Western Energy Services Corp. Releases Third Quarter 2019 Financial and Operating Results
CALGARY, Oct. 23, 2019 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its third quarter 2019 financial and operating results. Additional information relating to the Company, including the Company's financial statements and management's discussion and analysis as at and for the three and nine months ended September 30, 2019 and 2018 will be available on SEDAR at www.sedar.com. Non-International Financial Reporting Standards ("Non-IFRS") measures, such as Adjusted EBITDA, and abbreviations for standard industry terms are included in this press release. All amounts are denominated in Canadian dollars (CDN$) unless otherwise identified.
Third Quarter 2019 Operating Results:
- Third quarter revenue decreased by $11.8 million to $47.1 million in 2019 as compared to $58.9 million in 2018. In the contract drilling segment, revenue totalled $32.8 million in the third quarter of 2019, a decrease of $13.5 million (or 29%) as compared to $46.3 million in the third quarter of 2018. In the production services segment, revenue totalled $14.3 million for the three months ended September 30, 2019, as compared to $12.6 million for the three months ended September 30, 2018, an increase of $1.7 million (or 13%). While activity was higher in the United States and for well servicing in Canada, lower contract drilling and oilfield rental equipment activity in Canada impacted revenue as described below:
- Drilling rig utilization – Operating Days ("Drilling Rig Utilization") in Canada decreased to 22% in the third quarter of 2019 compared to an average of 38% in the same period of the prior year, reflecting a 1,600 basis points ("bps") reduction. The decrease in activity was mainly attributable to mandated crude oil production curtailments in Alberta, coupled with continued market uncertainty and as a result, customers have reduced or cancelled their 2019 drilling programs. Third quarter 2019 Drilling Rig Utilization of 22% represented a discount of 100 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 23%, a decrease as compared to the third quarter of 2018 when Drilling Rig Utilization of 38% was 800 bps higher than the industry average. The decrease in the Company's utilization as compared to the industry average in 2019 was a function of a smaller industry rig fleet, as older rigs continue to be decommissioned and higher specification rigs continue to move out of the Western Canadian Sedimentary Basin ("WCSB"). Western's market share, represented by the Company's Operating Days as a percentage of the CAODC's total Operating Days in the WCSB, decreased to 8.8% in the third quarter of 2019, as compared to 10.3% in the third quarter of 2018. Revenue per Billable Day decreased by 1% in the third quarter of 2019, as compared to the same period in the prior year, as rates on all rig classes have remained relatively constant despite decreased activity in the industry;
- In the United States, six of the Company's eight drilling rigs worked during the quarter, two of which were operating on term contracts. During the fourth quarter of 2018, the Company purchased one Cardium class drilling rig for its fleet in the United States, which commenced operations in the Permian basin. Additionally, a Duvernay class rig from the Canadian fleet was deployed to the Permian Basin in the first quarter of 2019. While Drilling Rig Utilization of 50% in the third quarter of 2019, was consistent with the third quarter of 2018, as a result of a larger and more geographically diversified rig fleet in the third quarter of 2019, Operating Days increased by 32%, as compared to the same period in the prior year. While day rates on the Company's high specification Duvernay class rigs in the Williston Basin in North Dakota remained constant, revenue per Billable Day for the third quarter of 2019 decreased by 9% as the rigs working in the Permian Basin in Texas, worked at lower average day rates, while operating at a significantly lower cost; and
- In Canada, service rig utilization was 33% in the third quarter of 2019 compared to 25% in the same period of the prior year. The increase is due to continued efforts by management to improve activity with existing customers and broaden the Company's customer base, despite customer programs being impacted by wet weather in certain areas, continued market uncertainty and mandated crude oil production curtailments in Alberta. While utilization improved, revenue per Service Hour decreased during the third quarter of 2019 by 4%, as compared to the same period in the prior year, due to pricing pressure in certain operating areas. Higher utilization, offset partially by lower pricing, led to well servicing revenue in the period increasing to $12.1 million, an improvement of $2.3 million (or 24%), as compared to the same period in the prior year.
