
240,639 |
|
|
|
214,067 |
|
|
|
12.4 |
|
Net loss |
|
(30,648 |
) |
|
|
(26,287 |
) |
|
|
16.6 |
|
|
|
(95,942 |
) |
|
|
(85,031 |
) |
|
|
12.8 |
|
Cash provided by operations |
|
31,961 |
|
|
|
56,757 |
|
|
|
(43.7 |
) |
|
|
199,845 |
|
|
|
93,266 |
|
|
|
114.3 |
|
Funds provided by operations(1) |
|
64,368 |
|
|
|
85,140 |
|
|
|
(24.4 |
) |
|
|
218,619 |
|
|
|
155,612 |
|
|
|
40.5 |
|
Capital spending: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expansion |
|
9,909 |
|
|
|
2,336 |
|
|
|
324.2 |
|
|
|
26,380 |
|
|
|
10,980 |
|
|
|
140.3 |
|
Upgrade |
|
11,545 |
|
|
|
7,168 |
|
|
|
61.1 |
|
|
|
28,355 |
|
|
|
34,102 |
|
|
|
(16.9 |
) |
Maintenance and infrastructure |
|
6,913 |
|
|
|
6,257 |
|
|
|
10.5 |
|
|
|
30,247 |
|
|
|
12,238 |
|
|
|
147.2 |
|
Intangibles |
|
660 |
|
|
|
6,757 |
|
|
|
(90.2 |
) |
|
|
10,880 |
|
|
|
15,727 |
|
|
|
(30.8 |
) |
Proceeds on sale |
|
(3,757 |
) |
|
|
(4,273 |
) |
|
|
(12.1 |
) |
|
|
(12,437 |
) |
|
|
(10,054 |
) |
|
|
23.7 |
|
Net capital spending |
|
25,270 |
|
|
|
18,245 |
|
|
|
38.5 |
|
|
|
83,425 |
|
|
|
62,993 |
|
|
|
32.4 |
|
Net loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
|
(0.10 |
) |
|
|
(0.09 |
) |
|
|
11.1 |
|
|
|
(0.33 |
) |
|
|
(0.29 |
) |
|
|
13.8 |
|
(1) See
“NON-GAAP MEASURES”. |
|
Operating Highlights |
|
Three months ended September
30, |
|
Nine months ended September
30, |
|
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Contract drilling rig fleet |
|
257 |
|
|
|
256 |
|
|
|
0.4 |
|
|
|
257 |
|
|
|
256 |
|
|
|
0.4 |
|
Drilling rig utilization days: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
4,798 |
|
|
|
4,487 |
|
|
|
6.9 |
|
|
|
14,100 |
|
|
|
13,945 |
|
|
|
1.1 |
|
U.S. |
|
7,013 |
|
|
|
5,593 |
|
|
|
25.4 |
|
|
|
19,396 |
|
|
|
15,114 |
|
|
|
28.3 |
|
International |
|
736 |
|
|
|
736 |
|
|
|
- |
|
|
|
2,184 |
|
|
|
2,184 |
|
|
|
- |
|
Revenue per utilization day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada(1) (Cdn$) |
|
19,538 |
|
|
|
19,980 |
|
|
|
(2.2 |
) |
|
|
21,273 |
|
|
|
21,092 |
|
|
|
0.9 |
|
U.S.(2) (US$) |
|
21,399 |
|
|
|
19,026 |
|
|
|
12.5 |
|
|
|
21,296 |
|
|
|
19,732 |
|
|
|
7.9 |
|
International (US$) |
|
50,007 |
|
|
|
50,528 |
|
|
|
(1.0 |
) |
|
|
49,959 |
|
|
|
50,214 |
|
|
|
(0.5 |
) |
Operating cost per utilization day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada (Cdn$) |
|
14,164 |
|
|
|
13,656 |
|
|
|
3.7 |
|
|
|
14,294 |
|
|
|
13,764 |
|
|
|
3.9 |
|
U.S. (US$) |
|
14,151 |
|
|
|
12,591 |
|
|
|
12.4 |
|
|
|
14,071 |
|
|
|
13,917 |
|
|
|
1.1 |
|
Service rig fleet |
|
210 |
|
|
|
210 |
|
|
|
- |
|
|
|
210 |
|
|
|
210 |
|
|
|
- |
|
Service rig operating hours |
|
37,169 |
|
|
|
42,653 |
|
|
|
(12.9 |
) |
|
|
121,694 |
|
|
|
128,523 |
|
|
|
(5.3 |
) |
Revenue per operating hour (Cdn$) |
|
708 |
|
|
|
638 |
|
|
|
11.0 |
|
|
|
696 |
|
|
|
635 |
|
|
|
9.6 |
|
(1) Includes lump sum revenue from contract
shortfall for the nine months ended September 30, 2018 and prior
year comparatives. |
(2) 2017 comparative periods include revenue
from idle but contracted rig days. |
|
Financial
Position |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Stated in
thousands of Canadian dollars, except ratios) |
September
30, 2018 |
|
|
December 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Working capital(1) |
|
223,024 |
|
|
|
232,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
109,762 |
|
|
|
65,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt(2) |
|
1,698,651 |
|
|
|
1,730,437 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term financial liabilities |
|
1,718,653 |
|
|
|
1,754,059 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
3,785,874 |
|
|
|
3,892,931 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt to long-term debt plus equity
ratio |
|
0.50 |
|
|
|
0.49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) See “NON-GAAP MEASURES”. |
(2) Net of unamortized debt issue costs. |
|
Summary for the three months ended September 30,
2018:
- Revenue this quarter was $382 million which is 22% higher than
the third quarter of 2017. The increase in revenue is primarily the
result of higher activity and higher average day rates in our U.S.
contract drilling business. Compared with the third quarter of 2017
our activity for the quarter, as measured by drilling rig
utilization days increased 25% and 7% in the U.S. and Canada,
respectively, and remained consistent internationally. Revenue from
our Contract Drilling Services segment increased over the
comparative prior year period by 25% while revenue in our
Completion and Production Services segment was down 4%.
- Adjusted EBITDA (see “NON-GAAP MEASURES”) this quarter of $81
million is an increase of $8 million from the third quarter of
2017. Our adjusted EBITDA as a percentage of revenue was 21% this
quarter, compared with 23% in the comparative quarter of 2017.
Adjusted EBITDA this quarter was positively impacted by higher
activity and day rates in the U.S. offset by higher share-based
incentive compensation from an increase in the Corporation’s share
price versus the comparative prior year period. Total share-based
incentive compensation expensed in the quarter was $8 million
compared to $2 million in the third quarter of 2017. See discussion
on share-based incentive compensation under “Other Items” later in
this report for additional details.
- Operating loss (see “NON-GAAP MEASURES”) this quarter was $10
million compared with an operating loss of $17 million in the third
quarter of 2017. Operating results this quarter were positively
impacted by the increase in activity and average day rates in our
U.S. contract drilling business.
- General and administrative expenses this quarter were $30
million, $8 million higher than the third quarter of 2017. The
increase is due to higher share-based incentive compensation
expense tied to the price of our common shares (see “Other Items”
later in this report) partially offset by a strengthening of the
Canadian dollar on our U.S. dollar denominated costs.
