PDS
$1.86
Precision Drilling
($.11)
(5.58%)
Earnings Details
3rd Quarter September 2018
Thursday, October 25, 2018 6:00:00 AM
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Summary

Precision Drilling (PDS) Recent Earnings

Precision Drilling (PDS) reported a 3rd Quarter September 2018 loss of $0.08 per share on revenue of $292.7 million. The consensus estimate was a loss of $0.06 per share on revenue of $308.7 million. Revenue grew 16.7% on a year-over-year basis.

Precision Drilling Corp is an North American provider of oil & natural gas drilling & related services & products. It specialized in providing onshore drilling services in conventional & unconventional oil & natural gas basins in Canada and US.

Results
Reported Earnings
($0.08)
Earnings Whisper
-
Consensus Estimate
($0.06)
Reported Revenue
$292.7 Mil
Revenue Estimate
$308.7 Mil
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Precision Drilling Corporation Announces 2018 Third Quarter Unaudited Financial Results

CALGARY, Alberta, Oct. 25, 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 third quarter financial results:

  • Revenue of $382 million was an increase of 22% over the prior year comparative quarter.
  • Net loss of $31 million ($0.10 per share) compares to a net loss of $26 million ($0.09 per share) in the third quarter of 2017.
  • Earnings before income taxes, loss on repurchase and redemption of unsecured senior notes, finance charges, foreign exchange and depreciation and amortization (adjusted EBITDA see “NON-GAAP MEASURES”) of $81 million was 11% higher than the third quarter of 2017.
  • Funds provided by operations (see “NON-GAAP MEASURES”) of $64 million versus $85 million in the prior year comparative quarter.
  • Third quarter ending cash balance was $110 million, up $45 million from December 31, 2017.
  • Third quarter capital expenditures were $29 million.

On October 5, we announced that we had entered into an arrangement agreement with Trinidad Drilling Limited (Trinidad) pursuant to which Precision agreed to acquire all the issued and outstanding common shares of Trinidad on the basis of 0.445 common shares of Precision for each outstanding Trinidad share. The aggregate transaction value is approximately $1,028 million, based on Precision’s share price as of October 4, 2018 and including the assumption of approximately $477 million in Trinidad net debt as of June 30, 2018. Upon completion of the transaction, existing holders of Trinidad shares will collectively own 29.1% of Precision. The transaction provides for payment of a non-completion fee of $20 million by Trinidad in certain circumstances if the transaction is not completed.

Precision’s President and CEO Kevin Neveu stated: “During the third quarter Precision remained firmly on track to deliver on our three key priorities for 2018: enhancing financial performance through higher utilization and improved margins; generating free cash flow for reducing total debt levels; and commercializing advanced rig technologies. Although third quarter weather-related delays in Canada, rig reactivation costs associated with seven rigs in the U.S., and other one-time transaction costs negatively impacted period cashflows, our team’s persistent focus on cash management delivered an increased cash balance and increased total liquidity for the third consecutive quarter.”

“Our cash generating potential and liquidity position remain strong. We expect to achieve the upper range of our debt reduction target for 2018 and will continue our long-term debt reduction program, reducing total debt, including debt repayments earlier this year, by $300 million to $500 million before the end of 2021.” 

“We stand behind our Board-supported agreement to combine with Trinidad and remain firm that our offer of 29.1 percent of Precision shares to the Trinidad shareholders is fair, offering far more value creation upside than other available options.  We believe the combined company will create significant value for both Precision and Trinidad shareholders with immediate cost synergies and strong strategic fit.  Additionally, the incremental free cash flow generating potential of this combination will support Precision’s ongoing long-term debt reduction targets with potential to accelerate our stated timeline.  The combined platform, particularly the 61 Trinidad high specification AC rigs and enhanced U.S. and international exposure, improves our fixed cost leverage and market presence in those key markets. We are in the process of completing required regulatory filings and will provide updates as new information becomes available.”

“In the U.S., despite recent capital markets volatility, market indications for High Performance rig demand in 2019 are promising as development drilling in unconventional basins continues to shift to the most technically capable and operationally efficient rigs, benefiting Precision with our Super Series fleet. Current customer demand for Precision’s Super Triple rigs is hitting levels not experienced since 2014 and our leading-edge day rates are trending above US$25,000 per day with customers increasingly willing to sign longer term contracts. Precision signed 13 term contracts in the U.S. this quarter and five term contracts in October pointing to continued strong demand for our Super Triple rigs. All 18 of these term contracts were priced higher, with increases ranging from a few hundred dollars per day to more than $5,000 per day. Third quarter activity was slightly lower than expected averaging 76 rigs, but with recent rig activations we have 80 rigs running today, our highest activity level since 2014 and our strongest market share since we entered the U.S. a decade ago. During the quarter we incurred increased costs related to reactivation and restocking of rigs, totaling US$3 million to US$5 million that we do not expect to incur in the fourth quarter. Several of the rigs reactivated had not been active since 2015. These costs added to our daily operating costs and negatively impacted field margins.” 

“Our Canadian business continues to generate strong free cash flow with a High Performance fleet and limited capital requirements and we expect to continue on this path into 2019. We currently have 58 active rigs with quarter-to-date activity largely tracking 2017 levels. While there are well-founded concerns regarding commodity price differentials in the WCSB, early indications from our customers suggest a winter drilling season in-line with last year and strong demand in Deep Basin liquids plays. The demand for our Super Triples is leading to longer term customer contract commitments, with five term contracts signed year-to-date including two during the quarter, compared to zero in all of 2017. We are encouraged with the positive final investment decision from LNG Canada and believe Precision is well-positioned to benefit from incremental high spec rig demand and generally improving natural gas fundamentals.”

“Internationally, we have eight rigs working under contract, five in Kuwait and three in Saudi Arabia. Two of the three Saudi Arabia rigs were recently contracted through the end of the year and negotiations are well underway for multi-year extension. Construction of our sixth Kuwait rig remains on time and on budget for mid-2019 deployment and we are realizing the scale benefits of a world-class drilling operation in country. We are actively tendering our four idle rigs in the Middle East region as we continue to seek increased scale in Saudi Arabia.”