- Third quarter Adjusted EBITDA decreased by $2.7 million (or 35%) to $5.0 million in 2019 as compared to $7.7 million in the third quarter of 2018. The year over year change in Adjusted EBITDA is due to lower contract drilling and oilfield rental equipment activity in Canada, as well as $0.4 million in costs related to establishing well servicing operations for Western Oilfield Services in the United States and $0.3 million related to restructuring costs, offset by increased activity in the United States and well servicing in Canada.
- Administrative expenses decreased by $0.4 million (or 9%) to $3.9 million, as compared to $4.3 million in the third quarter of 2018, mainly due to lower rent expense as a result of the adoption of IFRS 16, as well as lower employee related costs.
- The Company incurred a net loss of $11.6 million in the third quarter of 2019 ($0.13 per basic common share) as compared to a net loss of $10.1 million in the same period in 2018 ($0.11 per basic common share). The change can be attributed to:
- A $2.7 million decrease in Adjusted EBITDA, mainly due to lower activity in the Canadian contract drilling segment; and
- A $0.1 million increase in finance costs due to higher long term debt balances outstanding in the quarter.
Offsetting the above mentioned items was:
- A $1.0 million decrease in depreciation expense due to certain assets being fully depreciated in the period;
- A $0.2 million change in other items, which include gains and losses on foreign exchange and asset sales;
- A $0.1 million decrease in stock based compensation mainly due to the Company's lower share price; and
- A $0.1 million increase in income tax recovery due to an increased loss before income taxes in the period.
- Third quarter 2019 additions to property and equipment of $1.1 million consist primarily of maintenance capital. In total, additions to property and equipment in the third quarter of 2019 decreased by $2.7 million (or 71%) from the $3.8 million incurred in the third quarter of 2018.
Year to Date 2019 Operating Results:
- Revenue for the nine month period ended September 30, 2019 decreased by $22.7 million to $150.6 million as compared to $173.3 million for the nine month period ended September 30, 2018. In the contract drilling segment, revenue totalled $109.9 million for the nine months ended September 30, 2019, including US$1.3 million of shortfall commitment revenue, and reflects a decrease of $24.9 million (or 18%) as compared to $134.8 million for the nine months ended September 30, 2018. In the production services segment, revenue totalled $40.9 million for the nine months ended September 30, 2019, as compared to $38.7 million in the same period of the prior year, an increase of $2.2 million (or 6%). Activity was higher in the United States and for well servicing in Canada; whereas lower contract drilling and oilfield rental equipment activity in Canada impacted revenue as described below:
- Drilling Rig Utilization in Canada for the nine month period ended September 30, 2019 decreased to 23%, compared to an average of 35% for the nine month period ended September 30, 2018, reflecting a 1,200 bps reduction. The decrease in activity was mainly attributable to mandated crude oil production curtailments in Alberta, coupled with heightened market uncertainty and as a result, customers have reduced or cancelled their 2019 drilling programs. Drilling Rig Utilization of 23% in 2019 represented a premium of 100 bps to the CAODC industry average of 22%, whereas in the first nine months of 2018, Drilling Rig Utilization of 35% represented a 600 bps premium to the CAODC industry average. The decrease in the Company's utilization premium to the industry average in 2019 was a function of a smaller industry rig fleet, as older rigs continue to be decommissioned and higher specification rigs continue to move out of the WCSB. Western's market share, represented by the Company's Operating Days as a percentage of the CAODC's total Operating Days in the WCSB, was 9.1% for the nine months ended September 30, 2019, as compared to 9.8% in the same period of the prior year. Despite lower activity, pricing reflects a 1% improvement in revenue per Billable Day in 2019, as compared to the same period in the prior year, due to rates on all rig classes remaining relatively constant, coupled with changes in the average rig mix;
- In the United States, seven of the Company's eight drilling rigs worked year to date, three of which were operating on term contracts. Additionally, US$1.3 million in shortfall commitment revenue was recognized in the period. During the fourth quarter of 2018, the Company purchased one Cardium class drilling rig for its fleet in the United States, which commenced operations in the Permian basin. Additionally, a Duvernay class rig from the Canadian fleet was deployed to the Permian Basin in the first quarter of 2019. As a result of a larger and more geographically diversified rig fleet for the nine months ended September 30, 2019, Operating Days increased by 57%, as compared to the same period in the prior year. Furthermore, Drilling Rig Utilization improved to 53% for the nine months ended September 30, 2019, compared to 44% in the same period of the prior year. While day rates on the Company's high specification Duvernay class rigs remained constant in the Williston Basin in North Dakota, revenue per Billable Day for the nine months ended September 30, 2019 decreased by 8% as the rigs working in the Permian Basin in Texas, worked at lower average day rates, while operating at a significantly lower cost; and
- In Canada, service rig utilization was 30% for the nine months ended September 30, 2019 compared to 24% in the same period of the prior year. The increase is due to continued efforts by management to improve activity with existing customers and broaden the Company's customer base, despite customer programs being impacted by continued market uncertainty, wet weather in certain areas and mandated crude oil production curtailments in Alberta. While utilization improved, revenue per Service Hour decreased during the nine months ended September 30, 2019 by 6%, as compared to the same period in the prior year, due to pricing pressure in certain operating areas. Higher utilization, offset partially by lower pricing, led to well servicing revenue in the period increasing to $33.6 million, an improvement of $3.7 million (or 13%), as compared to the same period in the prior year.