- Net finance charges were $31 million, a decrease of $1 million
compared with the third quarter of 2017, primarily due to a
reduction in interest expense related to debt retired in the fourth
quarter of 2017 and the second quarter of 2018 and the impact of
the strengthening of the Canadian dollar on our U.S. dollar
denominated interest.
- In Canada, average revenue per utilization day for contract
drilling rigs was $19,538 in the third quarter compared to $19,980
in the third quarter of 2017. Overall, shortfall payments received
in the prior year comparative quarter were largely offset by higher
spot market day rates in the current quarter. During the quarter,
we did not recognize any shortfall payments in revenue compared
with $5 million in the prior year comparative period. Excluding the
impact of shortfall payment revenue, average day rates were up 4%.
Revenue per utilization day in the U.S. increased in the third
quarter of 2018 to US$21,399 from US$19,026 in the prior year third
quarter. The increase in the U.S. revenue rate was the result of
higher day rates. During the quarter, we had turnkey revenue of
US$0.4 million compared with nil in the 2017 comparative period and
revenue from idle but contracted rigs of US$0.3 million compared
with nil in the prior year comparative period. On a sequential
basis, revenue per utilization day excluding revenue from turnkey
and idle but contracted rigs increased by US$1,085 due to higher
fleet average day rates.
- Average operating costs per utilization day for drilling rigs
in Canada increased to $14,164 compared with the prior year third
quarter of $13,656. The increase in average costs was due to timing
of equipment certification costs. On a sequential basis, operating
costs per day decreased by $2,548 compared to the second quarter of
2018 due to higher fixed cost absorption from higher activity
coming out of spring break-up. In the U.S., operating costs for the
quarter on a per day basis increased to US$14,151 in 2018 compared
with US$12,591 in 2017 due to costs associated with reactivating
and restocking rigs, timing of repair costs and higher
labour-related costs due to crew configuration. On a sequential
basis, operating costs per day increased by $125 compared to the
second quarter of 2018 as higher rig operating costs were partially
offset by no turnkey activity in the current period.
- We realized revenue from international contract drilling of
US$37 million in the third quarter of 2018, in-line with the prior
year period. Average revenue per utilization day in our
international contract drilling business was US$50,007 consistent
with the comparable prior year quarter.
- Directional drilling services realized revenue of $7 million in
the third quarter of 2018 compared with $6 million in the prior
year period.
- Funds provided by operations (see “NON-GAAP MEASURES”) in the
third quarter of 2018 were $64 million, a decrease of $21 million
from the prior year comparative quarter of $85 million. The
decrease was primarily the result of the timing of interest
payments and tax refunds received in the prior year comparative
period partially offset by improved operating results.
- Capital expenditures were $29 million in the third quarter, an
increase of $7 million over the same period in 2017. Capital
spending for the quarter included $21 million for upgrade and
expansion capital, $7 million for the maintenance of existing
assets and infrastructure spending and $1 million for intangibles
related to a new ERP system.
Summary for the nine months ended September 30,
2018:
- Revenue for the first nine months of 2018 was $1,114 million,
an increase of 14% from the 2017 period.
- Operating loss (see “NON-GAAP MEASURES”) was $26 million, a
decrease of $43 million over the same period in 2017. Operating
loss was 2% of revenue in 2018 compared with 7% of revenue in 2017.
Operating results this year were positively impacted by increased
activity and pricing in our North American contract drilling
businesses.
- General and administrative costs were $91 million, an increase
of $23 million from 2017. The increase was due to higher
share-based incentive compensation that is tied to the price of our
common shares (see “Other Items” later in this report) partially
offset by the strengthening of the Canadian dollar on our U.S.
dollar denominated costs.
- Net finance charges were $95 million, a decrease of $5 million
from 2017 primarily due to a reduction in interest expense related
to debt retired in 2017 and the effect of a stronger Canadian
dollar on our U.S. dollar denominated interest expense partially
offset by higher interest income earned in the comparative
period.
- Funds provided by operations (see “NON-GAAP MEASURES”) in the
first nine months of 2018 were $219 million, an increase of $63
million from the prior year comparative period of $156
million.
- Capital expenditures for the purchase of property, plant and
equipment were $96 million for the nine months of 2018, an increase
of $23 million over the same period in 2017. Capital spending for
2018 to date includes $55 million for upgrade and expansion
capital, $30 million for the maintenance of existing assets and
infrastructure and $11 million for intangibles related to a new ERP
system.
STRATEGY
Precision’s strategic priorities for 2018 are as follows:
- Reduce debt by generating free cash
flow while continuing to fund only the most attractive investment
opportunities – we generated $219 million in funds
provided by operations (see “NON-GAAP MEASURES”) in the first nine
months of 2018, representing a $63 million increase over the prior
year comparative period. Utilizing cash generated in the first nine
months of 2018, we reduced debt by $77 million through a partial
redemption of our 2021 unsecured senior notes and open market debt
repurchases of our 2021 and 2024 notes. We communicated a firm goal
to reduce debt by $75 to $125 million in 2018 and have successfully
achieved the low end of that range in the first nine months of this
year. We expect to achieve the upper range of our debt reduction
target for 2018. In addition, we ended the third quarter with $110
million of cash on the balance sheet.
- Reinforce Precision’s High Performance competitive
advantage by deploying Process Automation Controls (PAC),
Directional Guidance Systems (DGS) and Drilling Performance Apps
(Apps) on a wide scale basis – year to date in 2018 we
have drilled over 100 wells using our DGS compared to 58 wells in
all of 2017. We have 25 rigs currently running in the field with
PAC and have drilled approximately 290 wells with this technology
in 2018 compared to 154 in all of 2017. Earlier this year we
also equipped our training rigs in Nisku and Houston with PAC
technology. Customer adoption is rising, and we expect to be
running a total of 31 systems in the field by year end, continuing
full scale deployment and commercialization. Additionally, we are
deploying revenue generating Apps on several rigs and currently
have 15 Apps in varying stages of commercial development showcasing
the open platform of our PAC system. Several Apps are
customer-built and supported by Precision’s PAC platform with
specific hosting agreements in place.
- Enhance financial performance through higher
utilization and improved operating margins – in the first
nine months of 2018 overall utilization days are 14% higher than
the prior year comparative period while average operating margins
(revenue less operating costs) are up 24%, 4% and 5% in our U.S.,
international and Canadian contract drilling businesses,
respectively.
OUTLOOK
For the third quarter of 2018, the average West
Texas Intermediate (WTI) price of oil was 45% higher than the prior
year comparative period while the average Henry Hub gas price was
in-line and the average AECO price was 25% lower. According to the
Petroleum Services Society of Canada for the year to date period
ending October 22, 2018 Western Canada Select traded at an average
discount to WTI of $33.80 per barrel and was trading at a discount
of $56.74 on October 22, 2018.
|
|
Three months ended September
30, |
|
|
Year ended December 31, |
|
|
2018 |
|
|
2017 |
|
|
2017 |
|
Average oil and natural gas prices |
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
West Texas Intermediate (per barrel) (US$) |
|
69.77 |
|
|
|
48.03 |
|
|
|
50.95 |
|
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
AECO (per MMBtu) (CDN$) |
|
1.24 |
|
|
|
1.66 |
|
|
|
2.16 |
|
United States |
|
|
|
|
|
|
|
|
|
|
|
Henry Hub (per MMBtu) (US$) |
|
2.93 |
|
|
|
2.93 |
|
|
|
2.98 |
|
Contracts
Year to date in 2018 we have entered into 54
term contracts. The following chart outlines the average number of
drilling rigs by quarter that we had under contract for 2018 and
2019 as of October 24, 2018.