“Our technology initiatives are progressing well toward our 2018 commercialization target. We now have 25 Process Automation Control (PAC) systems deployed in the field, demonstrating to our customers the system’s ability to deliver consistent and repeatable, high-quality wells while improving safety, performance and operational efficiency. PAC has been successfully utilized to automate drilling routines on approximately 290 wells this year and system utilization is increasing as we continue to “field harden” the technology.  Precision, its partners, customers and several third parties have 15 drilling performance applications (Apps) under development with several Apps in field trials. Our progress and customer interest in Apps is well ahead of our initial expectations. Our optimization team is now fully equipped to run analytics on live streaming data giving drillers the required insights on 16 distinct activities to help optimize the drilling process in real-time. Our Directional Guidance System (DGS) technology is also making a difference having drilled over two and a half million feet to date on over 100 wells in 2018, all enabled by DGS software. Our customers are very encouraged with the results and prospects of each of these technologies and we expect increasing revenue and margin impact in 2019,” concluded Mr. Neveu.

SELECT FINANCIAL AND OPERATING INFORMATION

Adjusted EBITDA and funds provided by operations are Non-GAAP measures. See “NON-GAAP MEASURES.”

 
Financial Highlights
 
 Three months ended September 30, Nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts)2018  2017  % Change  2018  2017  % Change 
Revenue 382,457   314,504   21.6   1,114,179   974,037   14.4 
Adjusted EBITDA(1) 80,988   73,239   10.6   240,639   214,067   12.4 
Net loss (30,648)  (26,287)  16.6   (95,942)  (85,031)  12.8 
Cash provided by operations 31,961   56,757   (43.7)  199,845   93,266   114.3 
Funds provided by operations(1) 64,368   85,140   (24.4)  218,619   155,612   40.5 
Capital spending:                       
Expansion 9,909   2,336   324.2   26,380   10,980   140.3 
Upgrade 11,545   7,168   61.1   28,355   34,102   (16.9)
Maintenance and infrastructure 6,913   6,257   10.5   30,247   12,238   147.2 
Intangibles 660   6,757   (90.2)  10,880   15,727   (30.8)
Proceeds on sale (3,757)  (4,273)  (12.1)  (12,437)  (10,054)  23.7 
Net capital spending 25,270   18,245   38.5   83,425   62,993   32.4 
Net loss per share:                       
Basic and diluted (0.10)  (0.09)  11.1   (0.33)  (0.29)  13.8 
(1)           See “NON-GAAP MEASURES”.
 

 

Operating Highlights
 Three months ended September 30, Nine months ended September 30,
 2018  2017  % Change  2018  2017  % Change 
Contract drilling rig fleet 257   256   0.4   257   256   0.4 
Drilling rig utilization days:                       
Canada 4,798   4,487   6.9   14,100   13,945   1.1 
U.S. 7,013   5,593   25.4   19,396   15,114   28.3 
International 736   736   -   2,184   2,184   - 
Revenue per utilization day:                       
Canada(1) (Cdn$) 19,538   19,980   (2.2)  21,273   21,092   0.9 
U.S.(2) (US$) 21,399   19,026   12.5   21,296   19,732   7.9 
International (US$) 50,007   50,528   (1.0)  49,959   50,214   (0.5)
Operating cost per utilization day:                       
Canada (Cdn$) 14,164   13,656   3.7   14,294   13,764   3.9 
U.S. (US$) 14,151   12,591   12.4   14,071   13,917   1.1 
Service rig fleet 210   210   -   210   210   - 
Service rig operating hours 37,169   42,653   (12.9)  121,694   128,523   (5.3)
Revenue per operating hour (Cdn$) 708   638   11.0   696   635   9.6 
(1)  Includes lump sum revenue from contract shortfall for the nine months ended September 30, 2018 and prior year comparatives.
(2)  2017 comparative periods include revenue from idle but contracted rig days.
 

 

Financial Position
                                      
                                           
 (Stated in thousands of Canadian dollars, except ratios)September 30, 2018  December 31, 2017                                      
Working capital(1) 223,024   232,121                                      
Cash 109,762   65,081                                      
Long-term debt(2) 1,698,651   1,730,437                                      
Total long-term financial liabilities 1,718,653   1,754,059                                      
Total assets 3,785,874   3,892,931                                      
Long-term debt to long-term debt plus equity ratio 0.50   0.49                                      
                                             
(1) See “NON-GAAP MEASURES”.
(2)  Net of unamortized debt issue costs.
 

Summary for the three months ended September 30, 2018:

  • Revenue this quarter was $382 million which is 22% higher than the third quarter of 2017. The increase in revenue is primarily the result of higher activity and higher average day rates in our U.S. contract drilling business. Compared with the third quarter of 2017 our activity for the quarter, as measured by drilling rig utilization days increased 25% and 7% in the U.S. and Canada, respectively, and remained consistent internationally. Revenue from our Contract Drilling Services segment increased over the comparative prior year period by 25% while revenue in our Completion and Production Services segment was down 4%.

  • Adjusted EBITDA (see “NON-GAAP MEASURES”) this quarter of $81 million is an increase of $8 million from the third quarter of 2017. Our adjusted EBITDA as a percentage of revenue was 21% this quarter, compared with 23% in the comparative quarter of 2017. Adjusted EBITDA this quarter was positively impacted by higher activity and day rates in the U.S. offset by higher share-based incentive compensation from an increase in the Corporation’s share price versus the comparative prior year period. Total share-based incentive compensation expensed in the quarter was $8 million compared to $2 million in the third quarter of 2017. See discussion on share-based incentive compensation under “Other Items” later in this report for additional details.

  • Operating loss (see “NON-GAAP MEASURES”) this quarter was $10 million compared with an operating loss of $17 million in the third quarter of 2017. Operating results this quarter were positively impacted by the increase in activity and average day rates in our U.S. contract drilling business.

  • General and administrative expenses this quarter were $30 million, $8 million higher than the third quarter of 2017. The increase is due to higher share-based incentive compensation expense tied to the price of our common shares (see “Other Items” later in this report) partially offset by a strengthening of the Canadian dollar on our U.S. dollar denominated costs.

  • Net finance charges were $31 million, a decrease of $1 million compared with the third quarter of 2017, primarily due to a reduction in interest expense related to debt retired in the fourth quarter of 2017 and the second quarter of 2018 and the impact of the strengthening of the Canadian dollar on our U.S. dollar denominated interest.

  • In Canada, average revenue per utilization day for contract drilling rigs was $19,538 in the third quarter compared to $19,980 in the third quarter of 2017. Overall, shortfall payments received in the prior year comparative quarter were largely offset by higher spot market day rates in the current quarter. During the quarter, we did not recognize any shortfall payments in revenue compared with $5 million in the prior year comparative period. Excluding the impact of shortfall payment revenue, average day rates were up 4%. Revenue per utilization day in the U.S. increased in the third quarter of 2018 to US$21,399 from US$19,026 in the prior year third quarter. The increase in the U.S. revenue rate was the result of higher day rates. During the quarter, we had turnkey revenue of US$0.4 million compared with nil in the 2017 comparative period and revenue from idle but contracted rigs of US$0.3 million compared with nil in the prior year comparative period. On a sequential basis, revenue per utilization day excluding revenue from turnkey and idle but contracted rigs increased by US$1,085 due to higher fleet average day rates.