- Adjusted EBITDA for the nine months ended September 30, 2019 decreased by $5.0 million (or 21%) to $18.7 million as compared to $23.7 million for the nine months ended September 30, 2018. The year over year change is due to lower Adjusted EBITDA in all Canadian divisions, coupled with $1.1 million in costs related to establishing well servicing operations for Western Oilfield Services in the United States and $1.0 million related to restructuring costs, which was offset partially by shortfall commitment revenue and increased contract drilling activity in the United States.
- Administrative expenses for the nine month period ended September 30, 2019 decreased by $1.7 million (or 12%) to $12.5 million, as compared to $14.2 million in the same period of the prior year, mainly due to lower rent expense as a result of the adoption of IFRS 16, coupled with lower employee related costs.
- The Company incurred a net loss of $28.8 million for the nine months ended September 30, 2019 ($0.31 per basic common share) as compared to a net loss of $31.5 million in the same period in 2018 ($0.34 per basic common share). The change can be attributed to:
- A $5.0 million increase in income tax recovery due to the decrease in the Alberta corporate tax rate substantively enacted in the second quarter of 2019 and an increased loss before income taxes in the period;
- A $1.4 million decrease in depreciation expense due to certain assets being fully depreciated in the period;
- A $0.6 million decrease in stock based compensation expense mainly due to the Company's lower share price;
- A $0.4 million decrease in finance costs, mainly due to $0.6 million of non-cash accretion expense recognized in the prior year related to the early redemption of the Company's senior notes; and
- A $0.4 million change in other items, which include gains and losses on foreign exchange and asset sales.
Offsetting the above mentioned items was a $5.0 million decrease in Adjusted EBITDA, mainly due to lower Adjusted EBITDA in all Canadian divisions and startup costs related to establishing well servicing operations for Western Oilfield Services in the US, offset partially by shortfall commitment revenue and increased contract drilling activity in the United States.
- Year to date additions to property and equipment of $5.0 million included $1.4 million of expansion capital and $3.6 million of maintenance capital. In total, additions to property and equipment for the nine months ended September 30, 2019 decreased by $8.9 million (or 64%) from the $13.9 million incurred in the same period of the prior year. The Company incurred expansion capital mainly related to drilling rig upgrades, as well as required maintenance capital, in 2019.
- On January 1, 2019, the Company adopted IFRS 16, Leases, using the modified retrospective method. The adoption of IFRS 16 resulted in an increase in long term debt of $12.8 million, an increase in property and equipment of $10.1 million, a decrease in provisions of $1.4 million, a decrease in the deferred tax liability of $0.4 million, a decrease in other assets of $0.1 million, and a net decrease in retained earnings of $1.1 million. For the three and nine months ended September 30, 2019, the impact of IFRS 16 on Adjusted EBITDA was an increase of $0.8 million and $2.4 million respectively, whereas the impact on net loss was less than $0.1 million in each respective period, as increased Adjusted EBITDA was offset by higher depreciation expense and finance costs.