|
|
Average for the quarter ended
2018 |
|
|
Average for the quarter ended
2019 |
|
|
|
Mar. 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
|
Dec. 31 |
|
|
Mar. 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
|
Dec. 31 |
|
Average rigs under term contract as of October 24, 2018: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
8 |
|
|
|
9 |
|
|
|
9 |
|
|
|
11 |
|
|
|
8 |
|
|
|
7 |
|
|
|
7 |
|
|
|
6 |
|
U.S. |
|
|
36 |
|
|
|
48 |
|
|
|
50 |
|
|
|
48 |
|
|
|
37 |
|
|
|
23 |
|
|
|
14 |
|
|
|
10 |
|
International |
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
6 |
|
|
|
5 |
|
|
|
5 |
|
|
|
5 |
|
Total |
|
|
52 |
|
|
|
65 |
|
|
|
67 |
|
|
|
67 |
|
|
|
51 |
|
|
|
35 |
|
|
|
26 |
|
|
|
21 |
|
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 and 2019 as
of October 24, 2018.
|
|
Average for the year ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 |
|
|
2018 |
|
|
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average rigs under term contract as of October 24, 2018: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
20 |
|
|
|
9 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
29 |
|
|
|
45 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
8 |
|
|
|
7 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
57 |
|
|
|
61 |
|
|
|
33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In Canada, term contracted rigs normally
generate 250 utilization days per year because of the seasonal
nature of well site access. In most regions in the U.S. and
internationally, term contracts normally generate 365 utilization
days per year.
Drilling Activity
The following chart outlines the average number
of drilling rigs that we had working or moving by quarter for the
periods noted.
|
Average for the quarter ended
2017 |
|
|
2018 |
|
|
Mar. 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
|
Dec. 31 |
|
|
Mar. 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
Average Precision active rig count: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
76 |
|
|
|
29 |
|
|
|
49 |
|
|
|
54 |
|
|
|
72 |
|
|
|
31 |
|
|
|
52 |
|
U.S. |
|
47 |
|
|
|
59 |
|
|
|
61 |
|
|
|
58 |
|
|
|
64 |
|
|
|
72 |
|
|
|
76 |
|
International |
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
|
|
8 |
|
Total |
|
131 |
|
|
|
96 |
|
|
|
118 |
|
|
|
120 |
|
|
|
144 |
|
|
|
111 |
|
|
|
136 |
|
For the first nine months of 2018, drilling
activity has increased relative to this time last year in the U.S.
and is down slightly in Canada. According to industry sources, as
of October 19, 2018, the U.S. active land drilling rig count was up
approximately 18% from the same point last year and the Canadian
active land drilling rig count was down approximately 5%. 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.
Industry Conditions
We expect Tier 1 rigs to remain the preferred
rigs of customers globally. The economic value created by the
significant drilling and mobility efficiencies delivered by the
most advanced XY pad walking rigs has been highlighted and widely
accepted by our customers. The trend to longer-reach horizontal
completions and importance of the rig delivering these complex
wells consistently and efficiently has been well established by the
industry. We expect demand for leading edge high efficiency Tier 1
rigs will continue to strengthen, as drilling rig capability has
been a key economic facilitator of horizontal/unconventional
resource exploitation. Development and field application of
drilling equipment process automation coupled with closed loop
drilling controls and de-manning of rigs will continue this
technical evolution while creating further cost efficiencies and
performance value for customers.
Capital Spending
Capital spending in 2018 is expected to be $135
million and includes $52 million for sustaining and infrastructure,
$71 million for upgrade and expansion and $12 million on
intangibles related to a new ERP system. We expect that the $135
million will be split $115 million in the Contract Drilling
Services segment, $6 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 September
30, |
|
|
Nine months ended September
30, |
|
(Stated in thousands of Canadian dollars) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling Services |
|
347,494 |
|
|
|
278,569 |
|
|
|
24.7 |
|
|
|
1,004,649 |
|
|
|
864,957 |
|
|
|
16.2 |
|
Completion and Production Services |
|
36,297 |
|
|
|
37,816 |
|
|
|
(4.0 |
) |
|
|
114,045 |
|
|
|
113,546 |
|
|
|
0.4 |
|
Inter-segment eliminations |
|
(1,334 |
) |
|
|
(1,881 |
) |
|
|
(29.1 |
) |
|
|
(4,515 |
) |
|
|
(4,466 |
) |
|
|
1.1 |
|
|
|
382,457 |
|
|
|
314,504 |
|
|
|
21.6 |
|
|
|
1,114,179 |
|
|
|
974,037 |
|
|
|
14.4 |
|
Adjusted EBITDA:(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Drilling Services |
|
95,596 |
|
|
|
81,994 |
|
|
|
16.6 |
|
|
|
290,003 |
|
|
|
242,690 |
|
|
|
19.5 |
|
Completion and Production Services |
|
4,628 |
|
|
|
4,251 |
|
|
|
8.9 |
|
|
|
7,870 |
|
|
|
9,174 |
|
|
|
(14.2 |
) |
Corporate and Other |
|
(19,236 |
) |
|
|
(13,006 |
) |
|
|
47.9 |
|
|
|
(57,234 |
) |
|
|
(37,797 |
) |
|
|
51.4 |
|
|
|
80,988 |
|
|
|
73,239 |
|
|
|
10.6 |
|
|
|
240,639 |
|
|
|
214,067 |
|
|
|
12.4 |
|
(1) See “NON-GAAP MEASURES”. |
|
SEGMENT REVIEW OF CONTRACT DRILLING
SERVICES |
|
Three months ended September
30, |
|
|
Nine months ended September
30, |
|
(Stated in thousands of Canadian dollars,
except where noted) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue |
|
347,494 |
|
|
|
278,569 |
|
|
|
24.7 |
|
|
|
1,004,649 |
|
|
|
864,957 |
|
|
|
16.2 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
242,792 |
|
|
|
189,143 |
|
|
|
28.4 |
|
|
|
686,948 |
|
|
|
598,040 |
|
|
|
14.9 |
|
General and administrative |
|
9,106 |
|
|
|
7,432 |
|
|
|
22.5 |
|
|
|
27,698 |
|
|
|
24,227 |
|
|
|
14.3 |
|
Adjusted EBITDA(1) |
|
95,596 |
|
|
|
81,994 |
|
|
|
16.6 |
|
|
|
290,003 |
|
|
|
242,690 |
|
|
|
19.5 |
|
Depreciation |
|
80,742 |
|
|
|
80,653 |
|
|
|
0.1 |
|
|
|
238,621 |
|
|
|
251,907 |
|
|
|
(5.3 |
) |
Operating earnings (loss)(1) |
|
14,854 |
|
|
|
1,341 |
|
|
|
1,007.7 |
|
|
|
51,382 |
|
|
|
(9,217 |
) |
|
|
(657.5 |
) |
Operating earnings (loss)(1) as a percentage
of revenue |
|
4.3 |
% |
|
|
0.5 |
% |
|
|
|
|
|
|
5.1 |
% |
|
|
(1.1 |
)% |
|
|
|
|
(1) See “NON-GAAP MEASURES”. |
|
|
Three months ended September
30, |
|
Canadian onshore drilling statistics:(1) |
|
2018 |
|
|
2017 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Number of drilling rigs (end of period) |
|
|
135 |
|
|
|
604 |
|
|
|
136 |
|
|
|
634 |
|
Drilling rig operating days (spud to release) |
|
|
4,279 |
|
|
|
16,875 |
|
|
|
3,998 |
|
|
|
16,288 |
|
Drilling rig operating day utilization |