  • Average operating costs per utilization day for drilling rigs in Canada increased to $14,164 compared with the prior year third quarter of $13,656. The increase in average costs was due to timing of equipment certification costs. On a sequential basis, operating costs per day decreased by $2,548 compared to the second quarter of 2018 due to higher fixed cost absorption from higher activity coming out of spring break-up. In the U.S., operating costs for the quarter on a per day basis increased to US$14,151 in 2018 compared with US$12,591 in 2017 due to costs associated with reactivating and restocking rigs, timing of repair costs and higher labour-related costs due to crew configuration. On a sequential basis, operating costs per day increased by $125 compared to the second quarter of 2018 as higher rig operating costs were partially offset by no turnkey activity in the current period.

  • We realized revenue from international contract drilling of US$37 million in the third quarter of 2018, in-line with the prior year period. Average revenue per utilization day in our international contract drilling business was US$50,007 consistent with the comparable prior year quarter.

  • Directional drilling services realized revenue of $7 million in the third quarter of 2018 compared with $6 million in the prior year period. 
  • Funds provided by operations (see “NON-GAAP MEASURES”) in the third quarter of 2018 were $64 million, a decrease of $21 million from the prior year comparative quarter of $85 million. The decrease was primarily the result of the timing of interest payments and tax refunds received in the prior year comparative period partially offset by improved operating results.

  • Capital expenditures were $29 million in the third quarter, an increase of $7 million over the same period in 2017. Capital spending for the quarter included $21 million for upgrade and expansion capital, $7 million for the maintenance of existing assets and infrastructure spending and $1 million for intangibles related to a new ERP system.

Summary for the nine months ended September 30, 2018:

  • Revenue for the first nine months of 2018 was $1,114 million, an increase of 14% from the 2017 period.

  • Operating loss (see “NON-GAAP MEASURES”) was $26 million, a decrease of $43 million over the same period in 2017. Operating loss was 2% of revenue in 2018 compared with 7% of revenue in 2017. Operating results this year were positively impacted by increased activity and pricing in our North American contract drilling businesses.

  • General and administrative costs were $91 million, an increase of $23 million from 2017. The increase was due to higher share-based incentive compensation that is tied to the price of our common shares (see “Other Items” later in this report) partially offset by the strengthening of the Canadian dollar on our U.S. dollar denominated costs.

  • Net finance charges were $95 million, a decrease of $5 million from 2017 primarily due to a reduction in interest expense related to debt retired in 2017 and the effect of a stronger Canadian dollar on our U.S. dollar denominated interest expense partially offset by higher interest income earned in the comparative period.

  • Funds provided by operations (see “NON-GAAP MEASURES”) in the first nine months of 2018 were $219 million, an increase of $63 million from the prior year comparative period of $156 million.

  • Capital expenditures for the purchase of property, plant and equipment were $96 million for the nine months of 2018, an increase of $23 million over the same period in 2017. Capital spending for 2018 to date includes $55 million for upgrade and expansion capital, $30 million for the maintenance of existing assets and infrastructure and $11 million for intangibles related to a new ERP system.

STRATEGY

Precision’s strategic priorities for 2018 are as follows:

  1. Reduce debt by generating free cash flow while continuing to fund only the most attractive investment opportunities – we generated $219 million in funds provided by operations (see “NON-GAAP MEASURES”) in the first nine months of 2018, representing a $63 million increase over the prior year comparative period. Utilizing cash generated in the first nine months of 2018, we reduced debt by $77 million through a partial redemption of our 2021 unsecured senior notes and open market debt repurchases of our 2021 and 2024 notes. We communicated a firm goal to reduce debt by $75 to $125 million in 2018 and have successfully achieved the low end of that range in the first nine months of this year. We expect to achieve the upper range of our debt reduction target for 2018. In addition, we ended the third quarter with $110 million of cash on the balance sheet.

  2. Reinforce Precision’s High Performance competitive advantage by deploying Process Automation Controls (PAC), Directional Guidance Systems (DGS) and Drilling Performance Apps (Apps) on a wide scale basis – year to date in 2018 we have drilled over 100 wells using our DGS compared to 58 wells in all of 2017. We have 25 rigs currently running in the field with PAC and have drilled approximately 290 wells with this technology in 2018 compared to 154 in all of 2017. Earlier this year we also equipped our training rigs in Nisku and Houston with PAC technology. Customer adoption is rising, and we expect to be running a total of 31 systems in the field by year end, continuing full scale deployment and commercialization. Additionally, we are deploying revenue generating Apps on several rigs and currently have 15 Apps in varying stages of commercial development showcasing the open platform of our PAC system. Several Apps are customer-built and supported by Precision’s PAC platform with specific hosting agreements in place.
  1. Enhance financial performance through higher utilization and improved operating margins – in the first nine months of 2018 overall utilization days are 14% higher than the prior year comparative period while average operating margins (revenue less operating costs) are up 24%, 4% and 5% in our U.S., international and Canadian contract drilling businesses, respectively.

OUTLOOK

For the third quarter of 2018, the average West Texas Intermediate (WTI) price of oil was 45% higher than the prior year comparative period while the average Henry Hub gas price was in-line and the average AECO price was 25% lower. According to the Petroleum Services Society of Canada for the year to date period ending October 22, 2018 Western Canada Select traded at an average discount to WTI of $33.80 per barrel and was trading at a discount of $56.74 on October 22, 2018.

 
 Three months ended September 30,  Year ended December 31, 
 2018  2017  2017 
Average oil and natural gas prices           
Oil           
West Texas Intermediate (per barrel) (US$) 69.77   48.03   50.95 
Natural gas           
Canada           
AECO (per MMBtu) (CDN$) 1.24   1.66   2.16 
United States           
Henry Hub (per MMBtu) (US$) 2.93   2.93   2.98 

Contracts

Year to date in 2018 we have entered into 54 term contracts. The following chart outlines the average number of drilling rigs by quarter that we had under contract for 2018 and 2019 as of October 24, 2018.

