OREANDA-NEWS. Precision Drilling (TSX:PD)(NYSE:PDS) announces 2017 second quarter financial results:

  • Second quarter revenue was $276 million, an increase of 68% over the second quarter of 2016.
  • Second quarter earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, and depreciation and amortization (adjusted EBITDA see "Non- GAAP Measures") of $57 million was 152% higher than the second quarter of 2016.
  • Second quarter net loss was $36 million ($0.12 per share) compared with a net loss of $58 million ($0.20 per share) in the second quarter of 2016.
  • Second quarter capital expenditures were $28 million, with full year capital spending expected to be $138 million.

Kevin Neveu, Precision's President and Chief Executive Officer, stated: "I am very pleased with the substantial improvement in our business and particularly the improved financial results we generated during the second quarter compared to the dismal environment of 2016. I commend the Precision organization for strong operational execution and fixed cost leverage as we managed rig activations in the U.S., seasonal slowdowns in Canada and continued to hone our performance in our international operations. We remain focused on our three strategic objectives for 2017, centered on free cash flow generation and debt reduction, fixed cost leverage and the commercialization of rig automation and efficiency driven technologies. I believe we made solid progress in each initiative during the quarter."

"Precision continued to experience strengthening customer demand during the second quarter despite the increased uncertainty and volatility in commodity prices. Demand for our Pad Walking Super Triple rigs remains strong in all of our North American markets."

"In the U.S. we signed nine term contracts in the second quarter, and are currently operating 63 rigs. The industry has witnessed a tempering of rig additions from earlier this year, but I believe that even in a flat demand environment in the Lower 48, our customers will continue to gravitate towards high spec rigs in the drive to improve efficiency and reduce cost."

"Our rig count in Canada troughed at 19 rigs and experienced a slower than expected ramp up as the quarter progressed. While partially a result of weather delays, customer uncertainty emerged as a drag on demand. That being said, activity levels still showed a 120% year-over-year improvement, driving meaningful fixed cost absorption in the quarter and establishing a stronger start to the second half of the year."

"Our international operations continue to perform well, with eight active rigs in the Middle East and no contract rollovers in 2017. We expect to see consistent financial results out of the division throughout the year and continue to actively bid our four idle rigs in the region for opportunities in our two core markets of Kuwait and Saudi Arabia, as well as select new operating areas."

"Our 2017 capital program has increased by approximately $19 million as we elected to upgrade our existing ERP system. The upgrade is aimed at driving increased operating efficiencies, improving our fixed cost leverage and positioning the organization to better handle the increased data flows associated with our business. Additionally, I believe the timing of the upgrade is appropriate at this point in the cycle."

"As demonstrated during our Analyst and Investor Day in May, Precision holds a key competitive advantage in our ability to deploy efficiency-generating technologies and we continue to progress in the commercialization of these initiatives. I am pleased to announce that we have now installed 20 Process Automation Control systems on our rigs and beta-style field trials are progressing as planned. Year-to-date we have completed 30 jobs utilizing a Directional Guidance System and continue to prove out the synergies and efficiencies to be gained by using the software and reducing crew count. We remain on track to commercialize these technologies in 2017 as stated in our strategic priorities for the year" concluded Mr. Neveu.

S ELECT FINANCIAL AND OPERATING INFORMATION

Adjusted EBITDA and funds provided by 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) 2017 2016 % Change 2017 2016 % Change
Revenue 275,524 163,979 68.0 621,324 465,706 33.4
Adjusted EBITDA(1) 56,520 22,400 152.3 140,828 121,644 15.8
Adjusted EBITDA % of revenue 20.5% 13.7%   22.7% 26.1%  
Net loss (36,130) (57,677) (37.4) (58,744) (77,560) (24.3)
Cash provided by operations 2,739 20,665 (86.7) 36,509 132,839 (72.5)
Funds provided by (used in) operations(1) (15,187) (31,372) (51.6) 70,472 62,221 13.3
Capital spending:            
  Expansion 4,852 46,732 (89.6) 8,644 65,933 (86.9)
  Upgrade 13,287 - n/m 26,934 1,433 1,779.6
  Maintenance and infrastructure 10,298 6,692 53.9 14,951 13,219 13.1
  Proceeds on sale (3,563) (1,548) 130.2 (5,781) (3,705) 56.0
Net capital spending 24,874 51,876 (52.1) 44,748 76,880 (41.8)
             
Net loss per share:            
  Basic and diluted (0.12) (0.20) (40.0) (0.20) (0.26) (23.1)

(1) See "NON-GAAP MEASURES."

n/m - calculation not meaningful.

