CALGARY, Alberta, July 26, 2018 (GLOBE NEWSWIRE) -- (Canadian dollars except as indicated)
This news release contains “forward-looking information and statements” within the meaning of applicable securities laws. For a full disclosure of the forward-looking information and statements and the risks to which they are subject, see the “Cautionary Statement Regarding Forward-Looking Information and Statements” later in this news release. This news release contains references to Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies, see “Non-GAAP Measures” later in this news release.
Precision Drilling announces 2018 second quarter financial results:
Precision’s President and CEO Kevin Neveu stated: “Precision’s strong second quarter results were driven by continued growth in North American activity, having achieved our highest U.S. market share to date. Additionally, we captured higher day rates and margins in both markets. We attribute our market share gains and sequential rate increases to customers’ intense focus on capital efficiency which leads them to contract the best performing and most efficient drilling rigs and crews, lowering total well-pad cost.”
“During the quarter, we activated eight rigs in the U.S. and currently have 78 rigs running with visibility for four to six additional activations in the coming weeks. We believe customer focus on efficiency and cost may intensify, presenting additional growth opportunities for Precision. With established positions in all major U.S. shale plays and proven performance of our Super Series rigs we are in a strong position to take advantage of increased activity and customer capital reallocation. A similar trend is evident in Canada where despite flat year-over-year customer spending we already have 60 rigs active, surpassing last year’s third quarter peak. We expect Precision’s year-over-year growth in activity to continue through the third quarter.”
“We continue to demonstrate positive momentum with regard to our key strategic priorities for the year. First and foremost, we have reached the low end of our stated 2018 debt reduction range, reducing debt by $75 million year-to-date. Next, our financial performance has improved year-over-year through increased activity, pricing and margins in North America with particular strength in the U.S. Lastly, as it relates to technology, demand continues to improve for PAC (Process Automation Control), DGS (Directional Guidance System), and Drilling Performance Applications (Apps) with full commercialization expected by year end. We are purchasing ten additional PAC systems that will be deployed on our rigs in the second half of the year bringing us to 31 Super Series rigs in the field with PAC.”
“In the U.S., our High Performance field results are also showing up in our pricing and margins and I am pleased to report both day rates and margins per day increased nearly US$1,200 quarter-over-quarter with no increase in daily operating costs. I expect to see continued increases in our average rates and margins throughout the second half of the year with continued strength in pricing, further value capture from our technology initiatives and continued fixed cost leverage. In Canada, Precision’s activity levels increased 7% year-over-year outperforming the 3% increase in industry drilling days. In addition, day rates excluding shortfall revenue increased approximately $1,400 per day year-over-year largely as a result of improved spot pricing. Since our last earnings announcement Precision signed ten term contracts in the U.S. and two term contracts in Canada, which coupled with our activity increase and improved day rates, is a clear indication of continued customer alignment with our High Performance, High Value service offering.”
“Internationally, we previously announced our newbuild rig contract in Kuwait strengthening our Middle East footprint and increasing our Kuwait active rig count to six rigs by the third quarter of 2019. We are adding this newbuild with no increase in fixed costs, supported by sufficient scale in country. In the Kingdom of Saudi Arabia, three rigs are currently active, two of which roll off contract next month and we fully expect them to be re-contracted. We are actively bidding our four idle rigs in the Middle East and believe the prospects to activate these rigs are improving.”
“Customer adoption of PAC is strengthening and we have completed several analytical field case studies demonstrating the system’s ability to consistently and repeatedly deliver high quality wells while improving safety, performance and efficiency of operations. Our DGS technology is also gaining momentum having now drilled over two million feet to date utilizing the software including over 70 wells in 2018. Additionally, we are deploying revenue generating Apps on several rigs and currently have 12 Apps in varying stages of commercial development showcasing the open platform of our PAC system. Several Apps are customer-built and supported by Precision’s PAC platform with specific hosting agreements in place. We are pleased our technology initiatives are beginning to impact our revenue and margins.”
“Our updated 2018 capital plan is approximately $135 million. The $19 million increase from our previous update includes spending for our newbuild award in Kuwait, completion of a newbuild in the U.S., foreign exchange impact from a weaker Canadian dollar, and a minor increase in upgrade capital spending. With $95 million of cash on the balance sheet coupled with cash flow in the second half of the year I fully expect to fund growth and upgrade opportunities while reserving capacity to retire more of our debt,” concluded Mr. Neveu.
SELECT FINANCIAL AND OPERATING INFORMATION
Adjusted EBITDA and funds provided by (used in) operations are Non-GAAP measures. See “NON-GAAP MEASURES.”
Financial Highlights
Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
(Stated in thousands of Canadian dollars, except per share amounts) | 2018 | 2017 | % Change | 2018 | 2017 | % Change | |||||||||||||||||
Revenue(1) | 330,716 | 290,860 | 13.7 | 731,722 | 659,533 | 10.9 | |||||||||||||||||
Adjusted EBITDA(2) | 62,182 | 56,520 | 10.0 | 159,651 | 140,828 | 13.4 | |||||||||||||||||
Net loss | (47,217 | ) | (36,130 | ) | 30.7 | (65,294 | ) | (58,744 | ) | 11.2 | |||||||||||||
Cash provided by operations | 129,695 | 2,739 | 4,635.1 | 167,884 | 36,509 | 359.8 | |||||||||||||||||
Funds provided by (used in) operations(2) | 50,225 | (15,187 | ) | (430.7 | ) | 154,251 | 70,472 | 118.9 | |||||||||||||||
Capital spending: | |||||||||||||||||||||||
Expansion | 15,786 | 4,852 | 225.4 | 16,471 | 8,644 | 90.5 | |||||||||||||||||
Upgrade | 5,447 | 13,287 | (59.0 | ) | 16,810 | 26,934 | (37.6 | ) | |||||||||||||||
Maintenance and infrastructure | 13,091 | 2,997 | 336.8 | 23,334 | 5,981 | 290.1 | |||||||||||||||||
Intangibles | 2,429 | 7,301 | (66.7 | ) | 10,220 | 8,970 | 13.9 | ||||||||||||||||
Proceeds on sale | (2,630 | ) | (3,563 | ) | (26.2 | ) | (8,680 | ) | (5,781 | ) | 50.1 | ||||||||||||
Net capital spending | 34,123 | 24,874 | 37.2 | 58,155 | 44,748 | 30.0 | |||||||||||||||||
Net loss per share: | |||||||||||||||||||||||
Basic | (0.16 | ) | (0.12 | ) | 33.3 | (0.22 | ) | (0.20 | ) | 10.0 | |||||||||||||
Diluted | (0.16 | ) | (0.12 | ) | 33.3 | (0.22 | ) | (0.20 | ) | 10.0 |
(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.
