Precision Drilling Corporation Announces 2016 Third Quarter Financial Results

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CALGARY, ALBERTA–(Marketwired – Oct. 21, 2016) – Precision Drilling Corporation (TSX:PD)(NYSE:PDS) –

(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.

For the third quarter of 2016, we recorded earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment and depreciation and amortization (adjusted EBITDA see “Additional GAAP Measures”) of $41 million, 63% lower than the third quarter of 2015. Our activity for the quarter, as measured by drilling rig utilization days, decreased 37% in Canada, 42% in the U.S. and 36% internationally, compared to the third quarter of 2015. Our adjusted EBITDA as a percentage of revenue was 21% this quarter, compared to 30% in the third quarter of 2015. The decrease in adjusted EBITDA as a percent of revenue was mainly due to decreased activity in all of our businesses and lower spot market pricing.

We recorded a net loss this quarter of $47 million, or $0.16 per diluted share, compared to a net loss of $87 million, or $0.30 per diluted share, in the third quarter of 2015.

During the third quarter of 2015, significant decreases in industry activity resulting from the decline in oil and natural gas prices and its impact on current and future business were indicators of impairment in some of our cash generating asset groups resulting in an after tax impairment charges of $74 million, or $0.25 per share.

Revenue this quarter was $202 million or 45% lower than the third quarter of 2015, mainly due to decreased activity in all of our operations. Revenue from our Contract Drilling Services and Completion and Production Services segments decreased over the comparative prior year period by 45% and 44%, respectively.

Net loss for the first nine months of 2016 was $125 million, or $0.43 per diluted share, compared to a net loss of $92 million, or $0.32 per diluted share in 2015, while revenue was $668 million, or 45% less than 2015.

Our current expected capital plan for 2016 is $222 million, an increase of $20 million compared to the $202 million capital plan announced in July 2016. The capital increase relates to upgrade capital backed by customer contracts.

Kevin Neveu, Precision’s President and Chief Executive Officer, stated: “Customer sentiment has substantially improved on the backdrop of strengthening commodity prices supported by OPEC strategic intentions and improving supply and demand fundamentals. This improved outlook is evident in the conversations we are having with customers, but more importantly in our activity increases, recent contract bookings and improving pricing environment. We continue to remain cautious as we believe this optimism may be fragile and sensitive to commodity price volatility.”

“Earlier this month our fourth rig in Kuwait commenced operations and we expect the fifth rig to start later in November. Both rigs were on budget and delivered ahead of schedule. We are pleased with our growth in this region, and with improved commodity prices we expect customer inquiries will increase.”

“During the third quarter, we gained visibility through rig commitments in both the U.S. and Canada and report seven rig years added to our 2017 contract book, bringing average rigs under contract for next year to 42. With 37 rigs operating in the U.S. today, our activity is up 70% from second quarter lows, while the industry increase is approximately 35%. We believe our market share increase and contract additions reflect both the desirability of Precision’s high performance Super Triple rigs and our customers’ improving outlook.”

“While the Permian Basin is attracting the most attention, Precision has met customer needs reactivating rigs in several U.S. basins including the Permian, STACK, SCOOP, DJ, Marcellus and Bakken. Customer demand for XY walking, long-reach capable rigs is strong, industry supply is limited and pricing power is emerging as we have begun to successfully implement price increases on our Super Triple rigs.”

“In Canada, while industry activity has seasonally improved and is now approaching 2015 levels, it is still historically low and pricing remains highly competitive. For Precision, the Canadian Deep Basin continues to be an area of strength where Super Triple rigs have a strong market share. We expect this segment of our fleet to be fully utilized through the coming winter drilling season.”

“At the end of the quarter, we had a cash balance of $352 million and an undrawn revolving credit facility. With improved visibility during the quarter our capital structure priorities continued to evolve from solely protecting cash balances, to taking additional steps to reduce total debt. In 2016, Precision has repurchased approximately US$56 million of face value debt from our 2020 and 2021 notes, reducing total debt levels and generating interest savings of approximately $5 million annually. We intend to continue reducing our total debt levels, while ensuring adequate liquidity, using cash and cash flow from operations over the next few years.”

“For the remainder of the year, we will continue to focus on providing operational excellence to the field, reactivating rigs in multiple basins in the U.S., preparing for winter drilling season in Canada, and keeping an active recruitment and training program to crew up rigs. We have reactivated 51 rigs since 2016 lows and are pleased to have hired nearly 1,000 field personnel, many of whom were previously part of the Precision family,” concluded Mr. Neveu.

SELECT FINANCIAL AND OPERATING INFORMATION

Adjusted EBITDA and funds provided by operations are additional GAAP measures. See “ADDITIONAL GAAP MEASURES”.