Selected Financial Information |
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(stated in thousands, except share and per share amounts) |
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Three months ended September 30 |
Nine months ended September 30 |
|||||||||||||||||||||||||||||||||||||||||||||||||||||
Financial Highlights |
2019 |
2018 |
Change |
2019 |
2018 |
Change |
||||||||||||||||||||||||||||||||||||||||||||||||
Revenue |
47,067 |
58,879 |
(20%) |
150,570 |
173,277 |
(13%) |
||||||||||||||||||||||||||||||||||||||||||||||||
Adjusted EBITDA(1) |
4,968 |
7,691 |
(35%) |
18,654 |
23,700 |
(21%) |
||||||||||||||||||||||||||||||||||||||||||||||||
Adjusted EBITDA as a percentage of revenue |
11% |
13% |
(15%) |
12% |
14% |
(14%) |
||||||||||||||||||||||||||||||||||||||||||||||||
Cash flow from operating activities |
(592) |
(1,968) |
(70%) |
22,797 |
28,209 |
(19%) |
||||||||||||||||||||||||||||||||||||||||||||||||
Additions to property and equipment |
1,143 |
3,776 |
(70%) |
5,026 |
13,858 |
(64%) |
||||||||||||||||||||||||||||||||||||||||||||||||
Net loss |
(11,575) |
(10,108) |
15% |
(28,781) |
(31,530) |
(9%) |
||||||||||||||||||||||||||||||||||||||||||||||||
– basic net loss per share |
(0.13) |
(0.11) |
18% |
(0.31) |
(0.34) |
(9%) |
||||||||||||||||||||||||||||||||||||||||||||||||
– diluted net loss per share |
(0.13) |
(0.11) |
18% |
(0.31) |
(0.34) |
(9%) |
||||||||||||||||||||||||||||||||||||||||||||||||
Weighted average number of shares |
||||||||||||||||||||||||||||||||||||||||||||||||||||||
– basic |
92,402,039 |
92,236,159 |
- |
92,338,987 |
92,197,414 |
- |
||||||||||||||||||||||||||||||||||||||||||||||||
– diluted |
92,402,039 |
92,236,159 |
- |
92,338,987 |
92,197,414 |
- |
||||||||||||||||||||||||||||||||||||||||||||||||
Outstanding common shares as at period end |
92,501,314 |
92,304,538 |
- |
92,501,314 |
92,304,538 |
- |
||||||||||||||||||||||||||||||||||||||||||||||||
(1) See "Non-IFRS measures" included in this press release. |
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Three months ended September 30 |
Nine months ended September 30 |
|||||||||||
Operating Highlights(1) |
2019 |
2018 |
Change |
2019 |
2018 |
Change |
||||||
Contract Drilling |
||||||||||||
Canadian Operations: |
||||||||||||
Contract drilling rig fleet: |
||||||||||||
– Average active rig count |
12.1 |
20.6 |
(41%) |
12.6 |
19.6 |
(36%) |
||||||
– End of period |
49 |
50 |
(2%) |
49 |
50 |
(2%) |
||||||
Revenue per Billable Day |
19,547 |
19,822 |
(1%) |
21,188 |
20,962 |
1% |
||||||
Revenue per Operating Day |
21,571 |
21,754 |
(1%) |
23,590 |
23,177 |
2% |
||||||
Operating Days |
1,005 |
1,729 |
(42%) |
3,080 |
4,841 |
(36%) |
||||||
Drilling rig utilization – Billable Days |
25% |
41% |
(39%) |
26% |
39% |
(33%) |
||||||
Drilling rig utilization – Operating Days |
22% |
38% |
(42%) |
23% |
35% |
(34%) |
||||||
CAODC industry average utilization – Operating Days(2) |
23% |
30% |
(23%) |
22% |
29% |
(24%) |
||||||
United States Operations: |
||||||||||||
Contract drilling rig fleet: |
||||||||||||
– Average active rig count |
4.7 |
3.4 |
38% |
4.9 |
2.9 |
69% |
||||||
– End of period |
8 |
6 |
33% |
8 |
6 |
33% |
||||||
Revenue per Billable Day (US$) |
19,436 |
21,467 |
(9%) |
20,151(3) |
21,962 |
(8%) |
||||||
Revenue per Operating Day (US$) |
22,926 |
24,000 |
(4%) |
23,666(3) |
24,447 |
(3%) |
||||||
Operating Days |
368 |
278 |
32% |
1,129 |
718 |
57% |
||||||
Drilling rig utilization – Billable Days |
59% |
56% |
5% |
62% |
49% |
27% |
||||||
Drilling rig utilization – Operating Days |
50% |
50% |
- |
53% |
44% |
20% |
||||||
Production Services |
||||||||||||