(2) See “NON-GAAP MEASURES”.
Operating Highlights
Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
2018 | 2017 | % Change | 2018 | 2017 | % Change | ||||||||||||||||||
Contract drilling rig fleet | 257 | 256 | 0.4 | 257 | 256 | 0.4 | |||||||||||||||||
Drilling rig utilization days: | |||||||||||||||||||||||
Canada | 2,834 | 2,639 | 7.4 | 9,302 | 9,458 | (1.6 | ) | ||||||||||||||||
U.S. | 6,588 | 5,331 | 23.6 | 12,383 | 9,521 | 30.1 | |||||||||||||||||
International | 728 | 728 | - | 1,448 | 1,448 | - | |||||||||||||||||
Revenue per utilization day: | |||||||||||||||||||||||
Canada(1)(2) (Cdn$) | 22,072 | 22,177 | (0.5 | ) | 22,167 | 21,620 | 2.5 | ||||||||||||||||
U.S.(1)(3) (US$) | 21,795 | 19,826 | 9.9 | 21,237 | 20,147 | 5.4 | |||||||||||||||||
International (US$) | 49,832 | 49,679 | 0.3 | 49,935 | 50,054 | (0.2 | ) | ||||||||||||||||
Operating cost per utilization day: | |||||||||||||||||||||||
Canada (Cdn$) | 16,712 | 16,368 | 2.1 | 14,361 | 13,815 | 4.0 | |||||||||||||||||
U.S. (US$) | 14,026 | 14,248 | (1.6 | ) | 14,026 | 14,695 | (4.6 | ) | |||||||||||||||
Service rig fleet | 210 | 210 | - | 210 | 210 | - | |||||||||||||||||
Service rig operating hours | 31,824 | 33,813 | (5.9 | ) | 84,525 | 85,870 | (1.6 | ) | |||||||||||||||
Revenue per operating hour (Cdn$) | 676 | 629 | 7.5 | 691 | 633 | 9.2 |
(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.
(2) Includes lump sum revenue from contract shortfall for the six months ended June 30, 2018 and prior year comparatives.
(3) 2017 comparative periods include revenue from idle but contracted rig days.
Financial Position
(Stated in thousands of Canadian dollars, except ratios) | June 30, 2018 | December 31, 2017 | |||||
Working capital(1) | 196,149 | 232,121 | |||||
Cash | 94,669 | 65,081 | |||||
Long-term debt(2) | 1,735,842 | 1,730,437 | |||||
Total long-term financial liabilities | 1,753,580 | 1,754,059 | |||||
Total assets | 3,858,221 | 3,892,931 | |||||
Long-term debt to long-term debt plus equity ratio | 0.50 | 0.49 |
(1) See “NON-GAAP MEASURES”.
(2) Net of unamortized debt issue costs.
Summary for the three months ended June 30, 2018:
Summary for the six months ended June 30, 2018:
STRATEGY
Precision’s strategic priorities for 2018 are as follows:
OUTLOOK
For the second quarter of 2018, the average West Texas Intermediate price of oil was 41% higher than the prior year comparative period while the average Henry Hub gas price was 3% lower and the average AECO price was 55% lower.
Three months ended June 30, | Year ended December 31, | |||||||||
2018 | 2017 | 2017 | ||||||||
Average oil and natural gas prices | ||||||||||
Oil | ||||||||||
West Texas Intermediate (per barrel) (US$) | 67.91 | 48.33 | 50.95 | |||||||
Natural gas | ||||||||||
Canada | ||||||||||
AECO (per MMBtu) (CDN$) | 1.20 | 2.69 | 2.16 | |||||||
United States | ||||||||||
Henry Hub (per MMBtu) (US$) | 2.86 | 2.94 | 2.98 |
Contracts
Year to date in 2018 we have entered into 38 term contracts. The following chart outlines the average number of drilling rigs by quarter that we had under contract for 2017, the first two quarters of 2018 and the average number of drilling rigs by quarter we have under contract for 2018 as of July 25, 2018.
Average for the quarter ended 2017 | Average for the quarter ended 2018 | |||||||||||||||||||||||||||||||
Mar. 31 | June 30 | Sept. 30 | Dec. 31 | Mar. 31 | June 30 | Sept. 30 | Dec. 31 | |||||||||||||||||||||||||
Average rigs under term contract as at July 25, 2018: | ||||||||||||||||||||||||||||||||
Canada | 27 | 23 | 19 | 12 | 8 | 9 | 9 | 9 | ||||||||||||||||||||||||
U.S. | 26 | 33 | 31 | 27 | 36 | 48 | 47 | 35 | ||||||||||||||||||||||||
International | 8 | 8 | 8 | 8 | 8 | 8 | 7 | 6 | ||||||||||||||||||||||||
Total | 61 | 64 | 58 | 47 | 52 | 65 | 63 | 50 |
The following chart outlines the average number of drilling rigs that we had under contract for 2017 and the average number of rigs we have under contract for 2018 as of July 25, 2018.
Average for the year ended | ||||||||
2017 | 2018 | |||||||
Average rigs under term contract as at July 25, 2018: | ||||||||
Canada | 20 | 9 | ||||||
U.S. | 29 | 42 | ||||||
International | 8 | 7 | ||||||
Total | 57 | 58 |
In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.
Drilling Activity
The following chart outlines the average number of drilling rigs that we had working or moving by quarter for the periods noted.