Financial Highlights

Three months ended September 30, Nine months ended September 30,
(Stated in thousands of Canadian dollars, except per share amounts) 2016 2015 % Change 2016 2015 % Change
Revenue 201,802 364,089 (44.6 ) 667,508 1,210,671 (44.9 )
Adjusted EBITDA 41,411 111,031 (62.7 ) 163,075 362,770 (55.0 )
Adjusted EBITDA % of revenue 20.5% 30.5% 24.4% 30.0%
Net loss (47,377 ) (86,700 ) (45.4 ) (124,937 ) (92,484 ) 35.1
Cash provided by operations 17,515 61,049 (71.3 ) 150,354 446,064 (66.3 )
Funds provided by operations 31,688 99,228 (68.1 ) 93,909 307,587 (69.5 )
Capital spending:
Expansion 67,672 30,518 121.7 133,605 322,039 (58.5 )
Upgrade 4,902 10,110 (51.5 ) 6,335 42,145 (85.0 )
Maintenance and infrastructure 5,588 12,964 (56.9 ) 18,807 28,275 (33.5 )
Proceeds on sale (2,125 ) (1,085 ) 95.9 (5,830 ) (7,559 ) (22.9 )
Net capital spending 76,037 52,507 44.8 152,917 384,900 (60.3 )
Loss per share:
Basic (0.16 ) (0.30 ) (46.7 ) (0.43 ) (0.32 ) (34.4 )
Diluted (0.16 ) (0.30 ) (46.7 ) (0.43 ) (0.32 ) (34.4 )
Dividends paid per share – 0.07 (100.0 ) – 0.21 (100.0 )

Operating Highlights

Three months ended September 30, Nine months ended September 30,
2016 2015 % Change 2016 2015 % Change
Contract drilling rig fleet 253 330 (23.3 ) 253 330 (23.3 )
Drilling rig utilization days:
Canada 2,853 4,505 (36.7 ) 8,050 13,062 (38.4 )
U.S. 2,689 4,647 (42.1 ) 7,773 17,063 (54.4 )
International 644 999 (35.5 ) 2,044 3,262 (37.3 )
Revenue per utilization day:
Canada (Cdn$) 17,523 22,484 (22.1 ) 21,792 23,056 (5.5 )
U.S. (1)(US$) 23,826 26,202 (9.1 ) 27,842 26,238 6.1
International (US$) 43,879 38,893 12.8 43,191 42,666 1.2
Operating cost per utilization day:
Canada (Cdn$) 10,584 12,102 (12.5 ) 11,393 11,969 (4.8 )
U.S. (US$) 14,939 15,925 (6.2 ) 15,565 15,079 3.2
Service rig fleet 163 177 (7.9 ) 163 177 (7.9 )
Service rig operating hours 26,588 36,673 (27.5 ) 66,281 113,048 (41.4 )
Revenue per operating hour (Cdn$) 599 786 (23.8 ) 654 791 (17.3 )
(1) For the three month periods ended September 30 and the nine months ended September 30, 2015 includes revenue from idle but contracted rig days. For the nine months ended September 30, 2016 includes idle but contracted rig days and contract cancellation payments.

Financial Position

(Stated in thousands of Canadian dollars, except ratios) September 30,
2016		 December 31,
2015
Working capital 392,106 536,815
Long-term debt(1) 2,005,324 2,180,510
Total long-term financial liabilities 2,036,129 2,210,231
Total assets 4,450,324 4,878,690
Long-term debt to long-term debt plus equity ratio(1) 0.50 0.51
(1) Net of unamortized debt issue costs.

Our portfolio of term customer contracts, a scalable operating cost structure and economies achieved through vertical integration of the supply chain all help us manage our business through the industry cycles.

Precision’s strategic priorities for 2016 are as follows:

  1. Maintain strong liquidity to manage through an extended downturn – Sustain adequate liquidity by generating positive operating cash flow, ensure access to our revolving credit facility, and continue a multi-year plan for net debt reduction.
  2. Sustain High Performance, High Value service offering – Continue to deliver maximum efficiency and lower risks to support development drilling programs by operating the highest quality assets in the industry with well-trained, professional crews supported by robust systems that eliminate manual processes and improve automation throughout the Precision organization.
  3. Position for an eventual rebound – Concurrent with right-sizing the organization for the extended downturn, we will take steps to prepare for a rebound:
    1. Asset integrity – maintain high quality and integrity of our Tier 1 drilling fleet by utilizing spare equipment, avoiding fleet cannibalization and maintaining rigorous equipment standards.
    2. People – retain field leadership within the organization, maintain relationships with former crew members and continue to develop leadership and skills of workers within our organization.
    3. Ample liquidity – maintain strong liquidity to fund working capital requirements and other short term commitments that arise when activity levels increase.

For the third quarter of 2016, the average AECO natural gas price and the average West Texas Intermediate price of oil were lower than the 2015 comparable averages while the average Henry Hub natural gas price was higher.

Three months ended September 30, Year ended December 31,
2016 2015 2015
Average oil and natural gas prices
Oil
West Texas Intermediate (per barrel) (US$) 44.97 46.73 48.77
Natural gas
Canada
AECO (per MMBtu) (Cdn$) 2.34 2.91 2.70
U.S.
Henry Hub (per MMBtu) (US$) 2.85 2.74 2.60

Summary for the three months ended September 30, 2016:

  • Operating loss (see “Additional GAAP Measures” in this news release) this quarter was $56 million, or 28% of revenue, compared to an operating loss of $94 million and 26% of revenue in 2015. Operating results in 2016 were negatively impacted by the decrease in drilling activity and day rates in all of our operating segments. In 2015 our operating results were negatively impacted by the recognition of an impairment charge to our property, plant and equipment for $80 million.
  • General and administrative expenses this quarter were $22 million, $2 million lower than the third quarter of 2015. The decrease is primarily due to cost savings initiatives partially offset by higher share based incentive compensation, which is tied to the price of our common shares.
  • Net finance charges were $35 million, in line with the third quarter of 2015.
  • During the quarter we acquired and cancelled US$28 million face value of our 6.625% unsecured senior notes due 2020 and US$18 million face value of our 6.5% unsecured senior notes due 2021 for a total of $56 million, realizing a total gain on repurchase of $5 million.
  • Average revenue per utilization day for contract drilling rigs decreased in the third quarter of 2016 to $17,523 from the prior year third quarter of $22,484 in Canada and decreased in the U.S. to US$23,826 from US$26,202. The decrease in Canada is the result of lower spot market rates, less contract shortfall revenue received in the current quarter and a higher proportion of revenue from shallower drilling activity relative to the 2015 comparative period. The decrease in the U.S. is the result of lower spot market rates and lower turnkey activity partially offset by a higher daily revenue impact from idle but contracted rigs. We had US$3 million in turnkey revenue for the third quarter of 2016 compared with US$6 million in the 2015 comparative period and US$6 million in idle but contracted revenue in the current quarter versus US$13 million in the prior year.
  • Average operating costs per utilization day for drilling rigs in Canada decreased to $10,584, compared to the prior year third quarter of $12,102 primarily because of the prior year recognition of costs associated with moving rigs from the U.S. to Canada offset by the impact of fixed costs on lower activity. In the U.S., operating costs for the quarter on a per day basis decreased to US$14,939 in 2016 compared to US$15,925 in 2015 due to lower turnkey activity and cost savings initiatives partially offset by fixed costs spread over fewer active rigs.
  • We realized revenue from international contract drilling of $37 million in the third quarter of 2016, a $14 million decrease over the prior year period. Average revenue per utilization day in our international contract drilling business was US$43,879 an increase of 13% over the comparable prior year quarter primarily due to rig mix as we have fewer rigs working in the lower day rate jurisdictions.
  • Directional drilling services realized revenue of $6 million in the third quarter of 2016 compared with $12 million in the prior year period. The decrease was primarily the result of a decline in activity in both the U.S. and Canada.
  • Funds provided by operations in the third quarter of 2016 were $32 million, a decrease of $67 million from the prior year comparative quarter of $99 million. The decrease was primarily the result of lower activity levels in the current year period.
  • Capital expenditures for the purchase of property, plant and equipment were $78 million in the third quarter, an increase of $25 million over the same period in 2015. Capital spending for the third quarter of 2016 included $68 million for expansion capital, $5 million for upgrade capital and $5 million for the maintenance of existing assets and infrastructure spending.

Summary for the nine months ended September 30, 2016:

  • Revenue for the first nine months of 2016 was $668 million, a decrease of 45% from the 2015 period.
  • Operating loss was $126 million, an increase of $48 million over the same period in 2015. Operating loss was 19% of revenue in 2016 compared to operating loss of 6% of revenue in 2015. Operating earnings were negatively impacted by the decreased drilling activity and rates in our North American operations. In 2015 our operating results were negatively impacted by the recognition of an impairment charge to our property, plant and equipment for $80 million.
  • General and administrative costs were $79 million, a decrease of $18 million over the first nine months of 2015. The decrease is due to efforts in reducing fixed costs through the downturn partially offset by higher share based incentive compensation that is tied to the price of our common shares and by the weakening Canadian dollar on U.S. dollar denominated costs.
  • Net finance charges were $104 million, an increase of $17 million from the first nine months of 2015 primarily due to the recognition of $14 million interest revenue in the comparative period related to an income tax dispute settlement and the impact of foreign exchange on our U.S. dollar denominated interest.
  • During the first nine months we acquired and cancelled US$28 million face value of our 6.625% unsecured senior notes due 2020 and US$28 million face value of our 6.5% unsecured senior notes due 2021 for a total of $64 million, realizing a total gain on repurchase of $10 million.
  • Funds provided by operations (see “Additional GAAP Measures” in this news release) in the first nine months of 2016 were $94 million, a decrease of $214 million from the prior year comparative period of $308 million.
  • Capital expenditures for the purchase of property, plant and equipment were $159 million in the first nine months of 2016, a decrease of $234 million over the same period in 2015. Capital spending for 2016 to date included $134 million for expansion capital, $6 million for upgrade capital and $19 million for the maintenance of existing assets and infrastructure.

OUTLOOK

Contracts

Our portfolio of term customer contracts provides a base level of activity and revenue. As of October 20, 2016, for the fourth quarter of 2016 we had, on average, term contracts for 27 rigs in Canada, 24 in the U.S. and eight internationally and an average of 31 rigs contracted in Canada, 23 in the U.S. and seven internationally for the full year. As of October 20, 2016, for the full year of 2017 we had a total average of 42 rigs on term contract including 19 in Canada, 15 in the U.S. and eight internationally. 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

In the U.S., our average active rig count in the quarter was 29 rigs, down 22 rigs over the third quarter in 2015 but up five rigs from the second quarter of 2016. We currently have 37 rigs active in the U.S.

In Canada, our average active rig count in the quarter was 31 rigs, a decrease of 18 over the third quarter in 2015 but up 18 rigs from the second quarter of 2016. We currently have 45 rigs active in Canada.