Canadian Operations: Well servicing rig fleet: |
||||||||||||
– Average active rig count |
20.9 |
16.3 |
28% |
18.8 |
15.8 |
19% |
||||||
– End of period |
63 |
66 |
(5%) |
63 |
66 |
(5%) |
||||||
Revenue per Service Hour |
631 |
654 |
(4%) |
654 |
693 |
(6%) |
||||||
Service Hours |
19,244 |
15,026 |
28% |
51,388 |
43,090 |
19% |
||||||
Service rig utilization |
33% |
25% |
32% |
30% |
24% |
25% |
||||||
(1) |
See "Non-IFRS Measures" included in this press release. |
|
(2) |
Source: The Canadian Association of Oilwell Drilling Contractors ("CAODC") monthly Contractor Summary. The CAODC industry average is based on Operating Days divided by total available days. |
|
(3) |
Excludes shortfall commitment revenue from take or pay contracts of US$1.3 million for the nine months ended September 30, 2019. |
|
Financial Position at (stated in thousands) |
September 30, 2019 |
December 31, 2018 |
September 30, 2018 |
Working capital |
13,762 |
15,739 |
18,694 |
Property and equipment |
578,834 |
615,395 |
620,169 |
Total assets |
617,943 |
667,295 |
669,079 |
Long term debt |
232,722 |
222,258 |
222,564 |
Western is an oilfield service company focused on three core business lines: contract drilling, well servicing and oilfield rental equipment services. Western provides contract drilling services through its division, Horizon Drilling ("Horizon") in Canada, and its wholly owned subsidiary, Stoneham Drilling Corporation ("Stoneham") in the United States ("US"). Western provides well servicing and oilfield rental equipment services in Canada through its wholly owned subsidiary Western Production Services Corp. ("Western Production Services"). Western Production Services' division, Eagle Well Servicing ("Eagle") provides well servicing operations, while its division, Aero Rental Services ("Aero") provides oilfield rental equipment services. Stoneham's division, Western Oilfield Services, provides well servicing operations in the United States. Financial and operating results for Horizon and Stoneham are included in Western's contract drilling segment, while financial and operating results for Eagle, Aero, and Western Oilfield Services are included in Western's production services segment.
Western has a drilling rig fleet of 57 rigs specifically suited for drilling complex horizontal wells. Western is currently the fourth largest drilling contractor in Canada, based on the CAODC registered rigs, with a fleet of 49 rigs operating through Horizon. Of the Canadian fleet, 23 are classified as Cardium class rigs, 19 as Montney class rigs and seven as Duvernay class rigs. As compared to the Cardium class rigs, the Montney class rigs have a larger hookload, while the Duvernay class rigs have the largest hookload allowing the rig to support more drill pipe downhole. Additionally, Western has eight drilling rigs operating through Stoneham in the US, including six Duvernay class rigs. Western is also the fifth largest well servicing company in Canada with a fleet of 63 rigs operating through Eagle. Additionally, Western Oilfield Services has three well servicing rigs operating in the Bakersfield area of California in the US. Western's oilfield rental equipment division, which operates through Aero, provides oilfield rental equipment for hydraulic fracturing services, well completions and production work, coil tubing and drilling services.
Crude oil and natural gas prices impact the cash flow of Western's customers, which in turn impacts the demand for Western's services. The following table summarizes average crude oil and natural gas prices, as well as average foreign exchange rates, for the three and nine months ended September 30, 2019 and 2018.