Average for the quarter ended 2017 | 2018 | ||||||||||||||||||||||
Mar. 31 | June 30 | Sept. 30 | Dec. 31 | Mar. 31 | June 30 | ||||||||||||||||||
Average Precision active rig count: | |||||||||||||||||||||||
Canada | 76 | 29 | 49 | 54 | 72 | 31 | |||||||||||||||||
U.S. | 47 | 59 | 61 | 58 | 64 | 72 | |||||||||||||||||
International | 8 | 8 | 8 | 8 | 8 | 8 | |||||||||||||||||
Total | 131 | 96 | 118 | 120 | 144 | 111 |
For the first half of 2018, drilling activity has increased relative to this time last year in the U.S. and is down slightly in Canada. According to industry sources, as of July 20, 2018, the U.S. active land drilling rig count was up approximately 11% from the same point last year and the Canadian active land drilling rig count was down approximately 2%. To date in 2018, approximately 63% of the Canadian industry’s active rigs and 81% of the U.S. industry’s active rigs were drilling for oil targets, compared with 53% for Canada and 80% for the U.S. at the same time last year.
Industry Conditions
We expect Tier 1 rigs to remain the preferred rigs of customers globally. The economic value created by the significant drilling and mobility efficiencies delivered by the most advanced XY pad walking rigs has been highlighted and widely accepted by our customers. The trend to longer-reach horizontal completions and importance of the rig delivering these complex wells consistently and efficiently has been well established by the industry. We expect demand for leading edge high efficiency Tier 1 rigs will continue to strengthen, as drilling rig capability has been a key economic facilitator of horizontal/unconventional resource exploitation. Development and field application of drilling equipment process automation coupled with closed loop drilling controls and de-manning of rigs will continue this technical evolution while creating further cost efficiencies and performance value for customers.
Capital Spending
Capital spending in 2018 is expected to be $135 million and includes $72 million for sustaining and infrastructure, $48 million for upgrade and expansion and $15 million on intangibles related to a new ERP system. We expect that the $135 million will be split $113 million in the Contract Drilling Services segment, $6 million in the Completion and Production Services segment and $16 million to the Corporate segment.
SEGMENTED FINANCIAL RESULTS
Precision’s operations are reported in two segments: Contract Drilling Services, which includes the drilling rig, directional drilling, oilfield supply and manufacturing divisions; and Completion and Production Services, which includes the service rig, snubbing, rental, camp and catering and wastewater treatment divisions.
Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
(Stated in thousands of Canadian dollars) | 2018 | 2017 | % Change | 2018 | 2017 | % Change | |||||||||||||||||
Revenue:(1) | |||||||||||||||||||||||
Contract Drilling Services | 304,353 | 262,458 | 16.0 | 657,155 | 586,388 | 12.1 | |||||||||||||||||
Completion and Production Services | 27,706 | 29,381 | (5.7 | ) | 77,748 | 75,730 | 2.7 | ||||||||||||||||
Inter-segment eliminations | (1,343 | ) | (979 | ) | 37.2 | (3,181 | ) | (2,585 | ) | 23.1 | |||||||||||||
330,716 | 290,860 | 13.7 | 731,722 | 659,533 | 10.9 | ||||||||||||||||||
Adjusted EBITDA:(2) | |||||||||||||||||||||||
Contract Drilling Services | 83,441 | 67,031 | 24.5 | 194,407 | 160,696 | 21.0 | |||||||||||||||||
Completion and Production Services | (1,402 | ) | 336 | (517.3 | ) | 3,242 | 4,923 | (34.1 | ) | ||||||||||||||
Corporate and other | (19,857 | ) | (10,847 | ) | 83.1 | (37,998 | ) | (24,791 | ) | 53.3 | |||||||||||||
62,182 | 56,520 | 10.0 | 159,651 | 140,828 | 13.4 |
(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.
(2) See “NON-GAAP MEASURES”.
SEGMENT REVIEW OF CONTRACT DRILLING SERVICES
Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
(Stated in thousands of Canadian dollars, except where noted) | 2018 | 2017 | % Change | 2018 | 2017 | % Change | |||||||||||||||||
Revenue(1) | 304,353 | 262,458 | 16.0 | 657,155 | 586,388 | 12.1 | |||||||||||||||||
Expenses: | |||||||||||||||||||||||
Operating(1) | 211,008 | 188,080 | 12.2 | 444,156 | 408,897 | 8.6 | |||||||||||||||||
General and administrative | 9,904 | 7,347 | 34.8 | 18,592 | 16,795 | 10.7 | |||||||||||||||||
Adjusted EBITDA(2) | 83,441 | 67,031 | 24.5 | 194,407 | 160,696 | 21.0 | |||||||||||||||||
Depreciation | 80,179 | 85,065 | (5.7 | ) | 157,879 | 171,254 | (7.8 | ) | |||||||||||||||
Operating earnings (loss)(2) | 3,262 | (18,034 | ) | (118.1 | ) | 36,528 | (10,558 | ) | (446.0 | ) | |||||||||||||
Operating earnings (loss)(2) as a percentage of revenue | 1.1 | % | (6.9 | )% | 5.6 | % | (1.8 | )% |
(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.
(2) See “NON-GAAP MEASURES”.
Three months ended June 30, | ||||||||||||||||
Canadian onshore drilling statistics:(1) | 2018 | 2017 | ||||||||||||||
Precision | Industry(2) | Precision | Industry(2) | |||||||||||||
Number of drilling rigs (end of period) | 135 | 618 | 136 | 634 | ||||||||||||
Drilling rig operating days (spud to release) | 2,526 | 9,536 | 2,358 | 9,252 | ||||||||||||
Drilling rig operating day utilization | 21 | % | 17 | % | 19 | % | 16 | % | ||||||||
Number of wells drilled | 227 | 903 | 267 | 1,024 | ||||||||||||
Average days per well | 11.1 | 10.6 | 8.8 | 9.0 | ||||||||||||
Number of metres drilled (000s) | 731 | 2,756 | 758 | 2,928 | ||||||||||||
Average metres per well | 3,218 | 3,052 | 2,839 | 2,859 | ||||||||||||
Average metres per day | 289 | 289 | 321 | 316 |
Six months ended June 30, | ||||||||||||||||
Canadian onshore drilling statistics:(1) | 2018 | 2017 | ||||||||||||||
Precision | Industry(2) | Precision | Industry(2) | |||||||||||||
Number of drilling rigs (end of period) | 135 | 618 | 136 | 634 | ||||||||||||
Drilling rig operating days (spud to release) | 8,180 | 32,381 | 8,400 | 32,756 | ||||||||||||
Drilling rig operating day utilization | 34 | % | 29 | % | 34 | % | 28 | % | ||||||||
Number of wells drilled | 742 | 3,133 | 831 | 3,308 | ||||||||||||
Average days per well | 11.0 | 10.3 | 10.1 | 9.9 | ||||||||||||
Number of metres drilled (000s) | 2,228 | 9,201 | 2,229 | 9,088 | ||||||||||||
Average metres per well | 3,003 | 2,937 | 2,682 | 2,747 | ||||||||||||
Average metres per day | 272 | 284 | 265 | 277 |
(1) Canadian operations only.