In general, to date in 2016, lower oil prices have caused producers to significantly reduce drilling budgets decreasing demand for drilling rigs, resulting in pricing pressure on spot market day rates. We have recently experienced increased activity and if current commodity prices hold we expect our customers to increase their capital budgets for 2017. We expect Tier 1 rigs to remain the preferred rigs of customers globally and for us to benefit from our completed fleet enhancements.

Internationally, our average active rig count in the quarter was seven rigs, down four rigs over the third quarter in 2015 and in line with the second quarter of 2016. The decrease from the prior year period is the result of three fewer rigs working in Mexico and no rigs currently working in Kurdistan. We currently have eight rigs active internationally. In Kuwait, one new-build rig began working in October and the second new-build rig is expected to begin working later in the fourth quarter.

Industry Conditions

To date in 2016, drilling activity has decreased relative to this time last year for both Canada and the U.S. According to industry sources, as of October 14, 2016, the U.S. active land drilling rig count was down approximately 32% from the same point last year and the Canadian active land drilling rig count was down approximately 9%. The decrease in the North American rig count has resulted in the trend of high-grading toward Tier 1 rigs, which continue to show relative strength given the current market conditions.

In Canada there has been strength 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 2016, approximately 48% of the Canadian industry’s active rigs and 80% of the U.S. industry’s active rigs were drilling for oil targets, compared to 45% for Canada and 77% for the U.S. at the same time last year.

Capital Spending

Capital spending in 2016 is expected to be $222 million:

  • The 2016 capital expenditure plan includes $159 million for expansion capital, $43 million for sustaining and infrastructure expenditures, and $20 million to upgrade existing rigs. We expect that the $222 million will be split $218 million in the Contract Drilling segment and $4 million in the Completion and Production Services segment.
  • Precision’s expansion capital plan for 2016 includes two new-build drilling rigs for Kuwait. We expect to incur another $22 million with respect to these rigs in the fourth quarter.

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, coil tubing, rental, camp and catering and wastewater treatment divisions.

Three months ended September 30, Nine months ended September 30,
(Stated in thousands of Canadian dollars) 2016 2015 % Change 2016 2015 % Change
Revenue:
Contract Drilling Services 178,463 324,067 (44.9 ) 601,080 1,072,075 (43.9 )
Completion and Production Services 24,158 42,961 (43.8 ) 69,343 144,632 (52.1 )
Inter-segment eliminations (819 ) (2,939 ) (72.1 ) (2,915 ) (6,036 ) (51.7 )
201,802 364,089 (44.6 ) 667,508 1,210,671 (44.9 )
Adjusted EBITDA:(1)
Contract Drilling Services(2) 52,180 117,449 (55.6 ) 210,300 404,064 (48.0 )
Completion and Production Services 736 4,304 (82.9 ) (4,039 ) 10,657 (137.9 )
Corporate and other(2) (11,505 ) (10,722 ) 7.3 (43,186 ) (51,951 ) (16.9 )
41,411 111,031 (62.7 ) 163,075 362,770 (55.0 )
(1) See “ADDITIONAL GAAP MEASURES”.
(2) Certain expenses in the prior year have been reclassified to conform to current year presentation.

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)
2016 2015 % Change 2016 2015 % Change
Revenue 178,463 324,067 (44.9 ) 601,080 1,072,075 (43.9 )
Expenses:(1)
Operating 116,871 192,142 (39.2 ) 358,224 618,993 (42.1 )
General and administrative 8,789 11,692 (24.8 ) 29,516 40,102 (26.4 )
Restructuring 623 2,784 (77.6 ) 3,040 8,916 (65.9 )
Adjusted EBITDA(2) 52,180 117,449 (55.6 ) 210,300 404,064 (48.0 )
Depreciation 86,643 113,429 (23.6 ) 257,334 325,667 (21.0 )
Operating (loss) earnings(2) (34,463 ) 4,020 (957.3 ) (47,034 ) 78,397 (160.0 )
Operating earnings (loss) as a percentage of revenue (19.3% ) 1.2% (7.8% ) 7.3%
(1) Certain expenses in the prior year have been reclassified to conform to current year presentation.
(2) See “ADDITIONAL GAAP MEASURES”.
Three months ended September 30,
Canadian onshore drilling statistics:(1) 2016 2015
Precision Industry(2) Precision Industry(2)
Number of drilling rigs (end of period) 135 672 181 765
Drilling rig operating days (spud to release) 2,538 10,401 4,085 16,752
Drilling rig operating day utilization 20% 17% 25% 24%
Number of wells drilled 269 1,115 398 1,476
Average days per well 9.4 9.3 10.3 11.3
Number of metres drilled (000s) 627 2,568 881 3,549
Average metres per well 2,330 2,303 2,214 2,405
Average metres per day 247 247 216 212
Nine months ended September 30,
Canadian onshore drilling statistics:(1) 2016 2015
Precision Industry(2) Precision Industry(2)
Number of drilling rigs (end of period) 135 672 181 765
Drilling rig operating days (spud to release) 7,183 27,833 11,630 50,438
Drilling rig operating day utilization 19% 15% 24% 24%
Number of wells drilled 607 2,490 1,070 3,992
Average days per well 11.8 11.2 10.9 12.6
Number of metres drilled (000s) 1,616 6,328 2,441 10,260
Average metres per well 2,663 2,542 2,281 2,570
Average metres per day 225 227 210 203
(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) 2016 2015
Precision Industry(2) Precision Industry(2)
Average number of active land rigs for quarters ended:
March 31 32 516 80 1,353
June 30 24 397 57 873
September 30 29 465 51 829
Year to date average 28 459 63 1,015
(1) United States lower 48 operations only.
(2) Baker Hughes rig counts.