  Average for the quarter ended 2018  Average for the quarter ended 2019 
  Mar. 31  June 30  Sept. 30  Dec. 31  Mar. 31  June 30  Sept. 30  Dec. 31 
Average rigs under term contract
  as of October 24, 2018:
                                
Canada  8   9   9   11   8   7   7   6 
U.S.  36   48   50   48   37   23   14   10 
International  8   8   8   8   6   5   5   5 
Total  52   65   67   67   51   35   26   21 

The following chart outlines the average number of drilling rigs that we had under contract for 2017 and the average number of rigs we have under contract for 2018 and 2019 as of October 24, 2018.

  Average for the year ended                                                                               
  2017  2018  2019                                                                               
Average rigs under term contract
  as of October 24, 2018:
                                                                                          
Canada  20   9   7                                                                               
U.S.  29   45   21                                                                               
International  8   7   5                                                                               
Total  57   61   33                                                                               

In Canada, term contracted rigs normally generate 250 utilization days per year because of the seasonal nature of well site access. In most regions in the U.S. and internationally, term contracts normally generate 365 utilization days per year.

Drilling Activity

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

 Average for the quarter ended 2017  2018 
 Mar. 31  June 30  Sept. 30  Dec. 31  Mar. 31  June 30  Sept. 30 
Average Precision active rig count:                           
Canada 76   29   49   54   72   31   52 
U.S. 47   59   61   58   64   72   76 
International 8   8   8   8   8   8   8 
Total 131   96   118   120   144   111   136 

For the first nine months of 2018, drilling activity has increased relative to this time last year in the U.S. and is down slightly in Canada. According to industry sources, as of October 19, 2018, the U.S. active land drilling rig count was up approximately 18% from the same point last year and the Canadian active land drilling rig count was down approximately 5%. To date in 2018, approximately 64% of the Canadian industry’s active rigs and 81% of the U.S. industry’s active rigs were drilling for oil targets, compared with 53% for Canada and 80% for the U.S. at the same time last year.

Industry Conditions

We expect Tier 1 rigs to remain the preferred rigs of customers globally. The economic value created by the significant drilling and mobility efficiencies delivered by the most advanced XY pad walking rigs has been highlighted and widely accepted by our customers. The trend to longer-reach horizontal completions and importance of the rig delivering these complex wells consistently and efficiently has been well established by the industry. We expect demand for leading edge high efficiency Tier 1 rigs will continue to strengthen, as drilling rig capability has been a key economic facilitator of horizontal/unconventional resource exploitation. Development and field application of drilling equipment process automation coupled with closed loop drilling controls and de-manning of rigs will continue this technical evolution while creating further cost efficiencies and performance value for customers.

Capital Spending

Capital spending in 2018 is expected to be $135 million and includes $52 million for sustaining and infrastructure, $71 million for upgrade and expansion and $12 million on intangibles related to a new ERP system. We expect that the $135 million will be split $115 million in the Contract Drilling Services segment, $6 million in the Completion and Production Services segment and $14 million to the Corporate segment.


SEGMENTED FINANCIAL RESULTS

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

 Three months ended September 30,  Nine months ended September 30, 
(Stated in thousands of Canadian dollars)2018  2017  % Change  2018  2017  % Change 
Revenue:                       
Contract Drilling Services 347,494   278,569   24.7   1,004,649   864,957   16.2 
Completion and Production Services 36,297   37,816   (4.0)  114,045   113,546   0.4 
Inter-segment eliminations (1,334)  (1,881)  (29.1)  (4,515)  (4,466)  1.1 
  382,457   314,504   21.6   1,114,179   974,037   14.4 
Adjusted EBITDA:(1)                       
Contract Drilling Services 95,596   81,994   16.6   290,003   242,690   19.5 
Completion and Production Services 4,628   4,251   8.9   7,870   9,174   (14.2)
Corporate and Other (19,236)  (13,006)  47.9   (57,234)  (37,797)  51.4 
  80,988   73,239   10.6   240,639   214,067   12.4 
(1)  See “NON-GAAP MEASURES”.
 


SEGMENT REVIEW OF CONTRACT DRILLING SERVICES
 Three months ended September 30,  Nine months ended September 30, 
(Stated in thousands of Canadian dollars, except where noted)2018  2017  % Change  2018  2017  % Change 
Revenue 347,494   278,569   24.7   1,004,649   864,957   16.2 
Expenses:                       
Operating 242,792   189,143   28.4   686,948   598,040   14.9 
General and administrative 9,106   7,432   22.5   27,698   24,227   14.3 
Adjusted EBITDA(1) 95,596   81,994   16.6   290,003   242,690   19.5 
Depreciation 80,742   80,653   0.1   238,621   251,907   (5.3)
Operating earnings (loss)(1) 14,854   1,341   1,007.7   51,382   (9,217)  (657.5)
Operating earnings (loss)(1) as a percentage of revenue 4.3%  0.5%      5.1%  (1.1)%    
 (1)  See “NON-GAAP MEASURES”.

 

  Three months ended September 30, 
Canadian onshore drilling statistics:(1) 2018  2017 
  Precision  Industry(2)  Precision  Industry(2) 
Number of drilling rigs (end of period)  135   604   136   634 
Drilling rig operating days (spud to release)  4,279   16,875   3,998   16,288 
Drilling rig operating day utilization  35%  30%  32%  28%
Number of wells drilled  520   2,046   451   1,977 
Average days per well  8.2   8.2   8.9   8.2 
Number of metres drilled (000s)  1,313   5,502   1,123   5,179 
Average metres per well  2,526   2,689   2,490   2,620 
Average metres per day  307   326   281   318 


  Nine months ended September 30, 
Canadian onshore drilling statistics:(1) 2018  2017 
  Precision  Industry(2)  Precision  Industry(2) 
Number of drilling rigs (end of period)  135   604   136   634 
Drilling rig operating days (spud to release)  12,459   49,256   12,398   49,889 
Drilling rig operating day utilization  34%  29%  34%  29%
Number of wells drilled  1,262   5,179   1,282   5,285 
Average days per well  9.9   9.5   9.7   9.4 
Number of metres drilled (000s)  3,542   14,704   3,352   14,267 
Average metres per well  2,806   2,839   2,615   2,700 
Average metres per day  284   299   270   286 
(1)  Canadian operations only.
(2)  Canadian Association of Oilwell Drilling Contractors (“CAODC”), and Precision – excludes non-CAODC rigs and non-reporting CAODC members.