(2) Canadian Association of Oilwell Drilling Contractors (“CAODC”), and Precision – excludes non-CAODC rigs and non-reporting CAODC members.
United States onshore drilling statistics:(1) | 2018 | 2017 | |||||||||||||
Precision | Industry(2) | Precision | Industry(2) | ||||||||||||
Average number of active land rigs for quarters ended: | |||||||||||||||
March 31 | 64 | 951 | 47 | 722 | |||||||||||
June 30 | 72 | 1,021 | 59 | 874 | |||||||||||
Year to date average | 68 | 986 | 53 | 798 |
(1) United States lower 48 operations only.
(2) Baker Hughes rig counts.
Revenue from Contract Drilling Services was $304 million this quarter, or 16% higher than the second quarter of 2017, while adjusted EBITDA increased by 24% to $83 million. The increase in revenue was primarily due to higher utilization days in the United States. During the quarter we did not recognize any shortfall payments in our Canadian contract drilling business compared with $4 million in the prior year comparative period. In the U.S. we recognized turnkey revenue of US$10 million compared with US$5 million in the comparative period and we did not recognize any idle but contracted revenue compared with US$2 million in the comparative quarter of 2017.
Drilling rig utilization days in Canada (drilling days plus move days) were 2,834 during the second quarter of 2018, an increase of 7% compared to 2017 primarily due to increased Deep Basin activity with several customers working pad rigs through spring break-up. Drilling rig utilization days in the U.S. were 6,588, or 24% higher than the same quarter of 2017 as our U.S. activity was up with higher industry activity. Drilling rig utilization days in our international business were 728, in-line with the same quarter of 2017.
Compared with the same quarter in 2017, drilling rig revenue per utilization day in Canada was in-line with last year as increases in spot market rates in the current quarter offset lower shortfall revenue and a higher number of rigs under long-term contract in the prior period. Drilling rig revenue per utilization day for the quarter in the U.S. was up 10% compared to prior year as higher average day rates and higher turnkey revenue were partially offset by lower lump sum move revenue and lower idle but contract revenue. International revenue per utilization day was in-line with the prior year comparative period.
In Canada, 8% of our utilization days in the quarter were generated from rigs under term contract, compared with 31% in the second quarter of 2017. In the U.S., 67% of utilization days were generated from rigs under term contract as compared with 57% in the second quarter of 2017.
Operating costs were 69% of revenue for the quarter which was two percentage points lower than the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were slightly higher than the prior year period primarily driven by larger average crew sizes associated with increased pad rig activity in the quarter. In the U.S., operating costs for the quarter on a per day basis were slightly lower than the prior year period primarily due to higher lump sum move costs in the prior period and the impact of fixed costs spread over higher activity partially offset by higher costs associated with turnkey activity.
Depreciation expense in the quarter was 6% lower than in the second quarter of 2017. The decrease in depreciation expense was primarily due to the strengthening of the Canadian dollar on our U.S. dollar denominated costs and a lower capital asset base as assets become fully depreciated.
SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES
Three months ended June 30, | Six months ended June 30, | ||||||||||||||||||||||
(Stated in thousands of Canadian dollars, except where noted) | 2018 | 2017 | % Change | 2018 | 2017 | % Change | |||||||||||||||||
Revenue | 27,706 | 29,381 | (5.7 | ) | 77,748 | 75,730 | 2.7 | ||||||||||||||||
Expenses: | |||||||||||||||||||||||
Operating | 26,814 | 27,231 | (1.5 | ) | 70,078 | 67,099 | 4.4 | ||||||||||||||||
General and administrative | 2,294 | 1,814 | 26.5 | 4,428 | 3,708 | 19.4 | |||||||||||||||||
Adjusted EBITDA(1) | (1,402 | ) | 336 | (517.3 | ) | 3,242 | 4,923 | (34.1 | ) | ||||||||||||||
Depreciation | 5,012 | 7,094 | (29.3 | ) | 11,887 | 14,497 | (18.0 | ) | |||||||||||||||
Operating loss(1) | (6,414 | ) | (6,758 | ) | (5.1 | ) | (8,645 | ) | (9,574 | ) | (9.7 | ) | |||||||||||
Operating loss(1) as a percentage of revenue | (23.2 | )% | (23.0 | )% | (11.1 | )% | (12.6 | )% | |||||||||||||||
Well servicing statistics: | |||||||||||||||||||||||
Number of service rigs (end of period) | 210 | 210 | - | 210 | 210 | - | |||||||||||||||||
Service rig operating hours | 31,824 | 33,813 | (5.9 | ) | 84,525 | 85,870 | (1.6 | ) | |||||||||||||||
Service rig operating hour utilization | 17 | % | 18 | % | (5.6 | ) | 22 | % | 23 | % | (4.3 | ) | |||||||||||
Service rig revenue per operating hour | 676 | 629 | 7.5 | 691 | 633 | 9.2 |
(1) See “NON-GAAP MEASURES”.
Revenue from Completion and Production Services was down $2 million or 6% compared with the second quarter of 2017 due to lower activity in our Canadian well servicing and rental businesses partially offset by higher camp activity. Our service rig operating hours in the quarter were down 6% from the second quarter of 2017 while rates increased an average of 7%. Approximately 98% of our second quarter Canadian service rig activity was oil related.
During the quarter, Completion and Production Services generated 88% of its revenue from Canadian operations and 12% from U.S. operations compared with the second quarter of 2017 where 86% of revenue was generated in Canada and 14% in the U.S.
Average service rig revenue per operating hour in the quarter was $676 or $47 higher than the second quarter of 2017. The increase was primarily the result of increased costs passed through to the customer.
Adjusted EBITDA was lower than the second quarter of 2017 primarily due to reorganization costs of $1 million incurred in the current quarter.
Operating costs as a percentage of revenue was 97% compared with the prior year comparative quarter of 93%.