Revenue from Contract Drilling Services was $178 million this quarter, or 45% lower than the third quarter of 2015, while adjusted EBITDA decreased by 56% to $52 million. The decreases were mainly due to lower drilling rig utilization days in our Canadian, U.S. and international contract drilling businesses.

Drilling rig utilization days in Canada (drilling days plus move days) were 2,853 during the third quarter of 2016, a decrease of 37% compared to 2015 primarily due to the decrease in industry activity resulting from lower commodity prices. Drilling rig utilization days in the U.S. were 2,689 or 42% lower than the same quarter of 2015 as U.S. activity was down due to lower industry activity. Drilling rig utilization days in our international business were 644 or 36% lower than the same quarter of 2015 due to lower activity in Mexico and the Middle East.

Compared to the same quarter in 2015, drilling rig revenue per utilization day was down 22% in Canada due to the decline of spot market rates as industry activity has dropped. Drilling rig revenue per utilization day for the current quarter in the U.S. was down 9% from the prior comparative period, while international revenue per day was up 13%. The decrease in the U.S. average rate was due to lower spot market rates, a lower percentage of revenue coming from turnkey activity, and lower relative idle but contracted revenue. International revenue per day was up due to rig mix.

In Canada, 33% of utilization days in the quarter were generated from rigs under term contract, compared to 54% in the third quarter of 2015. In the U.S., 53% of utilization days were generated from rigs under term contract as compared to 71% in the third quarter of 2015. At the end of the quarter, we had 29 drilling rigs under contract in Canada, 22 in the U.S. and seven internationally.

Operating costs were 65% of revenue for the quarter, which was six 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 primarily because of 2015 move rig move costs partially offset by the impact of fixed costs on lower activity and cost saving initiatives. In the U.S., operating costs for the quarter on a per day basis were lower than the prior year primarily due to lower turnkey activity and cost saving initiatives partially offset by fixed costs spread over lower activity.

General and administrative costs are lower than the prior year by $3 million due to cost saving initiatives taken throughout 2015 and in the first nine months of 2016.

Restructuring costs in the quarter relate to cost cutting measures taken in response to the continued downturn in industry activity levels.

Depreciation expense in the quarter was 24% lower than in the third quarter of 2015 because of a lower asset base after decommissioning equipment and the recording of an impairment charge to our property, plant and equipment in the fourth quarter of 2015 partially offset by new-build rigs deployed in 2015 and 2016.

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) 2016 2015 % Change 2016 2015 % Change
Revenue 24,158 42,961 (43.8 ) 69,343 144,632 (52.1 )
Expenses: (1)
Operating 21,883 36,852 (40.6 ) 64,605 124,445 (48.1 )
General and administrative 1,485 1,747 (15.0 ) 6,756 7,716 (12.4 )
Restructuring 54 58 (6.9 ) 2,021 1,814 11.4
Adjusted EBITDA(2) 736 4,304 (82.9 ) (4,039 ) 10,657 (137.9 )
Depreciation 6,759 8,714 (22.4 ) 20,537 26,178 (21.5 )
Impairment of property, plant and equipment – 79,573 (100.0 ) – 79,573 (100.0 )
Operating loss(2) (6,023 ) (83,983 ) (92.8 ) (24,576 ) (95,094 ) (74.2 )
Operating loss as a percentage of revenue (24.9% ) (195.5% ) (35.4% ) (65.7% )
Well servicing statistics:
Number of service rigs (end of period) 163 177 (7.9 ) 163 177 (7.9 )
Service rig operating hours 26,588 36,673 (27.5 ) 66,281 113,048 (41.4 )
Service rig operating hour utilization 18% 22% 15% 23%
(1) Prior year comparative has been changed to conform to the current year calculation.
(2) See “ADDITIONAL GAAP MEASURES”.

Revenue from Completion and Production Services was down $19 million or 44% compared to the third quarter of 2015 due to lower activity levels in all service lines and lower average rates. In response to lower oil prices, customers curtailed spending and activity including well completion and production programs. Our well servicing activity in the quarter was down 28% from the third quarter of 2015. Approximately 83% of our third quarter Canadian service rig activity was oil related.

During the quarter, Completion and Production Services generated 90% of its revenue from Canadian and 10% from U.S. operations.

Average service rig revenue per operating hour in the third quarter was $599 or $187 lower than the third quarter of 2015. The decrease was primarily the result of industry pricing pressure.

Adjusted EBITDA was $4 million lower than the third quarter of 2015 due to a decline in activity and pricing.

Operating costs as a percentage of revenue increased to 91% in the third quarter of 2016, from 86% in the third quarter of 2015. The increase is the result of the impact of fixed costs spread across lower activity levels, as well as lower revenue from pricing pressure.

Depreciation in the quarter was 22% lower than the third quarter of 2015 because of a lower asset base after an impairment charge in the third quarter of 2015.

