Western Energy Services Corp. releases first quarter 2018 financial and operating results
CALGARY, April 25, 2018 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its first quarter 2018 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 months ended March 31, 2018 and 2017 will be available on SEDAR at www.sedar.com. Non-International Financial Reporting Standards ("Non-IFRS") measures and abbreviations for standard industry terms are included in this press release. All amounts are denominated in Canadian dollars (CDN$) unless otherwise identified.
First Quarter 2018 Operating Results:
- While first quarter Operating Revenue decreased by $5.2 million (or 7%) to $73.0 million in 2018 as compared to $78.2 million in 2017, after normalizing for $6.4 million of shortfall commitment revenue recognized in the first quarter of 2017, Operating Revenue in the first quarter of 2018 improved by $1.2 million (or 2%). In the contract drilling segment, Operating Revenue totalled $57.4 million in the first quarter of 2018, which after normalizing for $6.4 million of shortfall commitment revenue recognized in the prior period, resulted in Operating Revenue improving by $4.6 million (or 9%). In the production services segment, Operating Revenue totalled $15.7 million for the three months ended March 31, 2018, as compared to $19.0 million in the same period of the prior year, a decrease of $3.3 million (or 17%). While activity was lower in the contract drilling and production services segments in Canada, improved pricing in Canada and higher utilization in the United States impacted Operating Revenue as described below:
- Drilling rig utilization – Operating Days ("Drilling Rig Utilization") in Canada averaged 52% in the first quarter of 2018 compared to an average of 54% in the first quarter of 2017, reflecting a 200 basis points ("bps") decrease. The decrease is attributable to activity slowing in the latter part of the quarter as some of Western's customers ended their winter drilling programs early, due to economic factors. First quarter 2018 Drilling Rig Utilization of 52% represented a premium of 1,100 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 41%, whereas in the first quarter of 2017, Drilling Rig Utilization of 54% represented a 1,400 bps premium to the industry average. The decrease in the Company's utilization premium to the industry average in the first quarter of 2018 is a function of a smaller industry rig fleet, as rigs continue to be decommissioned or moved 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, remained constant at 10.3% in the first quarter of 2018, as compared to 10.7% in the first quarter of 2017. While utilization decreased during the quarter, pricing continued to increase and resulted in an 11% improvement in Operating Revenue per Billable Day in the first quarter of 2018, as compared to the same period in the prior year, as the Company steadily raised rates and diversified its customer base as the energy industry continues to recover from a multi-year downturn. Similarly, when comparing to the fourth quarter of 2017, Operating Revenue per Billable Day in the first quarter of 2018 improved by 1%;
- In the United States, four of the Company's six drilling rigs operated during the quarter, two of which were working on long term contracts, resulting in Drilling Rig Utilization of 51% in the first quarter of 2018, as compared to 39% in the same period of the prior year. While day rates have generally improved, Operating Revenue per Billable Day in the United States was consistent in the first quarter of 2018, as compared to the first quarter of 2017, mainly due to changes in the average rig mix, as rigs running on lower day rates worked more during the first quarter of 2018. Compared to the fourth quarter of 2017, Operating Revenue per Billable Day improved by 10% due to changes in rig mix and contract rate increases that took effect in the first quarter of 2018; and
- Well servicing utilization was 31% in the first quarter of 2018 compared to 38% in the same period of the prior year, due to customers deferring work amid widening crude oil differentials. Hourly rates improved during the first quarter of 2018, increasing by 2% as compared to the same period in the prior year, due to changes in the average rig mix. Lower utilization, partially offset by improved pricing, led to a $2.5 million (or 16%) decrease in well servicing Operating Revenue in the period.
- First quarter Adjusted EBITDA decreased by $3.5 million (or 19%) to $15.1 million in 2018 as compared to $18.6 million in the first quarter of 2017. However, after normalizing for the $6.4 million in shortfall commitment revenue recognized in the first quarter of 2017, Adjusted EBITDA improved by $2.9 million (or 24%), as compared to the same period in the prior year. The year over year change in Adjusted EBITDA is due to improved pricing in Canada and higher activity in the United States, which was offset by decreased well servicing activity and lower shortfall commitment revenue.
- Administrative expenses, excluding depreciation and stock based compensation, decreased by $0.6 million (or 10%) to $5.2 million, as compared to $5.8 million in the first quarter of 2017, mainly due to lower employee related costs.
- The Company incurred a net loss of $5.9 million in the first quarter of 2018 ($0.06 per basic common share) as compared to a net loss of $4.4 million in the same period in 2017 ($0.06 per basic common share). The change can be attributed to the following:
- A $3.5 million decrease in Adjusted EBITDA, mainly due to lower shortfall commitment revenue and decreased well servicing activity, partially offset by improved pricing in Canada and higher activity in the United States; offset by:
- A $1.8 million positive change in other items, of which $1.6 million related to prior period transaction costs on the unsuccessful acquisition of Savanna Energy Services Corp. ("Savanna") in 2017, coupled with gains and losses on foreign exchange and asset sales; and
- A $0.3 million decrease in stock based compensation expense as fewer unvested stock options and equity settled restricted share units were outstanding in the quarter.