Depreciation in the quarter was $2 million lower than the prior year comparative period. The lower depreciation is due to a lower asset base as assets become fully depreciated.
SEGMENT REVIEW OF CORPORATE AND OTHER
Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA loss of $20 million, a $9 million increase compared with the second quarter of 2017 primarily due to higher share-based incentive compensation.
OTHER ITEMS
Share-based Incentive Compensation Plans
We have several cash-settled share-based incentive plans for non-management directors, officers, and other eligible employees. The fair values of the amounts payable under these plans are recognized as an expense with a corresponding increase in liabilities over the period that the participant becomes entitled to payment. The recorded liability is re-established at the end of each reporting period until settlement with the resultant change to fair value of the liability recognized in net earnings (loss) for the period.
We also have two equity-settled share-based incentive plans. Under the Executive Performance Share plan, which commenced in May 2017, the fair value of the PSUs granted is calculated at the date of grant using a Monte Carlo simulation, and that value is recorded as compensation expense over the grant's vesting period with an offset to contributed surplus. Upon redemption of the PSUs into common shares, the associated amount is reclassified from contributed surplus to shareholders' capital. The share option plan is treated similarly, except that the fair value of the share purchased options granted are valued using the Black-Scholes option pricing model and consideration paid by employees upon exercise of the equity purchase options are recognized in share capital.
A summary of the amounts expensed (recovered) under these plans during the reporting periods are as follows:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(Stated in thousands of Canadian dollars) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Cash settled share-based incentive plans | 7,681 | (4,452 | ) | 15,471 | (2,314 | ) | |||||||||
Equity settled share-based incentive plans | |||||||||||||||
Executive PSU | 1,696 | 821 | 2,749 | 821 | |||||||||||
Stock option plan | 901 | 587 | 1,718 | 1,720 | |||||||||||
Total share-based incentive compensation plan expense | 10,278 | (3,044 | ) | 19,938 | 227 | ||||||||||
Allocated: | |||||||||||||||
Operating | 3,305 | (944 | ) | 6,801 | 434 | ||||||||||
General and Administrative | 6,973 | (2,100 | ) | 13,137 | (207 | ) | |||||||||
10,278 | (3,044 | ) | 19,938 | 227 |
Cash settled shared-based compensation expense increased $12 million in the current quarter to $8 million compared to a recovery of $4 million in the same quarter in 2017. The increase is primarily due to the increasing share price experienced in the current quarter compared to a declining share price in the comparative 2017 period.
Executive PSU share-based incentive compensation expense for the quarter was $2 million compared to $1 million in the same quarter in 2017. This increase is a result of the plan being implemented part way through the second quarter in 2017 and from additional grants in 2018.
Financing Charges
Net financial charges for the quarter were $32 million, a decrease of $2 million compared with the second quarter of 2017 primarily because of a stronger Canadian dollar on our U.S. dollar denominated interest expense, reduction in interest expense related to debt retired in 2017 and higher interest income in the current period.
Loss on Repurchase and Redemption of Unsecured Senior Notes
During the quarter we redeemed US$50 million of our 6.5% unsecured senior notes due 2021 and repurchased and cancelled US$3 million principal amount of our 2021 notes and US$5 million principal amount of our 2024 notes incurring a net loss of $1 million.
Income Tax
Income tax expense for the quarter was a recovery of $13 million compared with a recovery of $37 million in the same quarter in 2017. The recoveries are due to negative pretax earnings.
LIQUIDITY AND CAPITAL RESOURCES
The oilfield services business is inherently cyclical in nature. To manage this, we focus on maintaining a strong balance sheet so we have the financial flexibility we need to continue to manage our growth and cash flow, regardless of where we are in the business cycle. We maintain a variable operating cost structure so we can be responsive to changes in demand.
Our maintenance capital expenditures are tightly governed by and highly responsive to activity levels with additional cost savings leverage provided through our internal manufacturing and supply divisions. Term contracts on expansion capital for new-build rig programs provide more certainty of future revenues and return on our capital investments.
Liquidity
Amount | Availability | Used for | Maturity | |||
Senior facility (secured) | ||||||
US$500 million (extendible, revolving term credit facility with US$250 million(1) accordion feature) | Undrawn, except US$28 million in outstanding letters of credit | General corporate purposes | November 21, 2021 | |||
Operating facilities (secured) | ||||||
$40 million | Undrawn, except $29 million in outstanding letters of credit | Letters of credit and general corporate purposes | ||||
US$15 million | Undrawn | Short term working capital requirements | ||||
Demand letter of credit facility (secured) | ||||||
US$30 million | Undrawn, except US$13 million in outstanding letters of credit | Letters of credit | ||||
Unsecured senior notes (unsecured) | ||||||
US$196 million – 6.5% | Fully drawn | Capital expenditures and general corporate purposes | December 15, 2021 | |||
US$350 million – 7.75% | Fully drawn | Debt redemption and repurchases | December 15, 2023 | |||
US$395 million – 5.25% | Fully drawn | Capital expenditures and general corporate purposes | November 15, 2024 | |||
US$400 million – 7.125% | Fully drawn | Debt redemption and repurchases | January 15, 2026 |
(1) Increases to US$300 million at the end of the covenant relief period of March 31, 2019.
As at June 30, 2018, we had $1,762 million outstanding under our unsecured senior notes. The current blended cash interest cost of our debt is approximately 6.6%.
Covenants
Following is a listing of our currently applicable financial covenants and the calculations as at June 30, 2018.
Covenant | As at June 30, 2018 | ||||
Senior Facility | |||||
Consolidated senior debt to consolidated Covenant EBITDA(1) | < 2.50 | 0.08 | |||
Consolidated Covenant EBITDA to consolidated interest expense | > 2.00 | 2.98 | |||
Unsecured Senior Notes | |||||
Consolidated interest coverage ratio | > 2.00 | 2.39 |
(1) For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.
At June 30, 2018, we were in compliance with the covenants of our senior credit facility and unsecured senior notes.
Senior Facility
The senior credit facility requires that we comply with certain covenants including a leverage ratio of consolidated senior debt to consolidated Covenant EBITDA (see “NON-GAAP MEASURES”) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.