SEGMENT REVIEW OF CORPORATE AND OTHER

Our Corporate and Other segment provides support functions to our operating segments. The Corporate and Other segment had an adjusted EBITDA loss of $12 million for the third quarter of 2016, slightly higher than the prior year comparable as higher share based incentive compensation was partially offset by cost saving initiatives.

OTHER ITEMS

Net finance charges were $35 million, in line with the third quarter of 2015.

Income tax expense for the quarter was a recovery of $36 million compared with a recovery of $46 million in the same quarter in 2015. Income tax expense is recognized by applying the income tax rate expected for the full financial year to the pre-tax income of the interim reporting period with adjustments for transactions specific to the quarter.

LIQUIDITY AND CAPITAL RESOURCES

The oilfield services business is inherently cyclical in nature. To manage this, we focus on maintaining a strong balance sheet in order to have the financial flexibility we need to continue to manage our growth and cash flow throughout 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 respond 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 April, 2016 we agreed with our lending group to the following amendments to our senior credit facility:

  • The Adjusted EBITDA (as defined in the debt agreement) to interest expense coverage ratio of greater than 2:1 was temporarily reduced to 1.5:1 and reverts to 2.5:1 for periods ending after March 31, 2018;
  • Permit second lien debt not to exceed US$400 million subject to certain terms and conditions;
  • Amend certain negative covenants to, among other things, prohibit distributions during the covenant relief period;
  • Add a new covenant with respect to anti-cash hoarding whereby we are only permitted to draw a maximum of $50 million on the facility if the only purpose is to accumulate cash;
  • Add a new covenant that restricts the repurchase and redemption of unsecured debt subject to a pro-forma minimum liquidity of US$500 million.

During the year we have acquired and cancelled US$28 million face value of our 6.625% unsecured senior notes due 2020 and US$28 million face value of our 6.5% unsecured senior notes due 2021 for a total of $64 million, realizing a total gain on repurchase of $10 million.

As at September 30, 2016 we had $2,028 million outstanding under our senior unsecured notes. The current blended cash interest cost of our debt is approximately 6.2%.

Amount Availability Used for Maturity
Senior facility (secured)
US$550 million (extendible, revolving term credit facility with US$250 million accordion feature) Undrawn, except US$41 million in outstanding letters of credit General corporate purposes June 3, 2019
Operating facilities (secured)
$40 million Undrawn, except $22 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$6 million in outstanding letters of credit Letters of credit
Senior notes (unsecured)
$200 million – 6.5% Fully drawn Debt repayment March 15, 2019
US$622 million – 6.625% Fully drawn Debt repayment and general corporate purposes November 15, 2020
US$372 million – 6.5% Fully drawn Capital expenditures and general corporate purposes December 15, 2021
US$400 million – 5.25% Fully drawn Capital expenditures and general corporate purposes November 15, 2024

Covenants

Senior Facility

The senior credit facility requires that we comply with certain financial 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 Additional GAAP Measures by the exclusion of bad debt expense, restructuring costs and certain foreign exchange amounts. As at September 30, 2016 our consolidated senior debt to Adjusted EBITDA ratio was negative 0.80:1.

Under the senior credit facility we are required to maintain an Adjusted EBITDA coverage ratio, calculated as Adjusted EBITDA to interest expense, of greater than 1.5:1 reverting to 2.5:1 for periods ending after March 31, 2018 for the most recent four consecutive fiscal quarters. As at September 30, 2016 our Adjusted EBITDA coverage ratio was 2.12:1.

The senior credit facility also prevents us from making distributions prior to April 1, 2018 and restricts our ability to repurchase our unsecured 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, 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 September 30, 2016, we were in compliance with the covenants of the senior credit facility.

Senior Notes

The senior notes require that we comply with certain financial covenants including an incurrence based test of Adjusted EBITDA, 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 Adjusted EBITDA to 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 September 30, 2016, Precision is in compliance with this covenant. Based on company projections for the fourth quarter of 2016, the possibility exists that we will not meet the minimum ratio of 2.0:1 for the most recent four consecutive quarters. If this occurs, it would limit our ability to incur additional indebtedness, except as permitted under the agreements, until such time as we are in compliance but would not restrict our access to available funds under the senior credit facility or to refinance 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 by, among other things, 50% of consolidated net earnings and decreases by 100% of consolidated net losses as defined in the note agreements, and payments made to shareholders. As at September 30, 2016 our restricted payments basket is negative and we are no longer able to make dividend payments until such time as the basket once again becomes 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. At September 30, 2016, we were in compliance with the covenants of our senior notes.

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 earnings.