United States onshore drilling statistics:(1)2018  2017 
 Precision  Industry(2)  Precision  Industry(2) 
Average number of active land rigs for quarters ended:               
March 31 64   951   47   722 
June 30 72   1,021   59   874 
September 30 76   1,032   61   927 
Year to date average 71   1,001   55   841 
(1)  United States lower 48 operations only.
(2)  Baker Hughes rig counts.

Revenue from Contract Drilling Services was $347 million this quarter, or 25% higher than the third quarter of 2017, while adjusted EBITDA (see “NON-GAAP MEASURES”) increased by 17% to $96 million. The increase in revenue was primarily due to higher utilization days as well as higher spot market rates in the U.S. During the quarter we did not recognize any shortfall payments in our Canadian contract drilling business compared with $5 million in the prior year comparative period. In the U.S. we recognized turnkey revenue of US$0.4 million compared with nil in the comparative period and we recognized US$0.3 million in idle but contracted revenue compared with nil in the comparative quarter of 2017.

Drilling rig utilization days in Canada (drilling days plus move days) were 4,798 during the third quarter of 2018, an increase of 7% compared to 2017 primarily due to increased industry activity despite wet weather in September which delayed certain rigs from moving to new rig locations.  Drilling rig utilization days in the U.S. were 7,013, or 25% higher than the same quarter of 2017 as our U.S. activity was up with higher industry activity. Drilling rig utilization days in our international business were 736, in-line with the same quarter of 2017.

Compared with the same quarter in 2017, drilling rig revenue per utilization day in Canada decreased 2% as lower shortfall revenue in the current quarter was partially offset by increases in spot market compared with the prior period. Drilling rig revenue per utilization day for the quarter in the U.S. was up 12% compared to prior year as we realized higher average day rates. International revenue per utilization day was in-line with the prior year comparative period.

In Canada, 11% of our utilization days in the quarter were generated from rigs under term contract, compared with 18% in the third quarter of 2017. In the U.S., 67% of utilization days were generated from rigs under term contract as compared with 55% in the third quarter of 2017.

Operating costs were 70% of revenue for the quarter, two percentage points higher than the prior year period. On a per utilization day basis, operating costs for the drilling rig division in Canada were higher than the prior year period due to timing of equipment certification costs to prepare rigs for upcoming winter work. In the U.S., operating costs for the quarter on a per day basis were higher than the prior year period primarily due to costs associated with reactivating and restocking rigs, timing of repair costs and higher labour-related costs due crew configuration.

Depreciation expense in the quarter was in-line with the third quarter of 2017.

 
SEGMENT REVIEW OF COMPLETION AND PRODUCTION SERVICES
 
 Three months ended September 30,  Nine months ended September 30, 
(Stated in thousands of Canadian dollars, except where noted)2018  2017  % Change  2018  2017  % Change 
Revenue 36,297   37,816   (4.0)  114,045   113,546   0.4 
Expenses:                       
Operating 30,138   31,674   (4.8)  100,216   98,773   1.5 
General and administrative 1,531   1,891   (19.0)  5,959   5,599   6.4 
Adjusted EBITDA(1) 4,628   4,251   8.9   7,870   9,174   (14.2)
Depreciation 6,641   6,731   (1.3)  18,528   21,228   (12.7)
Operating loss(1) (2,013)  (2,480)  (18.8)  (10,658)  (12,054)  (11.6)
Operating loss(1) as a percentage of revenue (5.5)%  (6.6)%      (9.3)%  (10.6)%    
Well servicing statistics:                       
Number of service rigs (end of period) 210   210   -   210   210   - 
Service rig operating hours 37,169   42,653   (12.9)  121,694   128,523   (5.3)
Service rig operating hour utilization 19%  22%  (13.6)  21%  22%  (4.5)
Service rig revenue per operating hour 708   638   11.0   696   635   9.6 
(1)  See “NON-GAAP MEASURES”.

Revenue from Completion and Production Services was down $2 million or 4% compared with the third quarter of 2017 due to lower activity in our Canadian well servicing and rental businesses partially offset by higher camp activity. Our service rig operating hours in the quarter were down 13% from the third quarter of 2017 while rates increased an average of 11%. Approximately 97% of our third quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 92% of its revenue from Canadian operations and 8% from U.S. operations compared with the third quarter of 2017 where 90% of revenue was generated in Canada and 10% in the U.S.

Average service rig revenue per operating hour in the quarter was $708 or $70 higher than the third quarter of 2017. The increase was primarily the result of increased costs passed through to the customer.

Adjusted EBITDA (see “NON-GAAP MEASURES”) was higher than the third quarter of 2017 primarily because of higher average rates and improved cost structure, slightly offset by lower activity.  

Operating costs as a percentage of revenue was 83% compared with the prior year comparative quarter of 84%.

Depreciation in the quarter was in-line with the prior year comparative period.

SEGMENT REVIEW OF CORPORATE AND OTHER

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA (see “NON-GAAP MEASURES”) loss of $19 million, a $6 million increase compared with the third quarter of 2017 primarily due to higher share-based incentive compensation and costs incurred associated with our arrangement agreement with Trinidad.

OTHER ITEMS

Share-based Incentive Compensation Plans

We have several cash-settled share-based incentive plans for non-management directors, officers, and other eligible employees. The fair values of the amounts payable under these plans are recognized as an expense with a corresponding increase in liabilities over the period that the participant becomes entitled to payment. The recorded liability is re-established at the end of each reporting period until settlement with the resultant change to fair value of the liability recognized in net earnings (loss) for the period.

We also have two equity-settled share-based incentive plans. Under the Executive Performance Share plan, which commenced in May 2017, the fair value of the PSUs granted is calculated at the date of grant using a Monte Carlo simulation, and that value is recorded as compensation expense over the grant's vesting period with an offset to contributed surplus. Upon redemption of the PSUs into common shares, the associated amount is reclassified from contributed surplus to shareholders' capital. The share option plan is treated similarly, except that the fair value of the share purchased options granted are valued using the Black-Scholes option pricing model and consideration paid by employees upon exercise of the equity purchase options are recognized in share capital.

A summary of the amounts expensed (recovered) under these plans during the reporting periods are as follows:

 
 Three months ended September 30,  Nine months ended September 30, 
(Stated in thousands of Canadian dollars)2018  2017  2018  2017 
Cash settled share-based incentive plans 5,128   770   20,599   (1,544)
Equity settled share-based incentive plans:               
Executive PSU 1,595   540   4,344   1,361 
Stock option plan 937   823   2,655   2,543 
Total share-based incentive compensation plan expense 7,660   2,133   27,598   2,360 
                
Allocated:               
Operating 2,292   691   9,093   1,125 
General and Administrative 5,368   1,442   18,505   1,235 
  7,660   2,133   27,598   2,360 
                

Cash settled shared-based compensation expense increased $4 million in the current quarter to $5 million compared to $1 million in the same quarter in 2017. The increase is primarily due to the increasing share price experienced in the current quarter compared to a declining share price in the comparative 2017 period.