Under the senior credit facility, we are required to maintain a ratio of consolidated Covenant EBITDA to consolidated interest expense for the most recent four consecutive quarters, of greater than 2.0:1 for the periods ending June 30, September 30, and December 31, 2018 and March 31, 2019. For periods ending after March 31, 2019 the ratio reverts to 2.5:1.
The senior credit facility prevents us from making distributions prior to April 1, 2019, after which, distributions are subject to a pro forma consolidated senior net leverage covenant of less than or equal to 1.75:1. The senior credit facility also limits the redemption and repurchase of junior debt subject to a pro forma consolidated senior net leverage covenant ratio of less than or equal to 1.75:1.
In addition, the senior credit facility contains certain covenants that place restrictions on our ability to incur or assume additional indebtedness; dispose of assets; pay dividends, undertake share redemptions or other distributions; change our primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or amalgamations; and enter into speculative swap agreements.
Unsecured Senior Notes
The senior notes require that we comply with financial covenants including an incurrence based consolidated interest coverage ratio test of consolidated cash flow, as defined in the senior note agreements, to consolidated interest expense of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our consolidated interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness.
The senior notes contain a restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and for repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2021 and 2024 senior notes, from October 1, 2016 for the 2023 senior notes and October 1, 2017 for the 2026 senior notes by, among other things, 50% of consolidated cumulative net earnings and decreases by 100% of consolidated cumulative net losses, as defined in the note agreements, and payments made to shareholders. Beginning with the December 31, 2015 calculation the governing net restricted payments basket was negative and as of that date we were no longer able to declare and make dividend payments until such time as the restricted payments baskets once again become positive. For further information, please see the senior note indentures which are available on SEDAR and EDGAR.
In addition, the senior notes contain certain covenants that limit our ability, and the ability of certain subsidiaries, to incur additional indebtedness and issue preferred shares; create liens; create or permit to exist restrictions on our ability or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and engage in transactions with affiliates.
Hedge of investments in foreign operations
We utilize foreign currency long-term debt to hedge our exposure to changes in the carrying values of our net investment in certain foreign operations as a result of changes in foreign exchange rates.
We have designated our U.S. dollar denominated long-term debt as a net investment hedge in our U.S. operations and other foreign operations that have a U.S. dollar functional currency. To be accounted for as a hedge, the foreign currency denominated long-term debt must be designated and documented as such and must be effective at inception and on an ongoing basis. We recognize the effective amount of this hedge (net of tax) in other comprehensive income. We recognize ineffective amounts (if any) in net earnings (loss).
Average shares outstanding
The following table reconciles the weighted average shares outstanding used in computing basic and diluted net loss per share:
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(Stated in thousands) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Weighted average shares outstanding – basic | 293,471 | 293,239 | 293,355 | 293,239 | |||||||||||
Effect of stock options and other equity compensation plans | — | — | — | — | |||||||||||
Weighted average shares outstanding – diluted | 293,471 | 293,239 | 293,355 | 293,239 |
QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per share amounts) | 2017 | 2018 | ||||||||||||||
Quarters ended | September 30 | December 31 | March 31 | June 30 | ||||||||||||
Revenue(1) | 314,504 | 347,187 | 401,006 | 330,716 | ||||||||||||
Adjusted EBITDA(2) | 73,239 | 90,914 | 97,469 | 62,182 | ||||||||||||
Net loss | (26,287 | ) | (47,005 | ) | (18,077 | ) | (47,217 | ) | ||||||||
Net loss per basic and diluted share | (0.09 | ) | (0.16 | ) | (0.06 | ) | (0.16 | ) | ||||||||
Funds provided by (used in) operations(2) | 85,140 | 28,323 | 104,026 | 50,225 | ||||||||||||
Cash provided by (used in) operations | 56,757 | 23,289 | 38,189 | 129,695 |
(Stated in thousands of Canadian dollars, except per share amounts) | 2016 | 2017 | ||||||||||||||
Quarters ended | September 30 | December 31 | March 31 | June 30 | ||||||||||||
Revenue(1) | 213,668 | 302,653 | 368,673 | 290,860 | ||||||||||||
Adjusted EBITDA(2) | 41,411 | 65,000 | 84,308 | 56,520 | ||||||||||||
Net loss | (47,377 | ) | (30,618 | ) | (22,614 | ) | (36,130 | ) | ||||||||
Net loss per basic and diluted share | (0.16 | ) | (0.10 | ) | (0.08 | ) | (0.12 | ) | ||||||||
Funds provided by (used in) operations(2) | 31,688 | 11,466 | 85,659 | (15,187 | ) | |||||||||||
Cash provided by (used in) operations | 17,515 | (27,846 | ) | 33,770 | 2,739 |
(1) Prior year comparatives have changed to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.
(2) See “NON-GAAP MEASURES”.
CRITICAL ACCOUNTING JUDGEMENTS AND ESTIMATES
Because of the nature of our business, we are required to make judgments and estimates in preparing our Consolidated Interim Financial Statements that could materially affect the amounts recognized. Our judgments and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgments and estimates used in preparing the Interim Financial Statements are described in our 2017 Annual Report and there have been no material changes to our critical accounting judgments and estimates during the three and six-month periods ended June 30, 2018 except for those impacted by the adoption of new accounting standards.
NON-GAAP MEASURES
In this press release we reference non-GAAP (Generally Accepted Accounting Principles) measures. Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital are terms used by us to assess performance as we believe they provide useful supplemental information to investors. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies.
Adjusted EBITDA
We believe that adjusted EBITDA (earnings before income taxes, loss on repurchase and redemption of unsecured senior notes, finance charges, foreign exchange, and depreciation and amortization), as reported in the Interim Consolidated Statement of Loss, is a useful measure, because it gives an indication of the results from our principal business activities prior to consideration of how our activities are financed and the impact of foreign exchange, taxation and depreciation and amortization charges.
Covenant EBITDA
Covenant EBITDA, as defined in our senior credit facility agreement, is used in determining the Corporation’s compliance with its covenants. Covenant EBITDA differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts.
Operating Earnings (Loss)
We believe that operating earnings (loss), as reported in the Interim Consolidated Statements of Loss, is a useful measure because it provides an indication of the results of our principal business activities before consideration of how those activities are financed and the impact of foreign exchange and taxation.