Operating Highlights

  Three months ended June 30, Six months ended June 30,
  2017 2016 % Change 2017 2016 % Change
Contract drilling rig fleet 256 252 1.6 256 252 1.6
Drilling rig utilization days:
  Canada 2,639 1,202 119.6 9,458 5,197 82.0
  U.S. 5,331 2,198 142.5 9,521 5,084 87.3
  International 728 637 14.3 1,448 1,400 3.4
Revenue per utilization day:            
  Canada (1)(3)(Cdn$) 18,245 24,980 (27.0) 18,446 24,134 (23.6)
  U.S.(2)(3)(US$) 19,134 27,519 (30.5) 19,503 29,966 (34.9)
  International (US$) 49,679 44,391 11.9 50,054 42,874 16.7
Operating cost per utilization day:            
  Canada (Cdn$) 12,436 14,954 (16.8) 10,641 11,836 (10.1)
  U.S. (US$) 13,556 14,899 (9.0) 14,052 15,896 (11.6)
Service rig fleet 210 163 28.8 210 163 28.8
Service rig operating hours 33,813 14,862 127.5 85,870 39,693 116.3
Revenue per operating hour (Cdn$) 629 602 4.5 633 691 (8.4)
             
(1) Includes lump sum revenue from contract shortfall.
(2) Includes revenue from idle but contracted rig days.
(3) Six months ended June 30, 2016 comparative includes revenue from contract cancellation payments.
Financial Position
(Stated in thousands of Canadian dollars, except ratios) June 30,
2017		 December 31,
2016
Working capital 243,903 230,874
Cash 95,064 115,705
Long-term debt(1) 1,844,773 1,906,934
Total long-term financial liabilities 1,868,073 1,946,742
Total assets 4,078,083 4,324,214
Long-term debt to long-term debt plus equity ratio(1) 0.49 0.49
(1) Net of unamortized debt issue costs.

Summary for the three months ended June 30, 2017

  • Revenue this quarter was $276 million representing a 68% increase over the second quarter of 2016. The increase in revenue was primarily the result of greater activity in all of our North American based businesses and higher average day rates from our international contract drilling business partially offset by fewer idle but contracted rigs, a decrease in average day rates in all of our North American businesses and no activity in our Mexico based contract drilling business. Compared with the second quarter of 2016 our activity for the quarter, as measured by drilling rig utilization days, increased 120% in Canada, 143% in the U.S. and 14% internationally. Revenue from our Contract Drilling Services and Completion and Production Services segments both increased over the comparative prior year period by 67% and 76%, respectively.
  • Adjusted EBITDA this quarter of $57 million was an increase of $34 million from the second quarter of 2016. Our adjusted EBITDA as a percentage of revenue was 21% this quarter, compared with 14% in the second quarter of 2016. The increase in adjusted EBITDA as a percent of revenue was mainly due to fixed costs spread over higher activity in the quarter partially offset by lower average day rates in North America.
  • Operating loss (see "Non-GAAP Measures") this quarter was $39 million compared with an operating loss of $74 million in the second quarter of 2016. Operating results this quarter were positively impacted by increased activity in our North American businesses partially offset by lower average pricing.
  • General and administrative expenses this quarter were $20 million, $8 million lower than the second quarter of 2016. The decrease was due to cost saving initiatives undertaken in 2016 and a decrease in our share based incentive compensation that is tied to the price of our common shares partially offset by a weaker Canadian dollar on our U.S. dollar denominated costs. As at June 30, 2017 we have a total share based incentive compensation liability of $23 million compared with $28 million at March 31, 2017 after having paid $0.4 million in the quarter.
  • Net finance charges were $35 million, an increase of $1 million compared with the second quarter of 2016 primarily due to higher interest income in 2016 and a weaker Canadian dollar on our U.S. dollar denominated interest expense, partially offset by a reduction in interest expense related to debt retired in 2016.
  • In Canada, average revenue per utilization day for contract drilling rigs decreased in the second quarter of 2017 to $18,245 from $24,980 in the prior year and decreased in the U.S. to US$19,134 from US$27,519 over the same period. The decrease in Canada was the result of fewer rigs working under legacy contracts, lower contract shortfall payments and a higher proportion of revenue from shallower drilling activity relative to the 2016 comparative period. During the quarter, we recognized $4 million in revenue associated with contract shortfall payments in Canada which was a decrease of $2 million from the prior year period. The decrease in the U.S. revenue rate was the result of fewer rigs working under long-term contracts with legacy pricing and a lower daily revenue impact from idle but contracted rigs. We recognized US$5 million in turnkey revenue in the second quarter compared with US$6 million in the 2016 comparative period and US$2 million in idle but contracted revenue in the current quarter versus US$7 million in the comparative period.
  • Average operating costs per utilization day for drilling rigs in Canada decreased to $12,436 compared with the prior year second quarter of $14,954. The decrease in average costs was due to improved absorption of fixed costs with higher utilization. In the U.S., operating costs for the quarter on a per day basis decreased to US$13,556 in 2017 compared with US$14,899 in 2016 due to fixed costs spread over higher utilization partially offset by favourable sales tax adjustments in the prior year comparative period.
  • We realized revenue from international contract drilling of US$36 million in the second quarter of 2017, a US$8 million increase over the prior year period. The increase was due to the startup of two new rigs in Kuwait in the fourth quarter of 2016 partially offset by no activity in our Mexico operations. Average revenue per utilization day in our international contract drilling business was US$49,679 an increase of 12% over the comparable prior year quarter primarily due to rig mix as we had fewer rigs working in the lower day rate jurisdictions.
  • During the quarter we added nine term contracts for drilling rigs, adding seven rig years to our contract book.
  • Directional drilling services realized revenue of $12 million in the second quarter of 2017 compared with $3 million in the prior year period. The increase was the result of higher activity levels and day rates in both Canada and the U.S.
  • Funds used in operations (see "Non- GAAP Measures") the second quarter of 2017 were $15 million, a decrease of $16 million from the prior year comparative quarter of $31 million. The improvement was primarily the result of stronger operating results in the current quarter compared with the prior year comparative quarter.
  • Capital expenditures for the purchase of property, plant and equipment were $28 million in the second quarter, a decrease of $25 million over the same period in 2016. Capital spending for the quarter included $5 million for expansion capital, $13 million for upgrade capital and $10 million for the maintenance of existing assets and infrastructure spending.