- First quarter 2018 capital expenditures of $4.7 million included $1.8 million of expansion capital and $2.9 million of maintenance capital. In total, capital spending in the first quarter of 2018 increased by $2.3 million from the $2.4 million incurred in the first quarter of 2017. The Company incurred expansion capital mainly related to drilling rig upgrades in the first quarter of 2018, as well as necessary maintenance capital.
- On January 31, 2018, the Company completed the one time draw of $215.0 million on its 7.25% second lien secured term loan facility (the "Second Lien Facility"). The proceeds from the Second Lien Facility draw, along with cash on hand and funds available under the $70.0 million syndicated revolving credit facility (the "Revolving Facility") and the $10.0 million committed operating facility (the "Operating Facility" and together the "Credit Facilities") were used to redeem the $265.0 million 7⅞% senior unsecured notes (the "Senior Notes") at their par value of $265.0 million on February 1, 2018.
| Selected Financial Information |
||||
| (stated in thousands, except share and per share amounts) |
||||
| Three months ended March 31 |
||||
| Financial Highlights |
2018 |
2017 |
Change |
|
| Revenue |
81,257 |
84,222 |
(4%) |
|
| Operating Revenue(1) |
72,965 |
78,153 |
(7%) |
|
| Gross Margin(1) |
20,271 |
24,458 |
(17%) |
|
| Gross Margin as a percentage of Operating Revenue |
28% |
31% |
(10%) |
|
| Adjusted EBITDA(1) |
15,112 |
18,625 |
(19%) |
|
| Adjusted EBITDA as a percentage of Operating Revenue |
21% |
24% |
(13%) |
|
| Cash flow from operating activities |
3,864 |
3,173 |
22% |
|
| Capital expenditures |
4,656 |
2,436 |
91% |
|
| Net loss |
(5,947) |
(4,365) |
36% |
|
| -basic net loss per share |
(0.06) |
(0.06) |
- |
|
| -diluted net loss per share |
(0.06) |
(0.06) |
- |
|
| Weighted average number of shares |
||||
| -basic |
92,177,048 |
73,795,944 |
25% |
|
| -diluted |
92,177,048 |
73,795,944 |
25% |
|
| Outstanding common shares as at period end |
92,177,098 |
73,795,944 |
25% |
|
| (1) See "Non-IFRS measures" included in this press release. |
||||
| Three months ended March 31 |
||||
| Operating Highlights(1) |
2018 |
2017 |
Change |
|
| Contract Drilling |
||||
| Canadian Operations: |
||||
| Contract drilling rig fleet: |
||||
| -Average active rig count |
29.1 |
30.5 |
(5%) |
|
| -End of period |
50 |
51 |
(2%) |
|
| Operating Revenue per Billable Day |
19,004 |
17,198(3) |
11% |
|
| Operating Revenue per Operating Day |
21,171 |
18,986(3) |
12% |
|
| Operating Days |
2,351 |
2,487 |
(5%) |
|
| Drilling rig utilization - Billable Days |
58% |
60% |
(3%) |
|
| Drilling rig utilization - Operating Days |
52% |
54% |
(4%) |
|
| CAODC industry average utilization(2) |
41% |
40% |
3% |
|
| United States Operations: |
||||
| Contract drilling rig fleet: |
||||
| -Average active rig count |
3.3 |
2.3 |
43% |
|
| -End of period |
6 |
5 |
20% |
|
| Operating Revenue per Billable Day (US$) |
19,928 |
19,964 |
- |
|
| Operating Revenue per Operating Day (US$) |
21,838 |
23,972 |
(9%) |
|
| Operating Days |
274 |
176 |
56% |
|
| Drilling rig utilization - Billable Days |
56% |
47% |
19% |
|
| Drilling rig utilization - Operating Days |
51% |
39% |
31% |
|
| Production Services |
||||
| Well servicing rig fleet: |
||||
| -Average active rig count |
20.6 |
25.0 |
(18%) |
|
| -End of period |
66 |
66 |
- |
|
| Service rig Operating Revenue per Service Hour |
703 |
688 |
2% |
|
| Service Hours |
18,476 |
22,457 |
(18%) |
|
| Service rig utilization |
31% |
38% |
(18%) |
|
| (1) |
See "Non-IFRS measures" included in this press release. |
| (2) |
Source: The Canadian Association of Oilwell Drilling Contractors ("CAODC"). 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 $6.4 million for the three months ended March 31, 2017. |
| Financial Position at (stated in thousands) |
March 31, 2018 |
December 31, 2017 |
March 31, 2017 |
| Working capital |
33,761 |
62,866 |
60,441 |
| Property and equipment |
643,253 |
652,828 |
693,036 |
| Total assets |
706,895 |
760,504 |
785,040 |
| Long term debt |
227,401 |
265,219 |
264,150 |
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. Financial and operating results for Horizon and Stoneham are included in Western's contract drilling segment, while financial and operating results for Eagle and Aero are included in Western's production services segment.