Funds Provided By (Used In) Operations
We believe that funds provided by (used in) operations, as reported in the Interim Consolidated Statements of Cash Flow, is a useful measure because it provides an indication of the funds our principal business activities generate prior to consideration of working capital, which is primarily made up of highly liquid balances.
Working Capital
We define working capital as current assets less current liabilities as reported on the Interim Consolidated Statement of Financial Position.
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS
Certain statements contained in this report, including statements that contain words such as "could", "should", "can", "anticipate", "estimate", "intend", "plan", "expect", "believe", "will", "may", "continue", "project", "potential" and similar expressions and statements relating to matters that are not historical facts constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and "forward-looking statements" within the meaning of the "safe harbor" provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively, "forward-looking information and statements").
In particular, forward looking information and statements include, but are not limited to, the following:
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:
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:
Readers are cautioned that the forgoing list of risk factors is not exhaustive. Additional information on these and other factors that could affect our business, operations or financial results are included in reports on file with applicable securities regulatory authorities, including but not limited to Precision’s Annual Information Form for the year ended December 31, 2017, which may be accessed on Precision’s SEDAR profile at www.sedar.com or under Precision’s EDGAR profile at www.sec.gov. The forward-looking information and statements contained in this news release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, except as required by law.
INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)
(Stated in thousands of Canadian dollars) | June 30, 2018 | December 31, 2017 | ||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash | $ | 94,669 | $ | 65,081 | ||||
Accounts receivable | 314,970 | 322,585 | ||||||
Income tax recoverable | 952 | 29,449 | ||||||
Inventory | 33,784 | 24,631 | ||||||
Total current assets | 444,375 | 441,746 | ||||||
Non-current assets: | ||||||||
Income tax recoverable | 2,358 | 2,256 | ||||||
Deferred tax assets | 38,024 | 41,822 | ||||||
Property, plant and equipment | 3,130,686 | 3,173,824 | ||||||
Intangibles | 36,129 | 28,116 | ||||||
Goodwill | 206,649 | 205,167 | ||||||
Total non-current assets | 3,413,846 | 3,451,185 | ||||||
Total assets | $ | 3,858,221 | $ | 3,892,931 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable and accrued liabilities | $ | 248,226 | $ | 209,625 | ||||
Non-current liabilities: | ||||||||
Share based compensation | 7,841 | 13,536 | ||||||
Provisions and other | 9,897 | 10,086 | ||||||
Long-term debt | 1,735,842 | 1,730,437 | ||||||
Deferred tax liability | 90,350 | 118,911 | ||||||
Total non-current liabilities | 1,843,930 | 1,872,970 | ||||||
Shareholders’ equity: | ||||||||
Shareholders’ capital | 2,321,902 | 2,319,293 | ||||||
Contributed surplus | 47,695 | 44,037 | ||||||
Deficit | (749,898 | ) | (684,604 | ) | ||||
Accumulated other comprehensive income | 146,366 | 131,610 | ||||||
Total shareholders’ equity | 1,766,065 | 1,810,336 | ||||||
Total liabilities and shareholders’ equity | $ | 3,858,221 | $ | 3,892,931 |
INTERIM CONSOLIDATED STATEMENTS OF LOSS (UNAUDITED)
Three months ended June 30, | Six months ended June 30, | ||||||||||||||
(Stated in thousands of Canadian dollars, except per share amounts) | 2018 | 2017 | 2018 | 2017 | |||||||||||
Revenue | $ | 330,716 | $ | 290,860 | $ | 731,722 | $ | 659,533 | |||||||
Expenses: | |||||||||||||||
Operating | 236,479 | 214,332 | 511,053 | 473,411 | |||||||||||
General and administrative | 32,055 | 20,008 | 61,018 | 45,294 | |||||||||||
Earnings before income taxes, loss on repurchase and redemption of unsecured senior notes, finance charges, foreign exchange and depreciation and amortization | 62,182 | 56,520 | 159,651 | 140,828 | |||||||||||
Depreciation and amortization | 88,621 | 95,799 | 175,929 | 192,962 | |||||||||||
Operating loss | (26,439 | ) | (39,279 | ) | (16,278 | ) | (52,134 | ) | |||||||
Foreign exchange | 556 | (798 | ) | 1,771 | (751 | ) | |||||||||
Finance charges | 32,103 | 34,532 | 63,782 | 67,514 | |||||||||||
Loss on repurchase and redemption of unsecured senior notes | 1,176 | — | 1,176 | — | |||||||||||
Loss before income taxes | (60,274 | ) | (73,013 | ) | (83,007 | ) | (118,897 | ) | |||||||
Income taxes: | |||||||||||||||
Current | 3,599 | (640 | ) | 5,165 | 250 | ||||||||||
Deferred | (16,656 | ) | (36,243 | ) | (22,878 | ) | (60,403 | ) | |||||||
(13,057 | ) | (36,883 | ) | (17,713 | ) | (60,153 | ) | ||||||||
Net loss | $ | (47,217 | ) | $ | (36,130 | ) | $ | (65,294 | ) | (58,744 | ) | ||||
Net loss per share: | |||||||||||||||
Basic | $ | (0.16 | ) | $ | (0.12 | ) | $ | (0.22 | ) | $ | (0.20 | ) | |||
Diluted | $ | (0.16 | ) | $ | (0.12 | ) | $ | (0.22 | ) | $ | (0.20 | ) |
INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(Stated in thousands of Canadian dollars) | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Net loss | $ | (47,217 | ) | $ | (36,130 | ) | $ | (65,294 | ) | $ | (58,744 | ) | ||||
Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency | 39,592 | (57,408 | ) | 93,326 | (75,962 | ) | ||||||||||
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax | (33,115 | ) | 48,901 | (78,570 | ) | 64,025 | ||||||||||