Summary for the six months ended June 30, 2017:

  • Revenue for the first half of 2017 was $621 million, an increase of 33% from the 2016 period.
  • Operating loss was $52 million, a decrease of $18 million over the same period in 2016. Operating loss was 8% of revenue in 2017 compared to 15% of revenue in 2016. Operating results this year were positively impacted by increased activity in our North American businesses partially offset by lower average pricing.
  • General and administrative costs were $45 million, a decrease of $10 million over the first half of 2016. The decrease was primarily due to fixed cost reductions implemented in 2016 and lower share based incentive compensation that is tied to the price of our common shares.
  • Net finance charges were $68 million, a decrease of $2 million from the first half of 2016 primarily due to a reduction in interest expense related to debt retired in 2016 partially offset by higher interest income earned in the comparative period.
  • Funds provided by operations (see "Non- GAAP Measures") in the first half of 2017 were $70 million, an increase of $8 million from the prior year comparative period of $62 million.
  • Capital expenditures for the purchase of property, plant and equipment were $51 million in the first half of 2017, a decrease of $30 million over the same period in 2016. Capital spending for 2017 to date included $9 million for expansion capital, $27 million for upgrade capital and $15 million for the maintenance of existing assets and infrastructure.

STRATEGY

Precision's strategic priorities for 2017 are as follows:

  1. Deliver High Performance, High Value service offering in an improving demand environment while demonstrating fixed cost leverage - In the U.S., we grew our active rig count by 56% throughout the first half of 2017. In Canada, we began the year with 50 active rigs and reached a seasonal peak of 91 rigs. Year-over-year in the first half 2017 our utilization days were up 134% across our North American drilling operations and was achieved without any material increase in fixed costs. In addition, we are upgrading our existing ERP system to increase operating efficiencies, improve our fixed cost leverage and position the organization to better handle the increased data flows associated with our business.
  2. Commercialize rig automation and efficiency-driven technologies across our Super Series fleet - We have now installed 20 Process Automation Control systems on our rigs and beta-style field trials are progressing as planned. Year-to-date we have completed 30 jobs utilizing a Directional Guidance system and continue to prove out the synergies and efficiencies gained in using the software and reducing crew count. We expect to commercialize these automation features during 2017.
  3. Maintain strict financial discipline in pursuing growth opportunities with a focus on free cash flow and debt reduction - Effectively all upgrade capital spending is supported by take-or-pay term contracts priced at a level that allows for attractive rates of return. In the first half of 2017 we generated funds from operations of $70 million (see "Non-GAAP measures").

OUTLOOK

For the second quarter of 2017, the average West Texas Intermediate price of oil was 6% higher than the prior year comparative period while average Henry Hub natural gas price was 39% higher.

  Three months ended June 30, Year ended December 31,
  2017 2016 2016
Average oil and natural gas prices      
Oil      
  West Texas Intermediate (per barrel) (US$) 48.33 45.45 43.30
Natural gas      
  Canada      
    AECO (per MMBtu) (CDN$) 2.69 1.41 2.14
  United States      
    Henry Hub (per MMBtu) (US$) 2.94 2.11 2.48

Contracts

The following chart outlines the average number of drilling rigs that we have under contract as of July 28, 2017 for the remaining quarters of 2017 and the full years 2017 and 2018.

  Average for the quarter ended 2017 Average for the year ended
  March 31 June 30 September 30 December 31 2017 2018
Average rigs under term contract as at July 28, 2017:            
  Canada 27 22 21 17 22 8
  U.S. 26 30 29 21 27 7
  International 8 8 8 8 8 7
Total 61 60 58 46 57 22
             

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. Year to date as of July 28, 2017 we have added 16 term contracts with durations of six months or longer.

Drilling Activity

The following chart outlines the average number of drilling rigs that we had working or moving by quarter for the periods noted.

Average for the quarter ended 2016 2017
  June 30 September 30 December 31 March 31 June 30
Average Precision active rig count:          
  Canada 13 31 51 76 29
  U.S. 24 29 39 47 59
  International 7 7 8 8 8
Total 44 67 98 131 96

In general, lower oil prices caused producers to significantly reduce their drilling budgets in 2015 and 2016, decreasing demand for drilling rigs, resulting in pricing pressure on spot market day rates and significantly depressed industry activity levels. Following OPEC's actions to limit production to stabilize oil prices, we have experienced increased demand for our rigs and if current commodity prices continue to improve we expect our customers to enhance their drilling programs, further strengthening rig demand.

On the back of improved commodity prices and industry activity levels, we were able to increase pricing across the majority of our fleet in the first half of 2017. Further pricing increases will be dependent on capital spending plans by our customers and resulting demand for our rigs, both of which are directly tied to commodity prices. The most competitive market in which we operate remains the shallower parts of the Western Canadian Sedimentary Basin, where pricing remains constrained due to excess rig availability.

Industry Conditions

In 2017, drilling activity has increased relative to this time last year for both Canada and the U.S. According to industry sources, as of July 28, 2017, the U.S. active land drilling rig count was up approximately 85% from the same point last year and the Canadian active land drilling rig count was up approximately 110%.