|
|
35 |
% |
|
|
30 |
% |
|
|
32 |
% |
|
|
28 |
% |
Number of wells drilled |
|
|
520 |
|
|
|
2,046 |
|
|
|
451 |
|
|
|
1,977 |
|
Average days per well |
|
|
8.2 |
|
|
|
8.2 |
|
|
|
8.9 |
|
|
|
8.2 |
|
Number of metres drilled (000s) |
|
|
1,313 |
|
|
|
5,502 |
|
|
|
1,123 |
|
|
|
5,179 |
|
Average metres per well |
|
|
2,526 |
|
|
|
2,689 |
|
|
|
2,490 |
|
|
|
2,620 |
|
Average metres per day |
|
|
307 |
|
|
|
326 |
|
|
|
281 |
|
|
|
318 |
|
|
|
Nine months ended September
30, |
|
Canadian onshore drilling statistics:(1) |
|
2018 |
|
|
2017 |
|
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Number of drilling rigs (end of period) |
|
|
135 |
|
|
|
604 |
|
|
|
136 |
|
|
|
634 |
|
Drilling rig operating days (spud to release) |
|
|
12,459 |
|
|
|
49,256 |
|
|
|
12,398 |
|
|
|
49,889 |
|
Drilling rig operating day utilization |
|
|
34 |
% |
|
|
29 |
% |
|
|
34 |
% |
|
|
29 |
% |
Number of wells drilled |
|
|
1,262 |
|
|
|
5,179 |
|
|
|
1,282 |
|
|
|
5,285 |
|
Average days per well |
|
|
9.9 |
|
|
|
9.5 |
|
|
|
9.7 |
|
|
|
9.4 |
|
Number of metres drilled (000s) |
|
|
3,542 |
|
|
|
14,704 |
|
|
|
3,352 |
|
|
|
14,267 |
|
Average metres per well |
|
|
2,806 |
|
|
|
2,839 |
|
|
|
2,615 |
|
|
|
2,700 |
|
Average metres per day |
|
|
284 |
|
|
|
299 |
|
|
|
270 |
|
|
|
286 |
|
(1) Canadian operations only. |
(2) Canadian Association of Oilwell Drilling
Contractors (“CAODC”), and Precision – excludes non-CAODC rigs and
non-reporting CAODC members. |
United States onshore drilling
statistics:(1) |
2018 |
|
|
2017 |
|
|
Precision |
|
|
Industry(2) |
|
|
Precision |
|
|
Industry(2) |
|
Average number of active land rigs for quarters ended: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31 |
|
64 |
|
|
|
951 |
|
|
|
47 |
|
|
|
722 |
|
June 30 |
|
72 |
|
|
|
1,021 |
|
|
|
59 |
|
|
|
874 |
|
September 30 |
|
76 |
|
|
|
1,032 |
|
|
|
61 |
|
|
|
927 |
|
Year to date average |
|
71 |
|
|
|
1,001 |
|
|
|
55 |
|
|
|
841 |
|
(1) United States lower 48 operations
only. |
(2) Baker Hughes rig counts. |
Revenue from Contract Drilling Services was $347
million this quarter, or 25% higher than the third quarter of 2017,
while adjusted EBITDA (see “NON-GAAP MEASURES”) increased by 17% to
$96 million. The increase in revenue was primarily due to higher
utilization days as well as higher spot market rates in the U.S.
During the quarter we did not recognize any shortfall payments in
our Canadian contract drilling business compared with $5 million in
the prior year comparative period. In the U.S. we recognized
turnkey revenue of US$0.4 million compared with nil in the
comparative period and we recognized US$0.3 million in idle but
contracted revenue compared with nil in the comparative quarter of
2017.
Drilling rig utilization days in Canada
(drilling days plus move days) were 4,798 during the third quarter
of 2018, an increase of 7% compared to 2017 primarily due to
increased industry activity despite wet weather in September which
delayed certain rigs from moving to new rig locations.
Drilling rig utilization days in the U.S. were 7,013, or 25%
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 736, in-line with the same quarter of
2017.
Compared with the same quarter in 2017, drilling
rig revenue per utilization day in Canada decreased 2% as lower
shortfall revenue in the current quarter was partially offset by
increases in spot market compared with the prior period. Drilling
rig revenue per utilization day for the quarter in the U.S. was up
12% compared to prior year as we realized higher average day rates.
International revenue per utilization day was in-line with the
prior year comparative period.
In Canada, 11% of our utilization days in the
quarter were generated from rigs under term contract, compared with
18% in the third quarter of 2017. In the U.S., 67% of utilization
days were generated from rigs under term contract as compared with
55% in the third quarter of 2017.
Operating costs were 70% of revenue for the
quarter, two percentage points higher 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 due
to timing of equipment certification costs to prepare rigs for
upcoming winter work. In the U.S., operating costs for the quarter
on a per day basis were higher than the prior year period primarily
due to costs associated with reactivating and restocking rigs,
timing of repair costs and higher labour-related costs due crew
configuration.
Depreciation expense in the quarter was in-line
with the third quarter of 2017.
|
SEGMENT REVIEW OF COMPLETION AND PRODUCTION
SERVICES |
|
|
Three months ended September
30, |
|
|
Nine months ended September
30, |
|
(Stated in thousands of Canadian dollars,
except where noted) |
2018 |
|
|
2017 |
|
|
% Change |
|
|
2018 |
|
|
2017 |
|
|
% Change |
|
Revenue |
|
36,297 |
|
|
|
37,816 |
|
|
|
(4.0 |
) |
|
|
114,045 |
|
|
|
113,546 |
|
|
|
0.4 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
30,138 |
|
|
|
31,674 |
|
|
|
(4.8 |
) |
|
|
100,216 |
|
|
|
98,773 |
|
|
|
1.5 |
|
General and administrative |
|
1,531 |
|
|
|
1,891 |
|
|
|
(19.0 |
) |
|
|
5,959 |
|
|
|
5,599 |
|
|
|
6.4 |
|
Adjusted EBITDA(1) |
|
4,628 |
|
|
|
4,251 |
|
|
|
8.9 |
|
|
|
7,870 |
|
|
|
9,174 |
|
|
|
(14.2 |
) |
Depreciation |
|
6,641 |
|
|
|
6,731 |
|
|
|
(1.3 |
) |
|
|
18,528 |
|
|
|
21,228 |
|
|
|
(12.7 |
) |
Operating loss(1) |
|
(2,013 |
) |
|
|
(2,480 |
) |
|
|
(18.8 |
) |
|
|
(10,658 |
) |
|
|
(12,054 |
) |
|
|
(11.6 |
) |
Operating loss(1) as a percentage of
revenue |
|
(5.5 |
)% |
|
|
(6.6 |
)% |
|
|
|
|
|
|
(9.3 |
)% |
|
|
(10.6 |
)% |
|
|
|
|
Well servicing statistics: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of service rigs (end of period) |
|
210 |
|
|
|
210 |
|
|
|
- |
|
|
|
210 |
|
|
|
210 |
|
|
|
- |
|
Service rig operating hours |
|
37,169 |
|
|
|
42,653 |
|
|
|
(12.9 |
) |
|
|
121,694 |
|
|
|
128,523 |
|
|
|
(5.3 |
) |
Service rig operating hour utilization |
|
19 |
% |
|
|
22 |
% |
|
|
(13.6 |
) |
|
|
21 |
% |
|
|
22 |
% |
|
|
(4.5 |
) |
Service rig revenue per operating hour |
|
708 |
|
|
|
638 |
|
|
|
11.0 |
|
|
|
696 |
|
|
|
635 |
|
|
|
9.6 |
|
(1) See “NON-GAAP MEASURES”. |
Revenue from Completion and Production Services was down $2
million or 4% compared with the third quarter of 2017 due to lower
activity in our Canadian well servicing and rental businesses
partially offset by higher camp activity. Our service rig operating
hours in the quarter were down 13% from the third quarter of 2017
while rates increased an average of 11%. Approximately 97% of our
third 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 third quarter of 2017
where 90% of revenue was generated in Canada and 10% in the
U.S.