Comprehensive loss | $ | (40,740 | ) | $ | (44,637 | ) | $ | (50,538 | ) | $ | (70,681 | ) |
INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
(Stated in thousands of Canadian dollars) | 2018 | 2017 | 2018 | 2017 | ||||||||||||
Cash provided by (used in): | ||||||||||||||||
Operations: | ||||||||||||||||
Net loss | $ | (47,217 | ) | $ | (36,130 | ) | $ | (65,294 | ) | $ | (58,744 | ) | ||||
Adjustments for: | ||||||||||||||||
Long-term compensation plans | 6,027 | (602 | ) | 13,926 | 2,331 | |||||||||||
Depreciation and amortization | 88,621 | 95,799 | 175,929 | 192,962 | ||||||||||||
Foreign exchange | (15 | ) | (1,402 | ) | 1,433 | (1,354 | ) | |||||||||
Finance charges | 32,103 | 34,532 | 63,782 | 67,514 | ||||||||||||
Income taxes | (13,057 | ) | (36,883 | ) | (17,713 | ) | (60,153 | ) | ||||||||
Other | (217 | ) | (607 | ) | (1,133 | ) | (777 | ) | ||||||||
Loss on repurchase and redemption of unsecured senior notes | 1,176 | — | 1,176 | — | ||||||||||||
Income taxes paid | (3,282 | ) | (1,711 | ) | (3,606 | ) | (2,761 | ) | ||||||||
Income taxes recovered | 27,551 | — | 27,587 | 332 | ||||||||||||
Interest paid | (42,021 | ) | (68,351 | ) | (42,521 | ) | (70,259 | ) | ||||||||
Interest received | 556 | 168 | 685 | 1,381 | ||||||||||||
Funds provided by (used in) operations | 50,225 | (15,187 | ) | 154,251 | 70,472 | |||||||||||
Changes in non-cash working capital balances | 79,470 | 17,926 | 13,633 | (33,963 | ) | |||||||||||
129,695 | 2,739 | 167,884 | 36,509 | |||||||||||||
Investments: | ||||||||||||||||
Purchase of property, plant and equipment | (34,324 | ) | (21,136 | ) | (56,615 | ) | (41,559 | ) | ||||||||
Purchase of intangibles | (2,429 | ) | (7,301 | ) | (10,220 | ) | (8,970 | ) | ||||||||
Proceeds on sale of property, plant and equipment | 2,630 | 3,563 | 8,680 | 5,781 | ||||||||||||
Changes in non-cash working capital balances | (8,204 | ) | (2,175 | ) | (8,032 | ) | (10,566 | ) | ||||||||
(42,327 | ) | (27,049 | ) | (66,187 | ) | (55,314 | ) | |||||||||
Financing: | ||||||||||||||||
Debt amendment fees | — | — | — | (341 | ) | |||||||||||
Redemption and repayment of unsecured senior notes | (76,657 | ) | — | (76,657 | ) | — | ||||||||||
(76,657 | ) | — | (76,657 | ) | (341 | ) | ||||||||||
Effect of exchange rate changes on cash and cash equivalents | 2,085 | (1,206 | ) | 4,548 | (1,495 | ) | ||||||||||
Increase (decrease) in cash and cash equivalents | 12,796 | (25,516 | ) | 29,588 | (20,641 | ) | ||||||||||
Cash and cash equivalents, beginning of period | 81,873 | 120,580 | 65,081 | 115,705 | ||||||||||||
Cash and cash equivalents, end of period | $ | 94,669 | $ | 95,064 | $ | 94,669 | $ | 95,064 |
INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)
(Stated in thousands of Canadian dollars) | Shareholders’ capital | Contributed surplus | Accumulated other comprehensive income | Deficit | Total equity | |||||||||||||||
Balance at January 1, 2018 | $ | 2,319,293 | $ | 44,037 | $ | 131,610 | $ | (684,604 | ) | $ | 1,810,336 | |||||||||
Net loss for the period | — | — | — | (65,294 | ) | (65,294 | ) | |||||||||||||
Other comprehensive income for the period | — | — | 14,756 | — | 14,756 | |||||||||||||||
Shares issued on redemption non-management directors' DSUs | 2,609 | (809 | ) | — | — | 1,800 | ||||||||||||||
Share based compensation expense | — | 4,467 | — | — | 4,467 | |||||||||||||||
Balance at June 30, 2018 | $ | 2,321,902 | $ | 47,695 | $ | 146,366 | $ | (749,898 | ) | $ | 1,766,065 |
(Stated in thousands of Canadian dollars) | Shareholders’ capital | Contributed surplus | Accumulated other comprehensive income | Deficit | Total equity | |||||||||||||||
Balance at January 1, 2017 | $ | 2,319,293 | $ | 38,937 | $ | 156,456 | $ | (552,568 | ) | $ | 1,962,118 | |||||||||
Net loss for the period | — | — | — | (58,744 | ) | (58,744 | ) | |||||||||||||
Other comprehensive loss for the period | — | — | (11,937 | ) | — | (11,937 | ) | |||||||||||||
Share based compensation expense | — | 2,541 | — | — | 2,541 | |||||||||||||||
Balance at June 30, 2017 | $ | 2,319,293 | $ | 41,478 | $ | 144,519 | $ | (611,312 | ) | $ | 1,893,978 |
SECOND QUARTER 2018 EARNINGS CONFERENCE CALL AND WEBCAST
Precision Drilling Corporation has scheduled a conference call and webcast to begin promptly at 12:00 noon MT (2:00 p.m. ET) on Thursday, July 26, 2018.
The conference call dial in numbers are 1-844-515-9176 or 614-999-9312.
A live webcast of the conference call will be accessible on Precision’s website at www.precisiondrilling.com by selecting “Investor Relations”, then “Webcasts & Presentations”. Shortly after the live webcast, an archived version will be available for approximately 60 days.
An archived recording of the conference call will be available approximately one hour after the completion of the call until July 31, 2018 by dialing 1-855-859-2056 or 404-537-3406, pass code 1184468.
About Precision
Precision is a leading provider of safe and High Performance, High Value services to the oil and gas industry. Precision provides customers with access to an extensive fleet of contract drilling rigs, directional drilling services, well service and snubbing rigs, camps, rental equipment, and water treatment units backed by a comprehensive mix of technical support services and skilled, experienced personnel.
Precision is headquartered in Calgary, Alberta, Canada. Precision is listed on the Toronto Stock Exchange under the trading symbol “PD” and on the New York Stock Exchange under the trading symbol “PDS”.
For further information, please contact:
Carey Ford, Senior Vice President and Chief Financial Officer
713.435.6111
Ashley Connolly, Manager, Investor Relations
403.716.4725
800, 525 - 8th Avenue S.W.
Calgary, Alberta, Canada T2P 1G1
Website: www.precisiondrilling.com