In Canada there has been a strengthening in natural gas and gas liquids drilling activity related to Deep Basin drilling in northwestern Alberta and northeastern British Columbia while the trend towards oil-directed drilling in the U.S. continues. To date in 2017, approximately 53% of the Canadian industry's active rigs and 80% of the U.S. industry's active rigs were drilling for oil targets, compared with 45% for Canada and 80% for the U.S. at the same time last year.

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 have been highlighted and widely accepted by our customers. The trend to longer-reach horizontal completions and the importance of the rig delivering these complex wells consistently and efficiently has been well established by the industry. We expect that demand for leading edge high efficiency Tier 1 rigs will continue to strengthen, as the drilling rig capability has been a key economic facilitator of horizontal/unconventional resource exploitation. Development and field application of drilling equipment process automation coupled with closed loop drilling controls and de-manning of the rigs will continue this technical evolution while creating further cost efficiencies and performance value for customers and further differentiating the specific capabilities of the leading edge Tier 1 rigs and those rig contractors capable of widely deploying those technologies.

Capital Spending

Capital spending in 2017 is expected to be $138 million, split $132 million in the Contract Drilling Services segment and $6 million in the Completion and Production Services segment:

  • The 2017 capital expenditure plan includes $13 million for expansion capital, $71 million for sustaining and infrastructure expenditures, and $54 million to upgrade existing rigs. The increase in sustaining and infrastructure capital spending is primarily related to a substantial upgrade to our existing enterprise resource planning system (ERP). We are upgrading our existing ERP system to increase operating efficiencies, improve our fixed cost leverage and position the organization to better handle the increased data flows associated with our business.

SEGMENTED FINANCIAL RESULTS

Precision's operations are reported in two segments: the Contract Drilling Services segment, which includes the drilling rig, directional drilling, oilfield supply and manufacturing divisions; and the Completion and Production Services segment, which includes the service rig, snubbing, rental, camp and catering and wastewater treatment divisions.

  Three months ended June 30, Six months ended June 30,
(Stated in thousands of Canadian dollars) 2017 2016 % Change 2017 2016 % Change
Revenue:            
  Contract Drilling Services 247,122 147,780 67.2 548,179 422,617 29.7
  Completion and Production Services 29,381 16,731 75.6 75,730 45,185 67.6
  Inter-segment eliminations (979) (532) 84.0 (2,585) (2,096) 23.3
  275,524 163,979 68.0 621,324 465,706 33.4
Adjusted EBITDA:(1)            
  Contract Drilling Services 67,031 42,503 57.7 160,696 158,120 1.6
  Completion and Production Services 336 (2,568) (113.1) 4,923 (4,775) (203.1)
  Corporate and other (10,847) (17,535) (38.1) (24,791) (31,681) (21.7)
  56,520 22,400 152.3 140,828 121,664 15.8
(1) 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)    
2017 2016 % Change 2017 2016 % Change
Revenue 247,122 147,780 67.2 548,179 422,617 29.7
Expenses:            
  Operating(1) 172,744 96,137 79.7 370,688 243,316 52.3
  General and administrative(1) 7,347 8,679 (15.3) 16,795 18,764 (10.5)
  Restructuring - 461 (100.0) - 2,417 (100.0)
Adjusted EBITDA(2) 67,031 42,503 57.7 160,696 158,120 1.6
  Depreciation 85,065 86,412 (1.6) 171,254 170,691 0.3
Operating loss(2) (18,034) (43,909) (58.9) (10,558) (12,571) (16.0)
Operating loss as a percentage of revenue (7.3%) (29.7%)   (1.9) (3.0%)  
(1) Certain expenses in the prior year comparative have been reclassified to conform to current year presentation.
(2) See "NON-GAAP MEASURES".
  Three months ended June 30,
Canadian onshore drilling statistics:(1) 2017 2016
  Precision Industry (2) Precision Industry(2)
  Number of drilling rigs (end of period) 136 634 135 672
  Drilling rig operating days (spud to release) 2,358 9,252 1,073 4,011
  Drilling rig operating day utilization 19% 16% 9% 7%
  Number of wells drilled 267 1,024 89 313
  Average days per well 8.8 9.0 12.1 12.8
  Number of metres drilled (000s) 758 2,928 301 931
  Average metres per well 2,839 2,859 3,384 2,974
  Average metres per day 321 316 281 232
  Six months ended June 30,
Canadian onshore drilling statistics:(1) 2017 2016
  Precision Industry (2) Precision Industry(2)
  Number of drilling rigs (end of period) 136 634 135 672
  Drilling rig operating days (spud to release) 8,400 32,756 4,644 17,177
  Drilling rig operating day utilization 34% 28% 19% 14%
  Number of wells drilled 831 3,308 338 1,375
  Average days per well 10.1 9.9 13.7 12.5
  Number of metres drilled (000s) 2,229 9,088 990 3,760
  Average metres per well 2,682 2,747 2,928 2,735
  Average metres per day 265 277 213 219
(1) Canadian operations only.
(2) Canadian Association of Oilwell Drilling Contractors ("CAODC"), and Precision - excludes non-CAODC rigs and non-reporting CAODC members.
United States onshore drilling statistics:(1) 2017 2016
  Precision Industry(2) Precision Industry(2)
Average number of active land rigs for quarters ended:        
  March 31 47 722 32 516
  June 30 59 874 24 397
Year to date average 53 798 28 457
(1) United States lower 48 operations only.
(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $247 million this quarter, or 67% higher than the second quarter of 2016, while adjusted EBITDA increased by 58% to $67 million. The increase in revenue was due to higher utilization days in Canada and the U.S. and higher average day rates for international contract drilling. During the quarter we recognized $4 million in shortfall payments in our Canadian contract drilling business, which was $2 million lower than in the prior year comparative quarter. During the quarter in the U.S. we recognized US$2 million of idle but contracted revenue compared with US$7 million in the comparative quarter of 2016.