Average shares outstanding

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

Three months ended
September 30,		 Nine months ended
September 30,
2016 2015 2016 2015
Weighted average shares outstanding – basic 293,238 292,912 293,098 292,866
Effect of stock options and other equity compensation plans – – – –
Weighted average shares outstanding – diluted 293,238 292,912 293,098 292,866
QUARTERLY FINANCIAL SUMMARY
(Stated in thousands of Canadian dollars, except per share amounts)
2015 2016
Quarters ended December 31 March 31 June 30 September 30
Revenue 344,953 301,727 163,979 201,802
Adjusted EBITDA(1) 111,095 99,264 22,400 41,411
Net loss: (270,952 ) (19,883 ) (57,677 ) (47,377 )
Per basic share (0.93 ) (0.07 ) (0.20 ) (0.16 )
Per diluted share (0.93 ) (0.07 ) (0.20 ) (0.16 )
Funds provided by (used in) operations(1) 49,503 93,593 (31,372 ) 31,688
Cash provided by operations 70,952 112,174 20,665 17,515
Dividends paid per share 0.07 – – –
2014 2015
Quarters ended December 31 March 31 June 30 September 30
Revenue 618,525 512,120 334,462 364,089
Adjusted EBITDA(1) 234,011 163,384 88,355 111,031
Net earnings (loss): (114,044 ) 24,033 (29,817 ) (86,700 )
Per basic share (0.39 ) 0.08 (0.10 ) (0.30 )
Per diluted share (0.39 ) 0.08 (0.10 ) (0.30 )
Funds provided by operations(1) 172,059 155,186 53,173 99,228
Cash provided by operations 134,887 215,138 169,877 61,049
Dividends paid per share 0.07 0.07 0.07 0.07
(1) See “ADDITIONAL GAAP MEASURES”.

ADDITIONAL GAAP MEASURES

We reference Generally Accepted Accounting Principles (GAAP) measures that are not defined terms under International Financial Reporting Standards to assess performance because we believe they provide useful supplemental information to investors.

Adjusted EBITDA

We believe that adjusted EBITDA (earnings before income taxes, gain on repurchase of unsecured senior notes, financing charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment and depreciation and amortization) as reported in the 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 depreciation and amortization charges.

Operating Earnings (Loss)

We believe that operating earnings (loss), as reported in the 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 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 capital expenditure plans for 2016;
  • the principal use of our free cash in 2016;
  • timing on the commissioning and delivery of two new rigs for Kuwait;
  • our strategic priorities for 2016;
  • our plans to use cash to reduce net debt levels;
  • continuing demand for Tier 1 rigs;
  • the average number of term contracts in place for 2016 and 2017; and
  • the impact that our financial projections may have on our senior note interest coverage ratio.

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 decline in oil prices will continue to 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, 2015, which may be accessed on Precision’s SEDAR profile at www.sedar.com or under Precision’s EDGAR profile at www.sec.gov. The forward-looking information and statements contained in this news release are made as of the date hereof and Precision undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a results of new information, future events or otherwise, except as required by law.

INTERIM CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

(Stated in thousands of Canadian dollars) September30,
2016		 December31,
2015
ASSETS
Current assets:
Cash $ 352,194 $ 444,759
Accounts receivable 205,802 311,595
Income tax recoverable 26,489 –
Inventory 25,438 24,245
Total current assets 609,923 780,599
Non-current assets:
Income tax recoverable – 2,917
Property, plant and equipment 3,630,139 3,883,332
Intangibles 3,673 3,363
Goodwill 206,589 208,479
Total non-current assets 3,840,401 4,098,091
Total assets $ 4,450,324 $ 4,878,690
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 217,817 $ 235,948
Income tax payable – 7,836
Total current liabilities 217,817 243,784
Non-current liabilities:
Share based compensation 16,263 15,201
Provisions and other 14,542 14,520
Long-term debt 2,005,324 2,180,510
Deferred tax liabilities 220,678 303,466
Total non-current liabilities 2,256,807 2,513,697
Shareholders’ equity:
Shareholders’ capital 2,319,293 2,316,321
Contributed surplus 37,819 35,800
Deficit (521,950 ) (397,013 )
Accumulated other comprehensive income 140,538 166,101
Total shareholders’ equity 1,975,700 2,121,209
Total liabilities and shareholders’ equity $ 4,450,324 $ 4,878,690

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) 2016 2015 2016 2015
Revenue $ 201,802 $ 364,089 $ 667,508 $ 1,210,671
Expenses:
Operating 137,935 226,055 419,914 737,402
General and administrative 21,748 23,702 78,765 96,956
Restructuring 708 3,301 5,754 13,543
Earnings before income taxes, gain on repurchase of unsecured senior notes, finance charges, foreign exchange, impairment of goodwill, impairment of property, plant and equipment and depreciation and amortization

41,411

111,031

163,075

362,770
Depreciation and amortization 96,998 125,236 288,858 361,461
Impairment of property, plant and equipment – 79,573 – 79,573
Operating loss (55,587 ) (93,778 ) (125,783 ) (78,264 )
Impairment of goodwill – 16,968 – 16,968
Foreign exchange (1,402 ) (12,510 ) 6,933 (32,598 )
Finance charges 34,673 34,783 104,071 86,813
Gain on repurchase of unsecured senior notes (5,108 ) – (9,981 ) –
Loss before income taxes (83,750 ) (133,019 ) (226,806 ) (149,447 )
Income taxes:
Current (9,999 ) 818 (24,358 ) 8,334
Deferred (26,374 ) (47,137 ) (77,511 ) (65,297 )
(36,373 ) (46,319 ) (101,869 ) (56,963 )
Net loss $ (47,377 ) $ (86,700 ) $ (124,937 ) $ (92,484 )
Net loss per share:
Basic $ (0.16 ) $ (0.30 ) $ (0.43 ) $ (0.32 )
Diluted $ (0.16 ) $ (0.30 ) $ (0.43 ) $ (0.32 )

INTERIM CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (UNAUDITED)