Western has a drilling rig fleet of 56 rigs specifically suited for drilling horizontal wells of increased complexity. Western is currently the fifth largest drilling contractor in Canada, based on the CAODC registered rigs, with a fleet of 50 rigs operating through Horizon. Of the Canadian fleet, 23 are classified as Cardium class rigs, 19 as Montney class rigs and eight 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 six drilling rigs operating through Stoneham, including five Duvernay class triple drilling rigs. Western is also the fifth largest well servicing company in Canada with a fleet of 66 rigs operating through Eagle. 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 months ended March 31, 2018 and 2017.
| Three months ended March 31 |
|||
| 2018 |
2017 |
Change |
|
| Average crude oil and natural gas prices(1)(2) |
|||
| Crude Oil |
|||
| West Texas Intermediate (US$/bbl) |
62.89 |
51.70 |
22% |
| Western Canadian Select (CDN$/bbl) |
46.90 |
50.42 |
(7%) |
| Natural Gas |
|||
| 30 day Spot AECO (CDN$/mcf) |
1.95 |
2.69 |
(28%) |
| Average foreign exchange rates(2) |
|||
| US dollar to Canadian dollar |
1.26 |
1.32 |
(5%) |
| (1) |
See "Abbreviations" included in this press release. |
|||||||||||||
| (2) |
Source: Bloomberg |
|||||||||||||
West Texas Intermediate ("WTI") on average improved in the first quarter of 2018 as compared to the fourth quarter of 2017, increasing by 14%, and was 22% higher compared to the same period in the prior year. For Western's Canadian customers, the impact of the weaker US dollar when translating WTI into Canadian dollars, resulted in only a 16% increase for the three months ended March 31, 2018, as compared to the same period in the prior year. Canadian heavy crude pricing declined in the first quarter of 2018, as Western Canadian Select ("WCS") on average decreased by 4% as compared to the fourth quarter of 2017, and by 7% as compared to the same period of the prior year, as a result of limited take away capacity. Natural gas prices also declined in the first quarter of 2018, as the 30 day spot AECO price decreased by 28% over the same period of the prior year, while improving by 17% as compared to the fourth quarter of 2017. However, the prices for condensate and natural gas liquids ("NGL") in Canada improved in the first quarter of 2018, as compared to the same period in the prior year.
Improved market conditions in 2018 has led to a corresponding increase in the demand for oilfield services in the United States. As reported by Baker Hughes, a GE Company, the average number of active drilling rigs in the United States increased approximately 31% for the three months ended March 31, 2018 as compared to the same period of the prior year. However in Canada, lower natural gas prices and wider differentials on heavy crude oil resulted in a decrease in industry activity. The CAODC reported that for drilling in Canada, the total number of Operating Days in the WCSB decreased by approximately 2% in the first quarter of 2018, as compared to the first quarter of 2017.
Outlook
Currently, nine of Western's drilling rigs are operating. Five of Western's 56 drilling rigs (or 9%) are under long term take or pay contracts, with one expected to expire in 2018, two expected to expire in 2019 and two expected to expire in 2020. These contracts each typically generate between 250 and 350 Billable Days per year.
Western's capital budget for 2018 remains unchanged and is expected to total $20 million with $8 million allocated for expansion capital and $12 million for maintenance capital. Western believes the 2018 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.
Weak natural gas prices are expected to persist in 2018. While Canadian crude oil prices have improved of late, capital budgets for Western's Canadian customers have not yet adjusted to the current pricing environment. As such, year over year activity levels for the remainder of 2018 are expected to remain relatively consistent with 2017. If commodity prices remain at current levels, activity in the second half of 2018 has the potential to improve year over year. Improving gross margin continues to be a priority for the Company and, as has been demonstrated over the last four quarters, Western is working to implement higher rates with each rig that is awarded work. Prices for Western's services remain below historical levels and will continue to impact Adjusted EBITDA and cash flow from operating activities in the near term. However, Western's variable cost structure and a prudent capital budget will aid in preserving balance sheet strength. As at March 31, 2018, Western had $64.1 million of available credit under its Credit Facilities, which mature on December 17, 2020 and $215.0 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 including the implementation of a price on carbon emissions in Alberta, 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, as a result of low natural gas prices and differentials on Canadian crude oil, and the increasing challenge of staffing field crews, particularly in the well servicing division. Western's rig fleet is well positioned to benefit from potential liquefied natural gas expansion 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.