Drilling rig utilization days in Canada (drilling days plus move days) were 2,639 during the second quarter of 2017, an increase of 120% compared to 2016 primarily due to the increase in industry activity resulting from higher oil and natural gas prices. Drilling rig utilization days in the U.S. were 5,331, or 143% higher than the same quarter of 2016 as U.S. activity was up with higher industry activity. Drilling rig utilization days in our international business were 728 or 14% higher than the same quarter of 2016 due to the addition of two rigs in Kuwait during the fourth quarter of 2016 partially offset by no activity in Mexico.

Compared with the same quarter in 2016, drilling rig revenue per utilization day was down 27% in Canada due to fewer rigs working on legacy contracts, lower shortfall revenue and a higher proportion of revenue from shallower drilling activity relative to the 2016 comparative period. Drilling rig revenue per utilization day for the quarter in the U.S. was down 30% from the prior comparative period, while international revenue per utilization day was up 12%. The decrease in the U.S. average rate was a result of fewer rigs working under long-term contracts with legacy pricing and a lower daily revenue impact from idle but contracted rigs. International revenue per utilization day was up due to rig mix with a higher proportion of days from Kuwait during the quarter and no activity in Mexico.

In Canada, 31% of our utilization days in the quarter were generated from rigs under term contract, compared with 55% in the second quarter of 2016. In the U.S., 57% of utilization days were generated from rigs under term contract as compared with 70% in the second quarter of 2016.

Operating costs were 70% of revenue for the quarter, which was 5 percentage points higher than the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were lower than the prior year period primarily because of improved absorption of fixed costs with higher utilization and the timing of certifications. In the U.S., operating costs for the quarter on a per day basis were lower than the prior year period due to fixed costs spread over higher utilization partially offset by favourable sales tax adjustments in the prior year comparative period. Both Canada and U.S. operating costs benefited from cost saving initiatives taken in 2015 and 2016.

Depreciation expense in the quarter was 2% lower than in the second quarter of 2016.

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)    
2017 2016 % Change 2017 2016 % Change
Revenue 29,381 16,731 75.6 75,730 45,185 67.6
Expenses:            
  Operating(1) 27,231 16,107 69.1 67,099 42,329 58.5
  General and administrative(1) 1,814 2,644 (31.4) 3,708 5,664 (34.5)
  Restructuring - 548 (100.0) - 1,967 (100.0)
Adjusted EBITDA(2) 336 (2,568) (113.1) 4,923 (4,775) (203.1)
  Depreciation 7,094 6,568 8.0 14,497 13,778 5.2
Operating loss(2) (6,758) (9,136) (26.0) (9,574) (18,553) (48.4)
Operating loss as a percentage of revenue (23.0%) (54.6%)  
(12.6%)		 (41.1%)  
  Well servicing statistics:            
  Number of service rigs (end of period) 210 163 28.8 210 163 28.8
  Service rig operating hours 33,813 14,862 127.5 85,870 39,693 116.3
  Service rig operating hour utilization 18% 10%   23% 13%  
  Service rig revenue per operating hour 629 602 4.5 633 691 (8.4)
(1) Certain expenses in the prior year comparative have been reclassified to conform to current year presentation.
(2) See "NON-GAAP MEASURES".

Revenue from Completion and Production Services was up $13 million or 76% compared with the second quarter of 2016 due to higher activity levels in all service lines partially offset by lower average rates. As oil and natural gas prices have recovered somewhat, customers have increased spending and activity in well completion and production programs. Our well servicing activity in the quarter was up 128% from the second quarter of 2016 as a result of improved industry activity levels and a larger fleet following the acquisition of service rigs late in the fourth quarter of 2016. Approximately 86% of our second quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 87% of its revenue from Canadian and 13% from U.S. operations in line with the second quarter of 2016.

Average service rig revenue per operating hour in the quarter was $629 or $27 higher than the second quarter of 2016. The increase was primarily the result of increased labour costs passed through to the customer.

Adjusted EBITDA was $3 million higher than the second quarter of 2016 as increased activity combined with cost cutting initiatives more than offset lower rates.

Operating costs as a percentage of revenue decreased to 93% in the second quarter of 2017, from 96% in the second quarter of 2016. The decrease was the result of the impact of fixed costs spread across greater activity combined with our reduced cost structure.

Depreciation in the quarter was 8% higher than the second quarter of 2016 due to the addition of well servicing units at the end of the fourth quarter of 2016 offset by assets becoming 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 $11 million a decrease of $7 million compared with the second quarter of 2016 primarily due to lower share based incentive compensation and cost saving initiatives.