Average service rig revenue per operating hour
in the quarter was $708 or $70 higher than the third quarter of
2017. The increase was primarily the result of increased costs
passed through to the customer.
Adjusted EBITDA (see “NON-GAAP MEASURES”) was
higher than the third quarter of 2017 primarily because of higher
average rates and improved cost structure, slightly offset by lower
activity.
Operating costs as a percentage of revenue was
83% compared with the prior year comparative quarter of 84%.
Depreciation in the quarter was in-line with the
prior 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 (see “NON-GAAP MEASURES”) loss of
$19 million, a $6 million increase compared with the third quarter
of 2017 primarily due to higher share-based incentive compensation
and costs incurred associated with our arrangement agreement with
Trinidad.
OTHER ITEMS
Share-based Incentive Compensation
Plans
We have several cash-settled share-based
incentive plans for non-management directors, officers, and other
eligible employees. The fair values of the amounts payable under
these plans are recognized as an expense with a corresponding
increase in liabilities over the period that the participant
becomes entitled to payment. The recorded liability is
re-established at the end of each reporting period until settlement
with the resultant change to fair value of the liability recognized
in net earnings (loss) for the period.
We also have two equity-settled share-based
incentive plans. Under the Executive Performance Share plan, which
commenced in May 2017, the fair value of the PSUs granted is
calculated at the date of grant using a Monte Carlo simulation, and
that value is recorded as compensation expense over the grant's
vesting period with an offset to contributed surplus. Upon
redemption of the PSUs into common shares, the associated amount is
reclassified from contributed surplus to shareholders' capital. The
share option plan is treated similarly, except that the fair value
of the share purchased options granted are valued using the
Black-Scholes option pricing model and consideration paid by
employees upon exercise of the equity purchase options are
recognized in share capital.
A summary of the amounts expensed (recovered)
under these plans during the reporting periods are as follows:
|
|
Three months ended September
30, |
|
|
Nine months ended September
30, |
|
(Stated in thousands of Canadian
dollars) |
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Cash settled share-based incentive plans |
|
5,128 |
|
|
|
770 |
|
|
|
20,599 |
|
|
|
(1,544 |
) |
Equity settled share-based incentive plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Executive PSU |
|
1,595 |
|
|
|
540 |
|
|
|
4,344 |
|
|
|
1,361 |
|
Stock option plan |
|
937 |
|
|
|
823 |
|
|
|
2,655 |
|
|
|
2,543 |
|
Total share-based incentive compensation plan
expense |
|
7,660 |
|
|
|
2,133 |
|
|
|
27,598 |
|
|
|
2,360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allocated: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
2,292 |
|
|
|
691 |
|
|
|
9,093 |
|
|
|
1,125 |
|
General and Administrative |
|
5,368 |
|
|
|
1,442 |
|
|
|
18,505 |
|
|
|
1,235 |
|
|
|
7,660 |
|
|
|
2,133 |
|
|
|
27,598 |
|
|
|
2,360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash settled shared-based compensation expense
increased $4 million in the current quarter to $5 million compared
to $1 million in the same quarter in 2017. The increase is
primarily due to the increasing share price experienced in the
current quarter compared to a declining share price in the
comparative 2017 period.
Executive PSU share-based incentive compensation
expense for the quarter was $2 million compared to $1 million in
the same quarter in 2017. This increase is a result of the plan
being implemented part way through the second quarter in 2017 and
from additional grants in 2018.
Financing Charges
Net financial charges for the quarter were $31
million, a decrease of $1 million compared with the third 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 the fourth quarter of 2017 and
the second quarter of 2018.
Income Tax
Income tax expense for the quarter was a
recovery of $9 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 and upgrade 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(1) (extendible, revolvingterm
credit facility with US$250 million(2) accordion feature) |
|
Undrawn, except US$28 million inoutstanding
letters of credit |
|
General corporate purposes |
|
November 21, 2021 |
Operating facilities
(secured) |
|
|
|
|
|
|
$40 million |
|
Undrawn, except $26 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$3 million inoutstanding
letters of credit |
|
Letters of credit |
|
|
Senior notes
(unsecured) |
|
|
|
|
|
|
US$196 million – 6.5% |
|
Fully drawn |
|
Capital expenditures and generalcorporate
purposes |
|
December 15, 2021 |
US$350 million – 7.75% |
|
Fully drawn |
|
Debt redemption and repurchases |
|
December 15, 2023 |
US$395 million – 5.25% |
|
Fully drawn |
|
Capital expenditures and generalcorporate
purposes |
|
November 15, 2024 |
US$400 million – 7.125% |
|
Fully drawn |
|
Debt redemption and repurchases |
|
January 15, 2026 |
(1) Upon closing of the arrangement agreement
to acquire Trinidad we have a commitment from one of our lenders to
increase the size of our revolving credit facility to US$600
million. |
(2) Increases to US$300 million at the end of
the covenant relief period of March 31, 2019. |
As of September 30, 2018, we had $1,724 million outstanding
under our unsecured senior notes. The current blended cash interest
cost of our debt is approximately 6.6%.
In the second quarter we redeemed US$50 million of our 6.5%
unsecured senior notes due 2021 and repurchased and cancelled US$3
million principal amount of our 2021 notes and US$5 million
principal of our 2024 notes.
Covenants
Following is a listing of our currently
applicable financial covenants and the calculations as of September
30, 2018.
|
Covenant |
|
As of September 30,2018 |
|
Senior Facility |
|
|
|
|
|
Consolidated senior debt to consolidated covenant
EBITDA(1) |
< 2.50 |
|
|
0.00 |
|
Consolidated covenant EBITDA to consolidated
interest expense(1) |
> 2.00 |
|
|
2.52 |
|
Senior Notes |
|
|
|
|
|
Consolidated interest coverage ratio |
> 2.00 |
|
|
2.46 |
|
(1) For purposes of calculating the leverage
ratio consolidated senior debt only includes secured
indebtedness. |
At September 30, 2018, we were in compliance with the covenants
of our senior credit facility and unsecured senior notes.
Senior Facility
The senior credit facility requires that we
comply with certain covenants including a leverage ratio of
consolidated senior debt to consolidated Covenant EBITDA (see
“NON-GAAP MEASURES”) of less than 2.5:1. For purposes of
calculating the leverage ratio consolidated senior debt only
includes secured indebtedness.