Three months ended September 30 |
Nine months ended September 30 |
||||||||
2019 |
2018 |
Change |
2019 |
2018 |
Change |
||||
Average crude oil and natural gas prices(1)(2) |
|||||||||
Crude Oil |
|||||||||
West Texas Intermediate (US$/bbl) |
56.47 |
69.46 |
(19%) |
57.04 |
66.74 |
(15%) |
|||
Western Canadian Select (CDN$/bbl) |
58.38 |
61.78 |
(6%) |
60.26 |
57.78 |
4% |
|||
Natural Gas |
|||||||||
30 day Spot AECO (CDN$/mcf) |
0.98 |
1.22 |
(20%) |
1.53 |
1.47 |
4% |
|||
Average foreign exchange rates(2) |
|||||||||
US dollar to Canadian dollar |
1.32 |
1.31 |
1% |
1.33 |
1.29 |
3% |
|||
(1) |
See "Abbreviations" included in this press release. |
(2) |
Source: Sproule September 30, 2019 Price Forecast, Historical Prices |
West Texas Intermediate ("WTI") on average declined for the three and nine months ended September 30, 2019 by 19% and 15% respectively, compared to the same periods in the prior year. However, pricing on Western Canadian Select ("WCS") crude oil was not impacted to the same extent, decreasing in the third quarter of 2019 by 6% and increasing by 4% for the nine months ended September 30, 2019, due to improved price differentials as a result of the mandated crude oil production curtailments implemented by the Government of Alberta, coupled with a weaker Canadian dollar. Natural gas prices in Canada were volatile and declined for the three months ended September 30, 2019, as the 30 day spot AECO price decreased by 20% over the same period in the prior year; however, for the nine months ended September 30, 2019, the 30 day spot AECO price improved by 4%, compared to the same period of the prior year.
In the United States, industry activity has decreased in 2019, particularly in the third quarter. As reported by Baker Hughes, a GE Company1, the average number of active drilling rigs in the United States decreased by 12% and 3% in the three and nine months ended September 30, 2019 respectively, compared to the same periods in the prior year. Likewise, in Canada, market conditions have deteriorated despite improved year to date prices for Canadian crude oil and natural gas. The mandated crude oil production curtailments implemented by the Government of Alberta and continued industry concerns over market access, increased regulation, and the prevailing customer preference to return cash to shareholders, or pay down debt, rather than grow production have resulted in a decrease in industry activity in Canada. The CAODC2 reported that for drilling in Canada, the total number of Operating Days in the WCSB decreased by approximately 32% and 31% respectively, for the three and nine months ended September 30, 2019, as compared to the same periods in the prior year.
Outlook
Currently, 16 of Western's drilling rigs are operating. Five of Western's 57 drilling rigs (or 9%) are under term take or pay contracts, with two expected to expire in 2019, two expected to expire in 2020 and one expected to expire in 2021. These contracts each typically generate between 250 and 350 Billable Days per year.
Due to decreased activity levels, Western's capital budget for 2019 has decreased by $6 million to $9 million from $15 million previously. Expansion capital is expected to total $3 million, up from $2 million previously, while maintenance capital is expected to total $6 million, down from $13 million previously. Western believes the 2019 capital budget provides a prudent use of cash resources and will allow it to maintain its premier drilling and well servicing rig fleets, while remaining responsive to customer requirements. Western will continue to manage its operations in a disciplined manner and make required adjustments to its capital program as customer demand changes.
Mandated crude oil production cuts in Alberta and uncertainty surrounding takeaway capacity related to the timing of construction on the Trans Mountain pipeline expansion and the Keystone XL pipeline, as well as the in service date of the Enbridge Line 3 pipeline replacement, have resulted in 2019 capital budgets for Western's Canadian customers decreasing significantly year over year. As such, year over year activity levels in Canada are expected to continue to be lower in 2019. Controlling fixed costs and maintaining balance sheet flexibility are priorities for the Company, as prices and demand for Western's services remain below historical levels. Going forward, Western's variable cost structure and a prudent capital budget will aid in preserving balance sheet strength.
Given the outlook for oilfield services in Canada, Western is proactively looking to deploy existing assets from Canada into more active resource plays in the United States. In the first quarter of 2019, Western transferred a Duvernay class drilling rig from Canada to the Permian Basin in the United States, increasing the United States drilling rig fleet to eight rigs. Additionally, in 2019, the Company began establishing well servicing operations in the United States and relocated three well service rigs from Canada to the Bakersfield area of California. Bakersfield is located in a mature basin where the demand for well interventions is high. Western's three well service rigs deployed in this area fit the profile of wells being serviced and feature engines that are compliant with the California Air Resources Board on-highway emissions standards.