Executive PSU share-based incentive compensation expense for the quarter was $2 million compared to $1 million in the same quarter in 2017. This increase is a result of the plan being implemented part way through the second quarter in 2017 and from additional grants in 2018.

Financing Charges

Net financial charges for the quarter were $31 million, a decrease of $1 million compared with the third quarter of 2017 primarily because of a stronger Canadian dollar on our U.S. dollar denominated interest expense and a reduction in interest expense related to debt retired in the fourth quarter of 2017 and the second quarter of 2018.

Income Tax

Income tax expense for the quarter was a recovery of $9 million compared with a recovery of $23 million in the same quarter in 2017. The recoveries are due to negative pretax earnings.

LIQUIDITY AND CAPITAL RESOURCES

The oilfield services business is inherently cyclical in nature. To manage this, we focus on maintaining a strong balance sheet so we have the financial flexibility we need to continue to manage our growth and cash flow, regardless of where we are in the business cycle. We maintain a variable operating cost structure so we can be responsive to changes in demand.

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

 
Liquidity
 
Amount Availability Used for Maturity
Senior facility (secured)      
US$500 million(1) (extendible, revolving
term credit facility with US$250 million(2) 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 $26 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$3 million in
outstanding letters of credit
 Letters of credit  
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)  Upon closing of the arrangement agreement to acquire Trinidad we have a commitment from one of our lenders to increase the size of our revolving credit facility to US$600 million.
(2)  Increases to US$300 million at the end of the covenant relief period of March 31, 2019.

As of September 30, 2018, we had $1,724 million outstanding under our unsecured senior notes. The current blended cash interest cost of our debt is approximately 6.6%.

In the second quarter we redeemed US$50 million of our 6.5% unsecured senior notes due 2021 and repurchased and cancelled US$3 million principal amount of our 2021 notes and US$5 million principal of our 2024 notes.


Covenants

Following is a listing of our currently applicable financial covenants and the calculations as of September 30, 2018.

 Covenant As of September 30,
2018
 
Senior Facility     
Consolidated senior debt to consolidated covenant EBITDA(1)< 2.50  0.00 
Consolidated covenant EBITDA to consolidated interest expense(1)> 2.00  2.52 
Senior Notes     
Consolidated interest coverage ratio> 2.00  2.46 
(1)  For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.

At September 30, 2018, we were in compliance with the covenants of our senior credit facility and unsecured senior notes.

Senior Facility

The senior credit facility requires that we comply with certain covenants including a leverage ratio of consolidated senior debt to consolidated Covenant EBITDA (see “NON-GAAP MEASURES”) of less than 2.5:1. For purposes of calculating the leverage ratio consolidated senior debt only includes secured indebtedness.

Under the senior credit facility, we are required to maintain a ratio of consolidated Covenant EBITDA (see “NON-GAAP MEASURES”) to consolidated interest expense for the most recent four consecutive quarters, of greater than 2.0:1 for the periods ending September 30, and December 31, 2018 and March 31, 2019. For periods ending after March 31, 2019 the ratio reverts to 2.5:1.

The senior credit facility prevents us from making distributions prior to April 1, 2019, after which, distributions are subject to a pro forma consolidated senior net leverage covenant of less than or equal to 1.75:1. The senior credit facility also limits the redemption and repurchase of junior debt subject to a pro forma consolidated senior net leverage covenant ratio of less than or equal to 1.75:1.

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

Unsecured Senior Notes

The senior notes require that we comply with financial covenants including an incurrence based consolidated interest coverage ratio test of consolidated cash flow, as defined in the senior note agreements, to consolidated interest expense of greater than 2.0:1 for the most recent four consecutive fiscal quarters. In the event that our consolidated interest coverage ratio is less than 2.0:1 for the most recent four consecutive fiscal quarters, the senior notes restrict our ability to incur additional indebtedness.

The senior notes contain a restricted payments covenant that limits our ability to make payments in the nature of dividends, distributions and for repurchases from shareholders. This restricted payment basket grows from a starting point of October 1, 2010 for the 2021 and 2024 senior notes, from October 1, 2016 for the 2023 senior notes and October 1, 2017 for the 2026 senior notes by, among other things, 50% of consolidated cumulative net earnings and decreases by 100% of consolidated cumulative net losses, as defined in the note agreements, and payments made to shareholders. Beginning with the December 31, 2015 calculation the governing net restricted payments basket was negative and as of that date we were no longer able to declare and make dividend payments until such time as the restricted payments baskets once again become positive. For further information, please see the senior note indentures which are available on SEDAR and EDGAR.

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

Hedge of investments in foreign operations

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

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

Average shares outstanding

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

 Three months ended Sept. 30,  Nine months ended Sept. 30, 
(Stated in thousands)2018  2017  2018  2017 
Weighted average shares outstanding 293,740   293,239   293,485   293,239 
Effect of stock options and other equity compensation plans           
Weighted average shares outstanding – basic and diluted 293,740   293,239   293,485   293,239 


 
QUARTERLY FINANCIAL SUMMARY
 (Stated in thousands of Canadian dollars, except per share amounts) 2017  2018 
Quarters ended December 31  March 31  June 30  September 30 
Revenue  347,187   401,006   330,716   382,457 
Adjusted EBITDA(2)  90,914   97,469   62,182   80,988 
Net loss  (47,005)  (18,077)  (47,217)  (30,648)
Net loss per basic and diluted share  (0.16)  (0.06)  (0.16)  (0.10)
Funds provided by operations(2)  28,323   104,026   50,225   64,368 
Cash provided by operations  23,289   38,189   129,695   31,961 


 (Stated in thousands of Canadian dollars, except per share amounts) 2016  2017 
Quarters ended December 31  March 31  June 30  September 30 
Revenue(1)  302,653   368,673   290,860   314,504 
Adjusted EBITDA(2)  65,000   84,308   56,520   73,239 
Net loss  (30,618)  (22,614)  (36,130)  (26,287)
Net loss per basic and diluted share  (0.10)  (0.08)  (0.12)  (0.09)
Funds provided by (used in) operations(2)  11,466   85,659   (15,187)  85,140 
Cash provided by (used in) operations  (27,846)  33,770   2,739   56,757 
(1)  Comparatives for revenue have changed for the periods ending December 2016, March 2017 and June 2017 to reflect a recast of certain amounts previously netted against operating expense. See our 2017 Annual Report.
(2)  See “NON-GAAP MEASURES”.
 