Under the senior credit facility, we are
required to maintain a ratio of consolidated Covenant EBITDA (see
“NON-GAAP MEASURES”) to consolidated interest expense for the most
recent four consecutive quarters, of greater than 2.0:1 for the
periods ending September 30, and December 31, 2018 and March 31,
2019. For periods ending after March 31, 2019 the ratio reverts to
2.5:1.
The senior credit facility prevents us from
making distributions prior to April 1, 2019, after which,
distributions are subject to a pro forma consolidated senior net
leverage covenant of less than or equal to 1.75:1. The senior
credit facility also limits the redemption and repurchase of junior
debt subject to a pro forma consolidated senior net leverage
covenant ratio of less than or equal to 1.75:1.
In addition, the senior credit facility contains
certain covenants that place restrictions on our ability to incur
or assume additional indebtedness; dispose of assets; pay
dividends, undertake share redemptions or other distributions;
change our primary business; incur liens on assets; engage in
transactions with affiliates; enter into mergers, consolidations or
amalgamations; and enter into speculative swap agreements.
Unsecured Senior Notes
The senior notes require that we comply with
financial covenants including an incurrence based consolidated
interest coverage ratio test of consolidated cash flow, as defined
in the senior note agreements, to consolidated interest expense of
greater than 2.0:1 for the most recent four consecutive fiscal
quarters. In the event that our consolidated interest coverage
ratio is less than 2.0:1 for the most recent four consecutive
fiscal quarters, the senior notes restrict our ability to incur
additional indebtedness.
The senior notes contain a restricted payments
covenant that limits our ability to make payments in the nature of
dividends, distributions and for repurchases from shareholders.
This restricted payment basket grows from a starting point of
October 1, 2010 for the 2021 and 2024 senior notes, from October 1,
2016 for the 2023 senior notes and October 1, 2017 for the 2026
senior notes by, among other things, 50% of consolidated cumulative
net earnings and decreases by 100% of consolidated cumulative net
losses, as defined in the note agreements, and payments made to
shareholders. Beginning with the December 31, 2015 calculation the
governing net restricted payments basket was negative and as of
that date we were no longer able to declare and make dividend
payments until such time as the restricted payments baskets once
again become positive. For further information, please see the
senior note indentures which are available on SEDAR and EDGAR.
In addition, the senior notes contain certain
covenants that limit our ability, and the ability of certain
subsidiaries, to incur additional indebtedness and issue preferred
shares; create liens; create or permit to exist restrictions on our
ability or certain subsidiaries to make certain payments and
distributions; engage in amalgamations, mergers or consolidations;
make certain dispositions and engage in transactions with
affiliates.
Hedge of investments in foreign operations
We utilize foreign currency long-term debt to
hedge our exposure to changes in the carrying values of our net
investment in certain foreign operations as a result of changes in
foreign exchange rates.
We have designated our U.S. dollar denominated
long-term debt as a net investment hedge in our U.S. operations and
other foreign operations that have a U.S. dollar functional
currency. To be accounted for as a hedge, the foreign currency
denominated long-term debt must be designated and documented as
such and must be effective at inception and on an ongoing basis. We
recognize the effective amount of this hedge (net of tax) in other
comprehensive income. We recognize ineffective amounts (if any) in
net earnings (loss).
Average shares outstanding
The following table reconciles the weighted
average shares outstanding used in computing basic and diluted net
loss per share:
|
Three months ended Sept. 30, |
|
|
Nine months ended Sept. 30, |
|
(Stated in thousands) |
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Weighted average shares outstanding |
|
293,740 |
|
|
|
293,239 |
|
|
|
293,485 |
|
|
|
293,239 |
|
Effect of stock options and other equity
compensation plans |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Weighted average shares outstanding – basic
and diluted |
|
293,740 |
|
|
|
293,239 |
|
|
|
293,485 |
|
|
|
293,239 |
|
|
QUARTERLY FINANCIAL SUMMARY |
(Stated in thousands of Canadian
dollars, except per share amounts) |
|
2017 |
|
|
2018 |
|
Quarters ended |
|
December 31 |
|
|
March 31 |
|
|
June 30 |
|
|
September
30 |
|
Revenue |
|
|
347,187 |
|
|
|
401,006 |
|
|
|
330,716 |
|
|
|
382,457 |
|
Adjusted EBITDA(2) |
|
|
90,914 |
|
|
|
97,469 |
|
|
|
62,182 |
|
|
|
80,988 |
|
Net loss |
|
|
(47,005 |
) |
|
|
(18,077 |
) |
|
|
(47,217 |
) |
|
|
(30,648 |
) |
Net loss per basic and diluted share |
|
|
(0.16 |
) |
|
|
(0.06 |
) |
|
|
(0.16 |
) |
|
|
(0.10 |
) |
Funds provided by operations(2) |
|
|
28,323 |
|
|
|
104,026 |
|
|
|
50,225 |
|
|
|
64,368 |
|
Cash provided by operations |
|
|
23,289 |
|
|
|
38,189 |
|
|
|
129,695 |
|
|
|
31,961 |
|
(Stated in thousands of Canadian
dollars, except per share amounts) |
|
2016 |
|
|
2017 |
|
Quarters ended |
|
December 31 |
|
|
March 31 |
|
|
June 30 |
|
|
September 30 |
|
Revenue(1) |
|
|
302,653 |
|
|
|
368,673 |
|
|
|
290,860 |
|
|
|
314,504 |
|
Adjusted EBITDA(2) |
|
|
65,000 |
|
|
|
84,308 |
|
|
|
56,520 |
|
|
|
73,239 |
|
Net loss |
|
|
(30,618 |
) |
|
|
(22,614 |
) |
|
|
(36,130 |
) |
|
|
(26,287 |
) |
Net loss per basic and diluted share |
|
|
(0.10 |
) |
|
|
(0.08 |
) |
|
|
(0.12 |
) |
|
|
(0.09 |
) |
Funds provided by (used in) operations(2) |
|
|
11,466 |
|
|
|
85,659 |
|
|
|
(15,187 |
) |
|
|
85,140 |
|
Cash provided by (used in) operations |
|
|
(27,846 |
) |
|
|
33,770 |
|
|
|
2,739 |
|
|
|
56,757 |
|
(1) Comparatives for revenue have changed for
the periods ending December 2016, March 2017 and June 2017 to
reflect a recast of certain amounts previously netted against
operating expense. See our 2017 Annual Report. |
(2) See “NON-GAAP MEASURES”. |
|
CRITICAL ACCOUNTING JUDGEMENTS AND
ESTIMATES
Because of the nature of our business, we are
required to make judgments and estimates in preparing our
Consolidated Interim Financial Statements that could materially
affect the amounts recognized. Our judgments and estimates are
based on our past experiences and assumptions we believe are
reasonable in the circumstances. The critical judgments and
estimates used in preparing the Interim Financial Statements are
described in our 2017 Annual Report and there have been no material
changes to our critical accounting judgments and estimates during
the three and nine-month periods ended September 30, 2018 except
for those impacted by the adoption of new accounting standards.
NON-GAAP MEASURES
In this press release we reference non-GAAP
(Generally Accepted Accounting Principles) measures. Adjusted
EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided
by (Used in) Operations and Working Capital are terms used by us to
assess performance as we believe they provide useful supplemental
information to investors. These terms do not have standardized
meanings prescribed under International Financial Reporting
Standards (IFRS) and may not be comparable to similar measures used
by other companies.