OTHER ITEMS

Net financial charges for the quarter were $35 million, an increase of $2 million compared with the second quarter of 2016 primarily due to higher interest income in 2016 and a weaker Canadian dollar on our U.S. dollar denominated interest expense partially offset by a reduction in interest expense related to debt retired in 2016. For the current quarter we incurred a $1 million foreign exchange gain compared with a loss of $1 million during the second quarter of 2016.

Income tax expense for the quarter was a recovery of $37 million compared with a recovery of $50 million in the same quarter in 2016. 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 apply a disciplined approach to managing and tracking results of our operations to keep costs down. We maintain a variable cost structure so we can be responsive to changes in demand.

Our maintenance capital expenditures are tightly governed by and highly responsive to activity levels with additional cost savings leverage provided through our internal manufacturing and supply divisions. Term contracts on expansion capital for new-build rig programs provide more certainty of future revenues and return on our capital investments.

Liquidity

In January, 2017 we agreed with our lending group to the following amendments to our senior credit facility:

  • Reduce the Adjusted EBITDA (as defined in the debt agreement) to interest expense coverage ratio to greater than 1.25:1 for the periods ending March 31, June 30 and September 30, 2017. For the periods ending December 31, 2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter.
  • Reduce the size of the facility to US$525 million and suspended the increase in the accordion feature to US$275 million until the end of the covenant relief period.

As at June 30, 2017 we had $1,870 million outstanding under our senior unsecured notes. The current blended cash interest cost of our debt is approximately 6.5%.

Amount   Availability   Used for   Maturity
Senior facility (secured)            
US$525 million (extendible, revolving term credit facility with US$250 million(1) accordion feature)   Drawn US$25 million in outstanding letters of credit   General corporate purposes   June 3, 2019
Operating facilities (secured)        
$40 million   Undrawn, except $21 million in outstanding letters of credit   Letters of credit and general corporate purposes    
US$15 million   Undrawn   Short term working capital requirements    
Demand letter of credit facility (secured)
US$30 million   Undrawn, except US$4 million in outstanding letters of credit   Letters of credit    
Senior notes (unsecured)        
US$372 million - 6.625%   Fully drawn   Debt repayment and general corporate purposes   November 15, 2020
US$319 million - 6.5%   Fully drawn   Capital expenditures and general corporate purposes   December 15, 2021
US$350 million - 7.75%   Fully drawn   Debt redemption and repurchases   December 15, 2023
US$400 million - 5.25%   Fully drawn   Capital expenditures and general corporate purposes   November 15, 2024
(1) Increases to US$275 million at the end of the covenant relief period of March 31, 2018.

Covenants

Senior Facility

The senior credit facility requires that we comply with certain covenants including a leverage ratio of consolidated senior debt to earnings before interest, taxes, depreciation and amortization as defined in the agreement (Adjusted EBITDA) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness. Adjusted EBITDA, as defined in our revolving term facility agreement differs from Adjusted EBITDA as defined under Non-GAAP Measures by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts. As at June 30, 2017 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.2:1.

Effective January 20, 2017, under the senior credit facility, we are required to maintain a ratio of Adjusted EBITDA to interest expense for the most recent four consecutive quarters, of greater than 1.25:1 for the periods ending March 31, June 30 and September 30, 2017. For the periods ending December 31, 2017 and March 31, 2018 the ratio is 1.5:1 reverting to 2.5:1 thereafter. As at June 30, 2017 our senior credit facility Adjusted EBITDA to interest expense ratio was 1.71:1.

The senior credit facility also prevents us from making distributions prior to April 1, 2018 and restricts our ability to repurchase our unsecured senior notes subject to a pro forma liquidity test of US$500 million.

In addition, the senior credit facility contains certain covenants that place restrictions on our ability to incur or assume additional indebtedness; dispose of assets; pay dividends, undertake share redemptions or other distributions; change our primary business; incur liens on assets; engage in transactions with affiliates; enter into mergers, consolidations or amalgamations; and enter into speculative swap agreements.

At June 30, 2017, we were in compliance with the covenants of the senior credit facility.

Senior Notes

The senior notes require that we comply with financial covenants including an incurrence based consolidated interest coverage ratio test, as defined in the senior note agreements, to interest coverage ratio of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our consolidated interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters the senior notes restrict our ability to incur additional indebtedness. As at June 30, 2017, our senior notes consolidated interest coverage ratio was 1.58:1, which limits our ability to incur additional indebtedness, except as permitted under the agreements, until such time as we are in compliance with the ratio test, but would not restrict our access to available funds under the senior credit facility or to refinance our existing debt. Furthermore, it does not give rise to any cross-covenant violations, give the lenders the right to demand repayment of any outstanding portion of the senior notes prior to the stated maturity dates, or provide any other forms of recourse to the lenders.

The senior notes contain a restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2020, 2021 and 2024 Senior Notes and from October 1, 2016 for the 2023 Senior Notes by, among other things, 50% of cumulative net earnings and decreases by 100% of cumulative net losses as defined in the note agreements, and payments made to shareholders. Beginning with the December 31, 2015 calculation the governing net restricted payments basket was negative and as of that date we were no longer able to declare and make dividend payments until such time as the restricted payments baskets once again become positive. For further information, please see the senior note indentures which are available on SEDAR and EDGAR.

In addition, the senior notes contain certain covenants that limit our ability, and the ability of certain subsidiaries, to incur additional indebtedness and issue preferred shares; create liens; create or permit to exist restrictions on our ability or certain subsidiaries to make certain payments and distributions; engage in amalgamations, mergers or consolidations; make certain dispositions and engage in transactions with affiliates.