CRITICAL ACCOUNTING JUDGEMENTS AND ESTIMATES

Because of the nature of our business, we are required to make judgments and estimates in preparing our Consolidated Interim Financial Statements that could materially affect the amounts recognized. Our judgments and estimates are based on our past experiences and assumptions we believe are reasonable in the circumstances. The critical judgments and estimates used in preparing the Interim Financial Statements are described in our 2017 Annual Report and there have been no material changes to our critical accounting judgments and estimates during the three and nine-month periods ended September 30, 2018 except for those impacted by the adoption of new accounting standards.

NON-GAAP MEASURES

In this press release we reference non-GAAP (Generally Accepted Accounting Principles) measures. Adjusted EBITDA, Covenant EBITDA, Operating Earnings (Loss), Funds Provided by (Used in) Operations and Working Capital are terms used by us to assess performance as we believe they provide useful supplemental information to investors. These terms do not have standardized meanings prescribed under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures used by other companies.


Adjusted EBITDA

We believe that adjusted EBITDA (earnings before income taxes, loss on repurchase and redemption of unsecured senior notes, finance charges, foreign exchange, and depreciation and amortization), as reported in the Interim Consolidated Statement of Loss, is a useful measure, because it gives an indication of the results from our principal business activities prior to consideration of how our activities are financed and the impact of foreign exchange, taxation and depreciation and amortization charges.


Covenant EBITDA

Covenant EBITDA, as defined in our senior credit facility agreement, is used in determining the Corporation’s compliance with its covenants. Covenant EBITDA differs from Adjusted EBITDA by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts.


Operating Earnings (Loss)

We believe that operating earnings (loss), as reported in the Interim Consolidated Statements of Loss, is a useful measure because it provides an indication of the results of our principal business activities before consideration of how those activities are financed and the impact of foreign exchange and taxation.


Funds Provided By (Used In) Operations

We believe that funds provided by (used in) operations, as reported in the Interim Consolidated Statements of Cash Flow, is a useful measure because it provides an indication of the funds our principal business activities generate prior to consideration of working capital, which is primarily made up of highly liquid balances.


Working Capital

We define working capital as current assets less current liabilities as reported on the Interim Consolidated Statement of Financial Position.


CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS

Certain statements contained in this report, including statements that contain words such as "could", "should", "can", "anticipate", "estimate", "intend", "plan", "expect", "believe", "will", "may", "continue", "project", "potential" and similar expressions and statements relating to matters that are not historical facts constitute "forward-looking information" within the meaning of applicable Canadian securities legislation and "forward-looking statements" within the meaning of the "safe harbor" provisions of the United States Private Securities Litigation Reform Act of 1995 (collectively, "forward-looking information and statements").

In particular, forward looking information and statements include, but are not limited to, the following:

  • our strategic priorities for 2018;
  • our capital expenditure plans for 2018;
  • anticipated activity levels in 2018 and our scheduled infrastructure projects;
  • anticipated demand for Tier 1 rigs;
  • the average number of term contracts in place for 2018 and 2019;
  • expectation for U.S. operating costs to be lower in the fourth quarter of 2018;
  • our future debt reduction plans beyond 2018; and
  • the anticipated financial, operational and strategic benefits of the proposed Trinidad Drilling transaction.

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

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

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

  • volatility in the price and demand for oil and natural gas;
  • fluctuations in the demand for contract drilling, well servicing and ancillary oilfield services;
  • our customers’ inability to obtain adequate credit or financing to support their drilling and production activity;
  • changes in drilling and well servicing technology which could reduce demand for certain rigs or put us at a competitive disadvantage;
  • shortages, delays and interruptions in the delivery of equipment supplies and other key inputs;
  • the effects of seasonal and weather conditions on operations and facilities;
  • the availability of qualified personnel and management;
  • a decline in our safety performance which could result in lower demand for our services;
  • changes in environmental laws and regulations such as increased regulation of hydraulic fracturing or restrictions on the burning of fossil fuels and greenhouse gas emissions, which could have an adverse impact on the demand for oil and gas;
  • terrorism, social, civil and political unrest in the foreign jurisdictions where we operate;
  • fluctuations in foreign exchange, interest rates and tax rates; and
  • other unforeseen conditions which could impact the use of services supplied by Precision and Precision’s ability to respond to such conditions.

Readers are cautioned that the forgoing list of risk factors is not exhaustive. Additional information on these and other factors that could affect our business, operations or financial results are included in reports on file with applicable securities regulatory authorities, including but not limited to Precision’s Annual Information Form for the year ended December 31, 2017, which may be accessed on Precision’s SEDAR profile at www.sedar.com or under Precision’s EDGAR profile at www.sec.gov. The forward-looking information and statements contained in this news release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, except as required by law.


INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

 (Stated in thousands of Canadian dollars) September 30,
2018
  December 31,
2017
 
ASSETS        
Current assets:        
Cash $109,762  $65,081 
Accounts receivable  342,175   322,585 
Income tax recoverable     29,449 
Inventory  32,115   24,631 
Total current assets  484,052   441,746 
Non-current assets:        
Income tax recoverable  2,307   2,256 
Deferred tax assets  33,518   41,822 
Property, plant and equipment  3,024,684   3,173,824 
Intangibles  35,406   28,116 
Goodwill  205,907   205,167 
Total non-current assets  3,301,822   3,451,185 
Total assets $3,785,874  $3,892,931 
         
LIABILITIES AND EQUITY        
Current liabilities:        
Accounts payable and accrued liabilities $257,449  $209,625 
Income taxes payable  3,579    
Total current liabilities  261,028   209,625 
         
Non-current liabilities:        
Share based compensation  10,328   13,536 
Provisions and other  9,674   10,086 
Long-term debt  1,698,651   1,730,437 
Deferred tax liability  76,279   118,911 
Total non-current liabilities  1,794,932   1,872,970 
Shareholders’ equity:        
Shareholders’ capital  2,322,280   2,319,293 
Contributed surplus  50,124   44,037 
Deficit  (780,546)  (684,604)
Accumulated other comprehensive income  138,056   131,610 
Total shareholders’ equity  1,729,914   1,810,336 
Total liabilities and shareholders’ equity $3,785,874  $3,892,931 