Adjusted EBITDA
We believe that adjusted EBITDA (earnings before
income taxes, loss on repurchase and redemption of unsecured senior
notes, finance charges, foreign exchange, and depreciation and
amortization), as reported in the Interim Consolidated Statement of
Loss, is a useful measure, because it gives an indication of the
results from our principal business activities prior to
consideration of how our activities are financed and the impact of
foreign exchange, taxation and depreciation and amortization
charges.
Covenant EBITDA
Covenant EBITDA, as defined in our senior credit
facility agreement, is used in determining the Corporation’s
compliance with its covenants. Covenant EBITDA differs from
Adjusted EBITDA by the exclusion of bad debt expense, restructuring
costs and certain foreign exchange amounts.
Operating Earnings (Loss)
We believe that operating earnings (loss), as
reported in the Interim Consolidated Statements of Loss, is a
useful measure because it provides an indication of the results of
our principal business activities before consideration of how those
activities are financed and the impact of foreign exchange and
taxation.
Funds Provided By (Used In)
Operations
We believe that funds provided by (used in)
operations, as reported in the Interim Consolidated Statements of
Cash Flow, is a useful measure because it provides an indication of
the funds our principal business activities generate prior to
consideration of working capital, which is primarily made up of
highly liquid balances.
Working Capital
We define working capital as current assets less
current liabilities as reported on the Interim Consolidated
Statement of Financial Position.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING
INFORMATION AND STATEMENTS
Certain statements contained in this report,
including statements that contain words such as "could", "should",
"can", "anticipate", "estimate", "intend", "plan", "expect",
"believe", "will", "may", "continue", "project", "potential" and
similar expressions and statements relating to matters that are not
historical facts constitute "forward-looking information" within
the meaning of applicable Canadian securities legislation and
"forward-looking statements" within the meaning of the "safe
harbor" provisions of the United States Private Securities
Litigation Reform Act of 1995 (collectively, "forward-looking
information and statements").
In particular, forward looking information and
statements include, but are not limited to, the following:
- our strategic priorities for 2018;
- our capital expenditure plans for 2018;
- anticipated activity levels in 2018 and our scheduled
infrastructure projects;
- anticipated demand for Tier 1 rigs;
- the average number of term contracts in place for 2018 and
2019;
- expectation for U.S. operating costs to be lower in the fourth
quarter of 2018;
- our future debt reduction plans beyond 2018; and
- the anticipated financial, operational and strategic benefits
of the proposed Trinidad Drilling transaction.
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) |
|
September 30,2018 |
|
|
December 31,2017 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
109,762 |
|
|
$ |
65,081 |
|
Accounts receivable |
|
|
342,175 |
|
|
|
322,585 |
|
Income tax recoverable |
|
|
— |
|
|
|
29,449 |
|
Inventory |
|
|
32,115 |
|
|
|
24,631 |
|
Total current assets |
|
|
484,052 |
|
|
|
441,746 |
|
Non-current assets: |
|
|
|
|
|
|
|
|
Income tax recoverable |
|
|
2,307 |
|
|
|
2,256 |
|
Deferred tax assets |
|
|
33,518 |
|
|
|
41,822 |
|
Property, plant and equipment |
|
|
3,024,684 |
|
|
|
3,173,824 |
|
Intangibles |
|
|
35,406 |
|
|
|
28,116 |
|
Goodwill |
|
|
205,907 |
|
|
|
205,167 |
|
Total non-current assets |
|
|
3,301,822 |
|
|
|
3,451,185 |
|
Total assets |
|
$ |
3,785,874 |
|
|
$ |
3,892,931 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
$ |
257,449 |
|
|
$ |
209,625 |
|
Income taxes payable |
|
|
3,579 |
|
|
|
— |
|
Total current liabilities |
|
|
261,028 |
|
|
|
209,625 |
|
|
|
|
|
|
|
|
|
|
Non-current liabilities: |
|
|
|
|
|
|
|
|
Share based compensation |
|
|
10,328 |
|
|
|
13,536 |
|
Provisions and other |
|
|
9,674 |
|
|
|
10,086 |
|
Long-term debt |
|
|
1,698,651 |
|
|
|
1,730,437 |
|
Deferred tax liability |
|
|
76,279 |
|
|
|
118,911 |
|
Total non-current liabilities |
|
|
1,794,932 |
|
|
|
1,872,970 |
|
Shareholders’ equity: |
|
|
|
|
|
|
|
|
Shareholders’ capital |
|
|
2,322,280 |
|
|
|
2,319,293 |
|
Contributed surplus |
|
|
50,124 |
|
|
|
44,037 |
|
Deficit |
|
|
(780,546 |
) |
|
|
(684,604 |
) |
Accumulated other comprehensive income |
|
|
138,056 |
|
|
|
131,610 |
|
Total shareholders’ equity |
|
|
1,729,914 |
|
|
|
1,810,336 |
|
Total liabilities and shareholders’
equity |
|
$ |
3,785,874 |
|
|
$ |
3,892,931 |
|
INTERIM CONSOLIDATED STATEMENTS OF LOSS
(UNAUDITED)
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
(Stated in thousands of Canadian dollars,
except per share amounts) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
382,457 |
|
|
$ |
314,504 |
|
|
$ |
1,114,179 |
|
|
$ |
974,037 |
|
Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
271,596 |
|
|
|
218,936 |
|
|
|
782,649 |
|
|
|
692,347 |
|
General and administrative |
|
|
29,873 |
|
|
|
22,329 |
|
|
|
90,891 |
|
|
|
67,623 |
|
Earnings before income taxes, loss on repurchase and
redemption of unsecured senior notes, finance charges,
foreign exchange and depreciation and amortization |
|
|
80,988 |
|
|
|
73,239 |
|
|
|
240,639 |
|
|
|
214,067 |
|
Depreciation and amortization |
|
|
90,690 |
|
|
|
90,555 |
|
|
|
266,619 |
|
|
|
283,517 |
|
Operating loss |
|
|
(9,702 |
) |
|
|
(17,316 |
) |
|
|
(25,980 |
) |
|
|
(69,450 |
) |
Foreign exchange |
|
|
(952 |
) |
|
|
(685 |
) |
|
|
819 |
|
|
|
(1,436 |
) |
Finance charges |
|
|
31,176 |
|
|
|
32,218 |
|
|
|
94,958 |
|
|
|
99,732 |
|
Loss on repurchase and redemption of
unsecured senior notes |