Hedge of investments in foreign operations

We utilize foreign currency long-term debt to hedge our exposure to changes in the carrying values of our net investment in certain foreign operations as a result of changes in foreign exchange rates.

We have designated our U.S. dollar denominated long-term debt as a net investment hedge in our U.S. operations and other foreign operations that have a U.S. dollar functional currency. To be accounted for as a hedge, the foreign currency denominated long-term debt must be designated and documented as such and must be effective at inception and on an ongoing basis. We recognize the effective amount of this hedge (net of tax) in other comprehensive income. We recognize ineffective amounts (if any) in net earnings (loss).

Average shares outstanding

The following table reconciles the weighted average shares outstanding used in computing basic and diluted net loss per share:

  Three months ended June 30, Six months ended June 30,
(Stated in thousands) 2017 2016 2017 2016
Weighted average shares outstanding - basic 293,239 293,134 293,239 293,027
Effect of stock options and other equity compensation plans - - - -
Weighted average shares outstanding - diluted 293,239 293,134 293,239 293,027

QUARTERLY FINANCIAL SUMMARY

(Stated in thousands of Canadian dollars, except per share amounts)

  2016 2017
Quarters ended September 30 December 31 March 31 June 30
Revenue 201,802 283,903 345,800 275,524
Adjusted EBITDA(1) 41,411 65,000 84,308 56,520
Net loss: (47,377) (30,618) (22,614) (36,130)
  Per basic and diluted share (0.16) (0.10) (0.08) (0.12)
Funds provided by (used in) operations(1) 31,688 11,466 85,659 (15,187)
Cash provided by (used in) operations 17,515 (27,846) 33,770 2,739

(Stated in thousands of Canadian dollars, except per share amounts)

  2015 2016
Quarters ended September 30 December 31 March 31 June 30
Revenue 364,089 344,953 301,727 163,979
Adjusted EBITDA(1) 111,031 111,095 99,264 22,400
Net loss: (86,700) (270,952) (19,883) (57,677)
  Per basic and diluted share (0.30) (0.93) (0.07) (0.20)
Funds provided by (used in) operations(1) 99,228 49,503 93,593 (31,372)
Cash provided by operations 61,049 70,952 112,174 20,665
Dividends paid per share 0.07 0.07 - -
(1) See "NON-GAAP MEASURES".

NON-GAAP MEASURES

In this press release we reference non-GAAP (Generally Accepted Accounting Principles) measures. Adjusted EBITDA, Operating Loss and Funds Provided by Operations 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, gain on repurchase of unsecured senior notes, financing 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 non-cash impairment, decommissioning, depreciation and amortization charges.

Operating Loss

We believe that operating 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.

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 2017;
  • our capital expenditure plans for 2017 and our scheduled ERP upgrade;
  • anticipated activity levels in 2017;
  • anticipated demand for Tier 1 rigs; and
  • the average number of term contracts in place for 2017 and 2018.

These forward-looking information and statements are based on certain assumptions and analysis made by Precision in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. These include, among other things:

  • the fluctuation in oil prices may pressure customers into reducing or limiting their drilling budgets;
  • the status of current negotiations with our customers and vendors;
  • customer focus on safety performance;
  • existing term contracts are neither renewed nor terminated prematurely;
  • our ability to deliver rigs to customers on a timely basis; and
  • the general stability of the economic and political environments in the jurisdictions where we operate.

Undue reliance should not be placed on forward-looking information and statements. Whether actual results, performance or achievements will conform to our expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ materially from our expectations. Such risks and uncertainties include, but are not limited to:

  • volatility in the price and demand for oil and natural gas;
  • fluctuations in the demand for contract drilling, well servicing and ancillary oilfield services;
  • our customers' inability to obtain adequate credit or financing to support their drilling and production activity;
  • changes in drilling and well servicing technology which could reduce demand for certain rigs or put us at a competitive disadvantage;
  • shortages, delays and interruptions in the delivery of equipment supplies and other key inputs;
  • the effects of seasonal and weather conditions on operations and facilities;
  • the availability of qualified personnel and management;
  • a decline in our safety performance which could result in lower demand for our services;
  • changes in environmental laws and regulations such as increased regulation of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, which could have an adverse impact on the demand for oil and gas;
  • terrorism, social, civil and political unrest in the foreign jurisdictions where we operate;
  • fluctuations in foreign exchange, interest rates and tax rates; and
  • other unforeseen conditions which could impact the use of services supplied by Precision and Precision's ability to respond to such conditions.
INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)
(Stated in thousands of Canadian dollars)   June 30 ,
2017 		  December 31,
2016
ASSETS        
Current assets:        
  Cash $ 95,064 $ 115,705
  Accounts receivable   284,302   293,682
  Income tax recoverable   41,085   38,087
  Inventory   25,737   24,136
Total current assets   446,188   471,610
Non-current assets:        
  Property, plant and equipment   3,422,824   3,641,889
  Intangibles   2,834   3,316
  Goodwill   206,237   207,399
Total non-current assets   3,631,895   3,852,604
Total assets $ 4,078,083 $ 4,324,214
         