Three months ended
September 30,		 Nine months ended
September 30,
(Stated in thousands of Canadian dollars) 2016 2015 2016 2015
Net loss $ (47,377 ) $ (86,700 ) $ (124,937 ) $ (92,484 )
Unrealized gain (loss) on translation of assets and liabilities of operations denominated in foreign currency 17,895 182,303 (130,096 ) 347,683
Foreign exchange gain (loss) on net investment hedge with U.S. denominated debt, net of tax (15,467 ) (133,400 ) 104,533 (259,985 )
Comprehensive loss $ (44,949 ) $ (37,797 ) $ (150,500 ) $ (4,786 )

INTERIM CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

Three months ended
September 30,		 Nine months ended
September 30,
(Stated in thousands of Canadian dollars) 2016 2015 2016 2015
Cash provided by (used in):
Operations:
Net loss $ (47,377 ) $ (86,700 ) $ (124,937 ) $ (92,484 )
Adjustments for:
Long-term compensation plans 983 (2,091 ) 16,072 10,616
Depreciation and amortization 96,998 125,236 288,858 361,461
Impairment of property, plant and equipment – 79,573 – 79,573
Impairment of goodwill – 16,968 – 16,968
Gain on repurchase of unsecured senior notes (5,108 ) – (9,981 ) –
Foreign exchange (2,563 ) (13,820 ) 8,974 (34,197 )
Finance charges 34,673 34,783 104,071 86,813
Income taxes (36,373 ) (46,319 ) (101,869 ) (56,963 )
Other 425 (58 ) 565 1,291
Income taxes paid (2,512 ) (1,398 ) (13,087 ) (11,186 )
Income taxes recovered 536 – 603 1,111
Interest paid (8,685 ) (7,500 ) (78,194 ) (70,693 )
Interest received 691 554 2,834 15,277
Funds provided by operations 31,688 99,228 93,909 307,587
Changes in non-cash working capital balances (14,173 ) (38,179 ) 56,445 138,477
17,515 61,049 150,354 446,064
Investments:
Purchase of property, plant and equipment (78,162 ) (53,592 ) (158,747 ) (392,459 )
Proceeds on sale of property, plant and equipment 2,125 1,085 5,830 7,559
Income taxes recovered – – 2,917 55,138
Changes in non-cash working capital balances 9,394 (3,985 ) (9,890 ) (158,261 )
(66,643 ) (56,492 ) (159,890 ) (488,023 )
Financing:
Repurchase of unsecured senior notes (55,916 ) – (64,325 ) –
Debt issue costs (59 ) – (1,214 ) (975 )
Dividends paid – (20,504 ) – (61,499 )
Issuance of common shares on the exercise of options 12 – 1,926 93
(55,963 ) (20,504 ) (63,613 ) (62,381 )
Effect of exchange rate changes on cash and cash equivalents 1,606 21,127 (19,416 ) 51,732
Increase (decrease) in cash and cash equivalents (103,485 ) 5,180 (92,565 ) (52,608 )
Cash and cash equivalents, beginning of period 455,679 433,693 444,759 491,481
Cash and cash equivalents, end of period $ 352,194 $ 438,873 $ 352,194 $ 438,873

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, 2016 $ 2,316,321 $ 35,800 $ 166,101 $ (397,013) $ 2,121,209
Net loss for the period – – – (124,937) (124,937)
Other comprehensive loss for the period – – (25,563) – (25,563)
Share options exercised 2,972 (1,046) – – 1,926
Share based compensation expense – 3,065 – – 3,065
Balance at September 30, 2016 $ 2,319,293 $ 37,819 $ 140,538 $ (521,950) $ 1,975,700
(Stated in thousands of Canadian dollars)

Shareholders’
capital

Contributed
surplus

 Accumulated
other
comprehensive
income		 Retained
earnings
(deficit)

Total
equity
Balance at January 1, 2015 $ 2,315,539 $ 31,109 $ 46,292 $ 48,426 $ 2,441,366
Net loss for the period – – – (92,484) (92,484)
Other comprehensive income for the period – – 87,698 – 87,698
Dividends – – – (61,499) (61,499)
Share options exercised 142 (49) – – 93
Shares issued on redemption of non-management directors’ DSUs 640 (324) – – 316
Share based compensation expense – 3,884 – – 3,884
Balance at September 30, 2015 $ 2,316,321 $ 34,620 $ 133,990 $ (105,557) $ 2,379,374

THIRD QUARTER 2016 EARNINGS CONFERENCE CALL AND WEBCAST

Precision Drilling Corporation has scheduled a conference call and webcast to begin promptly at 12:00 p.m. MT (2:00 p.m. ET) on Friday, October 21, 2016.

The conference call dial in numbers are 1-866-696-5910 or 416-340-2217.

A live webcast of the conference call will be accessible on Precision’s website at www.precisiondrilling.com by selecting “Investor Centre”, then “Webcasts and Presentations”. Shortly after the live webcast, an archived version will be available for approximately 30 days.

An archived recording of the conference call will be available approximately one hour after the completion of the call until November 21, 2016 by dialing 1-800-408-3053 or 905-694-9451, pass code 5065869

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, coil tubing services, camps, rental equipment, and wastewater 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”.

Carey Ford
Senior Vice President & Chief Financial Officer
Precision Drilling Corporation
403.716.4566
403.716.4755 (FAX)
www.precisiondrilling.com