As at September 30, 2019, Western had $15.8 million drawn on its $60.0 million credit facilities, consisting of its $50.0 million syndicated first lien credit facility (the "Revolving Facility") and its $10.0 million committed operating facility (the "Operating Facility" and together the "Credit Facilities"), which mature on December 17, 2021. Western currently has $211.8 million outstanding on its Second Lien Facility, which matures on January 31, 2023.
Oilfield service activity in Canada will be affected by the development of resource plays in Alberta and northeast British Columbia which will be impacted by pipeline construction, environmental regulations, and the level of investment in Canada. Currently, the largest challenges facing the oilfield service industry are limited take away capacity, continued customer spending constraints relative to historical levels, and the challenge of staffing field crews. Western's rig fleet is well positioned to benefit from the recently approved liquefied natural gas project in British Columbia. It is also Western's view that its modern drilling and well servicing rig fleets, reputation, and disciplined cash management provide a competitive advantage which will enable the Company to manage through the current oilfield service environment.
Non-IFRS Measures
Western uses certain measures in this press release which do not have any standardized meaning as prescribed by International Financial Reporting Standards ("IFRS"). These measures, which are derived from information reported in the condensed consolidated financial statements, may not be comparable to similar measures presented by other reporting issuers. These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding the Company. The Non-IFRS measure used in this press release is identified and defined as follows:
Adjusted EBITDA
Earnings before interest and finance costs, taxes, depreciation and amortization, other non-cash items and one-time gains and losses ("Adjusted EBITDA") is a useful supplemental measure as it is used by management and other stakeholders, including current and potential investors, to analyze the Company's principal business activities. Adjusted EBITDA provides an indication of the results generated by the Company's principal operating segments, which assists management in monitoring current and forecasting future operations, as certain non-core items such as interest and finance costs, taxes, depreciation and amortization, and other non-cash items and one-time gains and losses are removed. The closest IFRS measure would be net loss for consolidated results.
The following table provides a reconciliation of net loss, as disclosed in the condensed consolidated statements of operations and comprehensive income, to Adjusted EBITDA:
Three months ended September 30 |
Nine months ended September 30 |
|||||
(stated in thousands) |
2019 |
2018 |
2019 |
2018 |
||
Net loss |
(11,575) |
(10,108) |
(28,781) |
(31,530) |
||
Income tax recovery |
(3,657) |
(3,598) |
(14,986) |
(9,993) |
||
Loss before income taxes |
(15,232) |
(13,706) |
(43,767) |
(41,523) |
||
Add (deduct): |
||||||
Depreciation |
15,471 |
16,501 |
48,319 |
49,750 |
||
Stock based compensation |
145 |
223 |
459 |
1,024 |
||
Finance costs |
4,676 |
4,574 |
14,052 |
14,447 |
||
Other items |
(92) |
99 |
(409) |
2 |
||
Adjusted EBITDA |
4,968 |
7,691 |
18,654 |
23,700 |
||
Defined Terms:
Average active rig count (contract drilling): Calculated as drilling rig utilization – Billable Days multiplied by the average number of drilling rigs in the Company's fleet for the period.
Average active rig count (production services): Calculated as service rig utilization multiplied by the average number of service rigs in the Company's fleet for the period.
Billable Days: Defined as Operating Days plus rig mobilization days.
Drilling rig utilization – Operating Days (or "Drilling Rig Utilization"): Calculated based on Operating Days divided by total available days.
Drilling rig utilization – Billable Days: Calculated based on Billable Days divided by total available days.
Operating Days: Defined as contract drilling days, calculated on a spud to rig release basis.
Service Hours: Defined as well servicing hours completed.
Service rig utilization: Calculated based on Service Hours divided by available hours, being 10 hours per day, per well servicing rig, 365 days per year.
Contract Drilling Rig Classifications:
Cardium class rig: Defined as any contract drilling rig which has a total hookload less than or equal to 399,999 lbs (or 177,999 daN).
Montney class rig: Defined as any contract drilling rig which has a total hookload between 400,000 lbs (or 178,000 daN) and 499,999 lbs (or 221,999 daN).
Duvernay class rig: Defined as any contract drilling rig which has a total hookload equal to or greater than 500,000 lbs (or 222,000 daN).