LIABILITIES AND EQUITY        
Current liabilities:        
  Accounts payable and accrued liabilities $ 202,285 $ 240,736
Total current liabilities   202,285   240,736
Non-current liabilities:        
  Share based compensation   11,631   27,387
  Provisions and other   11,669   12,421
  Long-term debt   1,844,773   1,906,934
  Deferred tax liabilities   113,747   174,618
Total non-current liabilities   1,981,820   2,121,360
Shareholders' equity:        
  Shareholders' capital   2,319,293   2,319,293
  Contributed surplus   41,478   38,937
  Deficit   (611,312)   (552,568)
  Accumulated other comprehensive income   144,519   156,456
Total shareholders' equity   1,893,978   1,962,118
Total liabilities and shareholders' equity $ 4,078,083 $ 4,324,214
 
 
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)   2017   2016   2017   2016
Revenue $ 275,524 $ 163,979 $ 621,324 $ 465,706
Expenses:                
  Operating   198,996   111,712   435,202   283,549
  General and administrative   20,008   28,260   45,294   55,447
  Restructuring   -   1,607   -   5,046
Earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange and depreciation and amortization  

56,520

  

22,400

  

140,828

  

121,664
Depreciation and amortization   95,799   96,611   192,962   191,860
Operating loss   (39,279)   (74,211)   (52,134)   (70,196)
Foreign exchange   (798)   754   (751)   8,335
Finance charges   34,532   33,161   67,514   69,398
Gain on repurchase of unsecured senior notes   -   -   -   (4,873)
Loss before income taxes   (73,013)   (108,126)   (118,897)   (143,056)
Income taxes:                
  Current   (640)   (11,395)   250   (14,359)
  Deferred   (36,243)   (39,054)   (60,403)   (51,137)
    (36,883)   (50,449)   (60,153)   (65,496)
Net loss $ (36,130) $ (57,677) $ (58,744) $ (77,560)
Net loss per share:                
  Basic $ (0.12) $ (0.20) $ (0.20) $ (0.26)
  Diluted $ (0.12) $ (0.20) $ (0.20) $ (0.26)
INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)
    Three months ended June 30,   Six months ended June 30,
(Stated in thousands of Canadian dollars)   2017   2016   2017   2016
Net loss $ (36,130) $ (57,677) $ (58,744) $ (77,560)
Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency   (57,408)   6,107   (75,962)   (147,991)
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax   48,901   (5,473)   64,025   120,000
Comprehensive loss $ (44,637) $ (57,043) $ (70,681) $ (105,551)
INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)
    Three months ended June 30,   Six months ended June 30,
(Stated in thousands of Canadian dollars)   2017   2016   2017   2016
Cash provided by (used in):                
Operations:                
  Net loss $ (36,130) $ (57,677) $ (58,744) $ (77,560)
  Adjustments for:                
    Long-term compensation plans   (602)   7,565   2,331   15,089
    Depreciation and amortization   95,799   96,611   192,962   191,860
    Gain on repurchase of unsecured senior notes   -   -   -   (4,873)
    Foreign exchange   (1,402)   3,554   (1,354)   11,537
    Finance charges   34,532   33,161   67,514   69,398
    Income taxes   (36,883)   (50,449)   (60,153)   (65,496)
    Other   (607)   518   (777)   140
    Income taxes paid   (1,711)   (4,808)   (2,761)   (10,575)
    Income taxes recovered   -   67   332   67
    Interest paid   (68,351)   (61,478)   (70,259)   (69,509)
    Interest received   168   1,564   1,381   2,143
Funds provided by (used in) operations   (15,187)   (31,372)   70,472   62,221
Changes in non-cash working capital balances   17,926   52,037   (33,963)   70,618
    2,739   20,665   36,509   132,839
Investments:                
  Purchase of property, plant and equipment   (28,437)   (53,424)   (50,529)   (80,585)
  Proceeds on sale of property, plant and equipment  
3,563		  
1,548		  
5,781		  
3,705
  Income taxes recovered   -   2,917   -   2,917
  Changes in non-cash working capital balances   (2,175)   6,825   (10,566)   (19,284)
    (27,049)   (42,134)   (55,314)   (93,247)
Financing:                
  Repurchase of unsecured senior notes   -   -   -   (8,409)
  Debt issue costs   -   (1,155)   (341)   (1,155)
  Issuance of common shares on the exercise of options  
-		  
1,724		  
-		  
1,914
    -   569   (341)   (7,650)
Effect of exchange rate changes on cash and cash equivalents  
(1,206)		  
223		  
(1,495)		  
(21,022)
Increase (decrease) in cash and cash equivalents   (25,516)   (20,677)   (20,641)   10,920
Cash and cash equivalents, beginning of period   120,580   476,356   115,705   444,759
Cash and cash equivalents, end of period $ 95,064 $ 455,679 $ 95,064 $ 455,679
 
 
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, 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
(Stated in thousands of Canadian dollars)

Shareholders'
capital

Contributed
surplus

 Accumulated
other
comprehensive
income

Deficit

Total
equity
Balance at January 1, 2016 $ 2,316,321 $ 35,800 $ 166,101 $ (397,013) $2,121,209
Net loss for the period - - - (77,560) (77,560)
Other comprehensive loss for the period
-
-
(27,991)
-
(27,991)
Share options exercised 2,955 (1,041) - - 1,914
Share based compensation expense
-
1,983
-
-
1,983
Balance at June 30, 2016 $ 2,319,276 $ 36,742 $ 138,110 $ (474,573) $2,019,555