|
|
— |
|
|
|
— |
|
|
|
1,176 |
|
|
|
— |
|
Loss before income taxes |
|
|
(39,926 |
) |
|
|
(48,849 |
) |
|
|
(122,933 |
) |
|
|
(167,746 |
) |
Income taxes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
1,231 |
|
|
|
89 |
|
|
|
6,396 |
|
|
|
339 |
|
Deferred |
|
|
(10,509 |
) |
|
|
(22,651 |
) |
|
|
(33,387 |
) |
|
|
(83,054 |
) |
|
|
|
(9,278 |
) |
|
|
(22,562 |
) |
|
|
(26,991 |
) |
|
|
(82,715 |
) |
Net loss |
|
$ |
(30,648 |
) |
|
$ |
(26,287 |
) |
|
$ |
(95,942 |
) |
|
|
(85,031 |
) |
Net loss per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted |
|
$ |
(0.10 |
) |
|
$ |
(0.09 |
) |
|
$ |
(0.33 |
) |
|
$ |
(0.29 |
) |
INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(UNAUDITED)
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
(Stated in thousands of Canadian dollars) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Net loss |
|
$ |
(30,648 |
) |
|
$ |
(26,287 |
) |
|
$ |
(95,942 |
) |
|
$ |
(85,031 |
) |
Unrealized gain (loss) on translation of assets and
liabilities of operations denominated in foreign
currency |
|
|
(46,370 |
) |
|
|
(79,729 |
) |
|
|
46,956 |
|
|
|
(155,691 |
) |
Foreign exchange gain (loss) on net investment hedge
with U.S. denominated debt, net of tax |
|
|
38,060 |
|
|
|
68,057 |
|
|
|
(40,510 |
) |
|
|
132,082 |
|
Comprehensive loss |
|
$ |
(38,958 |
) |
|
$ |
(37,959 |
) |
|
$ |
(89,496 |
) |
|
$ |
(108,640 |
) |
INTERIM CONSOLIDATED STATEMENTS OF CASH
FLOW (UNAUDITED)
|
|
Three Months Ended
September 30, |
|
|
Nine Months Ended
September 30, |
|
(Stated in thousands of Canadian
dollars) |
|
2018 |
|
|
2017 |
|
|
2018 |
|
|
2017 |
|
Cash provided by (used in): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(30,648 |
) |
|
$ |
(26,287 |
) |
|
$ |
(95,942 |
) |
|
$ |
(85,031 |
) |
Adjustments for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term compensation plans |
|
|
5,074 |
|
|
|
1,945 |
|
|
|
19,000 |
|
|
|
4,276 |
|
Depreciation and amortization |
|
|
90,690 |
|
|
|
90,555 |
|
|
|
266,619 |
|
|
|
283,517 |
|
Foreign exchange |
|
|
(1,648 |
) |
|
|
(239 |
) |
|
|
(215 |
) |
|
|
(1,593 |
) |
Finance charges |
|
|
31,176 |
|
|
|
32,218 |
|
|
|
94,958 |
|
|
|
99,732 |
|
Income taxes |
|
|
(9,278 |
) |
|
|
(22,562 |
) |
|
|
(26,991 |
) |
|
|
(82,715 |
) |
Other |
|
|
(109 |
) |
|
|
72 |
|
|
|
(1,242 |
) |
|
|
(705 |
) |
Loss on repurchase and redemption of
unsecured senior notes |
|
|
— |
|
|
|
— |
|
|
|
1,176 |
|
|
|
— |
|
Income taxes paid |
|
|
(363 |
) |
|
|
(539 |
) |
|
|
(3,969 |
) |
|
|
(3,300 |
) |
Income taxes recovered |
|
|
3,921 |
|
|
|
11,600 |
|
|
|
31,508 |
|
|
|
11,932 |
|
Interest paid |
|
|
(24,732 |
) |
|
|
(1,877 |
) |
|
|
(67,253 |
) |
|
|
(72,136 |
) |
Interest received |
|
|
285 |
|
|
|
254 |
|
|
|
970 |
|
|
|
1,635 |
|
Funds provided by operations |
|
|
64,368 |
|
|
|
85,140 |
|
|
|
218,619 |
|
|
|
155,612 |
|
Changes in non-cash working capital
balances |
|
|
(32,407 |
) |
|
|
(28,383 |
) |
|
|
(18,774 |
) |
|
|
(62,346 |
) |
|
|
|
31,961 |
|
|
|
56,757 |
|
|
|
199,845 |
|
|
|
93,266 |
|
Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of property, plant and equipment |
|
|
(28,367 |
) |
|
|
(15,761 |
) |
|
|
(84,982 |
) |
|
|
(57,320 |
) |
Purchase of intangibles |
|
|
(660 |
) |
|
|
(6,757 |
) |
|
|
(10,880 |
) |
|
|
(15,727 |
) |
Proceeds on sale of property, plant and
equipment |
|
|
3,757 |
|
|
|
4,273 |
|
|
|
12,437 |
|
|
|
10,054 |
|
Changes in non-cash working capital
balances |
|
|
10,114 |
|
|
|
(150 |
) |
|
|
2,082 |
|
|
|
(10,716 |
) |
|
|
|
(15,156 |
) |
|
|
(18,395 |
) |
|
|
(81,343 |
) |
|
|
(73,709 |
) |
Financing: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt amendment fees |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(341 |
) |
Redemption and repayment of unsecured senior
notes |
|
|
— |
|
|
|
— |
|
|
|
(76,657 |
) |
|
|
— |
|
Issuance of common shares on the exercise
of options |
|
|
275 |
|
|
|
— |
|
|
|
275 |
|
|
|
— |
|
|
|
|
275 |
|
|
|
— |
|
|
|
(76,382 |
) |
|
|
(341 |
) |
Effect of exchange rate changes on cash and
cash equivalents |
|
|
(1,987 |
) |
|
|
(1,684 |
) |
|
|
2,561 |
|
|
|
(3,179 |
) |
Increase in cash and cash equivalents |
|
|
15,093 |
|
|
|
36,678 |
|
|
|
44,681 |
|
|
|
16,037 |
|
Cash and cash equivalents, beginning of
period |
|
|
94,669 |
|
|
|
95,064 |
|
|
|
65,081 |
|
|
|
115,705 |
|
Cash and cash equivalents, end of period |
|
$ |
109,762 |
|
|
$ |
131,742 |
|
|
$ |
109,762 |
|
|
$ |
131,742 |
|
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 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(95,942 |
) |
|
|
(95,942 |
) |
Other comprehensive income for the period |
|
|
— |
|
|
|
— |
|
|
|
6,446 |
|
|
|
— |
|
|
|
6,446 |
|
Shares issued on redemption of non-management directors'
DSUs |
|
|
2,609 |
|
|
|
(809 |
) |
|
|
— |
|
|
|
— |
|
|
|
1,800 |
|
Share options exercised |
|
|
378 |
|
|
|
(103 |
) |
|
|
— |
|
|
|
— |
|
|
|
275 |
|
Share based compensation expense |
|
|
— |
|
|
|
6,999 |
|
|
|
— |
|
|
|
— |
|
|
|
6,999 |
|
Balance at September 30,
2018 |
|
$ |
2,322,280 |
|
|
$ |
50,124 |
|
|
$ |
138,056 |
|
|
$ |
(780,546 |
) |
|
$ |
1,729,914 |
|
(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 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(85,031 |
) |
|
|
(85,031 |
) |
Other comprehensive loss for the period |
|
|
— |
|
|
|
— |
|
|
|
(23,609 |
) |
|
|
— |
|
|
|
(23,609 |
) |
Share based compensation expense |
|
|
— |
|
|
|
3,904 |
|
|
|
— |
|
|
|
— |
|
|
|
3,904 |
|
Balance at September 30, 2017 |
|
$ |
2,319,293 |
|
|
$ |
42,841 |
|
|
$ |
132,847 |
|
|
$ |
(637,599 |
) |
|
$ |
1,857,382 |
|
|
|
THIRD 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, October 25, 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 October 30, 2018 by dialing 1-855-859-2056 or
404-537-3406, pass code 4795636.
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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