Abbreviations:
- Barrel ("bbl");
- Basis point ("bps"): A 1% change equals 100 basis points and a 0.01% change is equal to one basis point;
- Canadian Association of Oilwell Drilling Contractors ("CAODC");
- DecaNewton ("daN");
- International Financial Reporting Standards ("IFRS");
- Pounds ("lbs");
- Thousand cubic feet ("mcf");
- Western Canadian Sedimentary Basin ("WCSB");
- Western Canadian Select ("WCS"); and
- West Texas Intermediate ("WTI").
Forward-Looking Statements and Information
This press release contains certain statements or disclosures relating to Western that are based on the expectations of Western as well as assumptions made by and information currently available to Western which may constitute forward-looking information under applicable securities laws. All information and statements contained herein that are not clearly historical in nature constitute forward-looking information, and words and phrases such as "may", "will", "should", "could", "expect", "intend", "anticipate", "believe", "estimate", "plan", "potential", "continue", "looking to", or the negative of these terms or other comparable terminology are generally intended to identify forward-looking information. Such information represents the Company's internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of additions to property and equipment, anticipated future debt levels and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information.
In particular, forward-looking information in this press release includes, but is not limited to, statements relating to commodity pricing; the future demand for and utilization of the Company's services and equipment; the pricing for the Company's services and equipment; the terms of existing and future drilling contracts in Canada and the US and the revenue resulting therefrom (including the number of Billable Days typically generated from such contracts and expected expiration dates of such contracts); the Company's expansion and maintenance capital plans for 2019 and its ability to make changes thereto in response to customer demands; the Company's liquidity needs including the ability of current capital resources to cover Western's financial obligations, working capital requirements and the 2019 capital budget; expectations as to the increase in crude oil transportation capacity through pipeline development; expectations as to the benefits of the liquefied natural gas expansion in British Columbia on the Company and its rig fleet; the future deployment or retirement of rigs and other existing assets; the potential impact of changes to laws, governmental and environmental regulations; the expectation of continued investment in the Canadian crude oil and natural gas industry; the development of Alberta and British Columbia resource plays; expectations relating to producer spending and activity levels for oilfield services; the Company's approach to management of its budget and operations; the Company's ability to maintain a competitive advantage to enable it to manage the current oilfield service environment; and the Company's ability to find and maintain enough field crew members.
The material assumptions in making the forward-looking statements in this press release include, but are not limited to, assumptions relating to: demand levels and pricing for oilfield services; demand for crude oil and natural gas and the price and volatility of crude oil and natural gas; pressures on commodity pricing; the continued business relationships between the Company and its significant customers; the Company's competitive advantage; crude oil transport and pipeline approval and development; the Company's ability to finance its operations; the effectiveness of the Company's cost structure and capital budget; the effects of seasonal and weather conditions on operations and facilities; the competitive environment to which the various business segments are, or may be, exposed in all aspects of their business and the Company's competitive position therein; the ability of the Company's various business segments to access equipment (including spare parts and new technologies); changes in laws or regulations; currency exchange fluctuations; the ability of the Company to attract and retain skilled labour and qualified management; the ability to retain and attract significant customers; the ability to maintain a satisfactory safety record; and general business, economic and market conditions.
Although Western believes that the expectations and assumptions on which such forward-looking statements and information are based on are reasonable, undue reliance should not be placed on the forward-looking statements and information as Western cannot give any assurance that they will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risk that recent improvements in commodity pricing may not continue, and other general industry, economic, market and business conditions. Readers are cautioned that the foregoing list of risks, uncertainties and assumptions are not exhaustive. Additional information on these and other risk factors that could affect Western's operations and financial results are discussed under the heading "Risk Factors" in Western's annual information form for the year ended December 31, 2018 which may be accessed through the SEDAR website at www.sedar.com. The forward-looking statements and information contained in this press release are made as of the date hereof and Western does not undertake any obligation to update publicly or revise any forward-looking statements and information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
1 |
Source: Baker Hughes, a GE Company, 2019 Rig Count monthly press releases. |
2 |
Source: CAODC, monthly Contractor Summary. |
SOURCE Western Energy Services Corp.
please contact: Alex R.N. MacAusland, President and CEO, or Jeffrey K. Bowers, Senior VP Finance and CFO at 403.984.5916
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