INTERIM CONSOLIDATED STATEMENTS OF LOSS (UNAUDITED)

  Three Months Ended September 30,  Nine Months Ended September 30, 
(Stated in thousands of Canadian dollars, except per share amounts) 2018  2017  2018  2017 
                 
Revenue $382,457  $314,504  $1,114,179  $974,037 
Expenses:                
Operating  271,596   218,936   782,649   692,347 
General and administrative  29,873   22,329   90,891   67,623 
Earnings before income taxes, loss on
  repurchase and redemption of unsecured senior
  notes, finance charges, foreign exchange and
  depreciation and amortization
  80,988   73,239   240,639   214,067 
Depreciation and amortization  90,690   90,555   266,619   283,517 
Operating loss  (9,702)  (17,316)  (25,980)  (69,450)
Foreign exchange  (952)  (685)  819   (1,436)
Finance charges  31,176   32,218   94,958   99,732 
Loss on repurchase and redemption of unsecured
  senior notes
        1,176    
Loss before income taxes  (39,926)  (48,849)  (122,933)  (167,746)
Income taxes:                
Current  1,231   89   6,396   339 
Deferred  (10,509)  (22,651)  (33,387)  (83,054)
   (9,278)  (22,562)  (26,991)  (82,715)
Net loss $(30,648) $(26,287) $(95,942)  (85,031)
Net loss per share:                
Basic and Diluted $(0.10) $(0.09) $(0.33) $(0.29)


INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)

  Three Months Ended September 30,  Nine Months Ended September 30, 
(Stated in thousands of Canadian dollars) 2018  2017  2018  2017 
Net loss $(30,648) $(26,287) $(95,942) $(85,031)
Unrealized gain (loss) on translation of assets and
  liabilities of operations denominated in foreign
  currency
  (46,370)  (79,729)  46,956   (155,691)
Foreign exchange gain (loss) on net investment hedge
  with U.S. denominated debt, net of tax
  38,060   68,057   (40,510)  132,082 
Comprehensive loss $(38,958) $(37,959) $(89,496) $(108,640)


INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

  Three Months Ended September 30,  Nine Months Ended September 30, 
(Stated in thousands of Canadian dollars) 2018  2017  2018  2017 
Cash provided by (used in):                
Operations:                
  Net loss $(30,648) $(26,287) $(95,942) $(85,031)
  Adjustments for:                
  Long-term compensation plans  5,074   1,945   19,000   4,276 
  Depreciation and amortization  90,690   90,555   266,619   283,517 
  Foreign exchange  (1,648)  (239)  (215)  (1,593)
  Finance charges  31,176   32,218   94,958   99,732 
  Income taxes  (9,278)  (22,562)  (26,991)  (82,715)
  Other  (109)  72   (1,242)  (705)
  Loss on repurchase and redemption of
    unsecured senior notes
        1,176    
  Income taxes paid  (363)  (539)  (3,969)  (3,300)
  Income taxes recovered  3,921   11,600   31,508   11,932 
  Interest paid  (24,732)  (1,877)  (67,253)  (72,136)
  Interest received  285   254   970   1,635 
Funds provided by operations  64,368   85,140   218,619   155,612 
Changes in non-cash working capital balances  (32,407)  (28,383)  (18,774)  (62,346)
   31,961   56,757   199,845   93,266 
Investments:                
Purchase of property, plant and equipment  (28,367)  (15,761)  (84,982)  (57,320)
Purchase of intangibles  (660)  (6,757)  (10,880)  (15,727)
Proceeds on sale of property, plant and
  equipment
  3,757   4,273   12,437   10,054 
  Changes in non-cash working capital balances  10,114   (150)  2,082   (10,716)
   (15,156)  (18,395)  (81,343)  (73,709)
Financing:                
Debt amendment fees           (341)
Redemption and repayment of unsecured
  senior notes
        (76,657)   
Issuance of common shares on the exercise of
  options
  275      275    
   275      (76,382)  (341)
Effect of exchange rate changes on cash and cash
  equivalents
  (1,987)  (1,684)  2,561   (3,179)
Increase in cash and cash equivalents  15,093   36,678   44,681   16,037 
Cash and cash equivalents, beginning of period  94,669   95,064   65,081   115,705 
Cash and cash equivalents, end of period $109,762  $131,742  $109,762  $131,742 


INTERIM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)

 (Stated in thousands of Canadian dollars) Shareholders’
capital
  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           (95,942)  (95,942)
Other comprehensive income for the period        6,446      6,446 
Shares issued on redemption of
  non-management directors' DSUs
  2,609   (809)        1,800 
Share options exercised  378   (103)        275 
Share based compensation expense     6,999         6,999 
Balance at September 30, 2018 $2,322,280  $50,124  $138,056  $(780,546) $1,729,914 


 (Stated in thousands of Canadian dollars) Shareholders’
capital
  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           (85,031)  (85,031)
Other comprehensive loss for the period        (23,609)     (23,609)
Share based compensation expense     3,904         3,904 
Balance at September 30, 2017 $2,319,293  $42,841  $132,847  $(637,599) $1,857,382 
 
 

THIRD QUARTER 2018 EARNINGS CONFERENCE CALL AND WEBCAST

Precision Drilling Corporation has scheduled a conference call and webcast to begin promptly at 12:00 noon MT (2:00 p.m. ET) on Thursday, October 25, 2018.

The conference call dial in numbers are 1-844-515-9176 or 614-999-9312.

A live webcast of the conference call will be accessible on Precision’s website at www.precisiondrilling.com by selecting “Investor Relations”, then “Webcasts & Presentations”. Shortly after the live webcast, an archived version will be available for approximately 60 days.

An archived recording of the conference call will be available approximately one hour after the completion of the call until October 30, 2018 by dialing 1-855-859-2056 or 404-537-3406, pass code 4795636.

About Precision

Precision is a leading provider of safe and High Performance, High Value services to the oil and gas industry. Precision provides customers with access to an extensive fleet of contract drilling rigs, directional drilling services, well service and snubbing rigs, camps, rental equipment, and water treatment units backed by a comprehensive mix of technical support services and skilled, experienced personnel.

Precision is headquartered in Calgary, Alberta, Canada. Precision is listed on the Toronto Stock Exchange under the trading symbol “PD” and on the New York Stock Exchange under the trading symbol “PDS”.

For further information, please contact:

Carey Ford, Senior Vice President and Chief Financial 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

Precision Drilling Logo Vertical RGB high.jpg

Source: Precision Drilling Corporation