2018 First Quarter Financial and Operating Results Conference Call and Webcast
Western has scheduled a conference call and webcast to begin promptly at 10:00 a.m. MT (12:00 p.m. ET) on Thursday, April 26, 2018.
The conference call dial-in number is 1-888-231-8191.
A live webcast of the conference call will be accessible on Western's website at www.wesc.ca by selecting "Investors", then "Webcasts". Shortly after the live webcast, an archived version will be available for approximately 14 days.
An archived recording of the conference call will also be available approximately two hours after the completion of the call until May 10, 2018 by dialing 1-855-859-2056, passcode 6586437.
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. These Non-IFRS measures are identified and defined as follows:
Operating Revenue
Management believes that in addition to revenue, Operating Revenue is a useful supplemental measure as it provides an indication of the revenue generated by Western's principal operating activities, excluding flow through third party charges such as rig fuel, which at the customer's request may be paid for initially by Western, then recharged in its entirety to Western's customers.
Gross Margin
Management believes that in addition to net income, Gross Margin is a useful supplemental measure as it provides an indication of the results generated by Western's principal operating activities prior to considering administrative expenses, depreciation and amortization, stock based compensation, how those activities are financed, the impact of foreign exchange, how the results are taxed, how funds are invested, and how non-cash items and one-time gains and losses affect results.
The following table provides a reconciliation of revenue under IFRS, as disclosed in the condensed consolidated statements of operations and comprehensive income, to Operating Revenue and Gross Margin:
| Three months ended March 31 |
|||
| (stated in thousands) |
2018 |
2017 |
|
| Operating Revenue |
|||
| Drilling |
57,350 |
59,236 |
|
| Production services |
15,735 |
19,013 |
|
| Less: inter-company eliminations |
(120) |
(96) |
|
| 72,965 |
78,153 |
||
| Third party charges |
8,292 |
6,069 |
|
| Revenue |
81,257 |
84,222 |
|
| Less: operating expenses |
(77,485) |
(76,242) |
|
| Add: |
|||
| Depreciation – operating |
16,391 |
16,381 |
|
| Stock based compensation – operating |
108 |
97 |
|
| Gross Margin |
20,271 |
24,458 |
|
Adjusted EBITDA
Management believes that in addition to net income, 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 provides an indication of the results generated by the Company's principal operating segments similar to Gross Margin but also factors in the cash administrative expenses incurred in the period.
Operating Earnings
Management believes that in addition to net income, Operating Earnings is a useful supplemental measure as it provides an indication of the results generated by the Company's principal operating segments similar to Adjusted EBITDA but also factors in the depreciation expense incurred in the period.
The following table provides a reconciliation of net loss under IFRS, as disclosed in the condensed consolidated statements of operations and comprehensive income, to earnings before interest and finance costs, taxes, depreciation and amortization ("EBITDA"), Adjusted EBITDA and Operating Earnings (Loss):
| Three months ended March 31 |
||||
| (stated in thousands) |
2018 |
2017 |
||
| Net loss |
(5,947) |
(4,365) |
||
| Add: |
||||
| Finance costs |
5,380 |
5,412 |
||
| Income tax recovery |
(1,242) |
(1,488) |
||
| Depreciation – operating |
16,391 |
16,381 |
||
| Depreciation – administrative |
259 |
322 |
||
| EBITDA |
14,841 |
16,262 |
||
| Add: |
||||
| Stock based compensation – operating |
108 |
97 |
||
| Stock based compensation – administrative |
250 |
569 |
||
| Other items |
(87) |
1,697 |
||
| Adjusted EBITDA |
15,112 |
18,625 |
||
| Subtract: |
||||
| Depreciation – operating |
(16,391) |
(16,381) |
||
| Depreciation – administrative |
(259) |
(322) |
||
| Operating Earnings (Loss) |
(1,538) |
1,922 |
||
Net Debt
The following table provides a reconciliation of long term debt under IFRS, as disclosed in the condensed consolidated balance sheets to Net Debt:
| (stated in thousands) |
March 31, 2018 |
December 31, 2017 |
| Long term debt |
227,401 |
265,219 |
| Current portion of long term debt |
398 |
475 |
| Less: cash and cash equivalents |
(2,209) |
(48,825) |
| Net Debt |
225,590 |
216,869 |
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");
- Natural Gas Liquids ("NGL");
- 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 the words "may", "will", "should", "could", "expect", "intend", "anticipate", "believe", "estimate", "propose", "plan", "predict", "potential", "continue", or the negative of these terms or other comparable terminology are generally intended to identify forward-looking information. Such information represents the Corporation's internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital expenditures, 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 Operating Days typically generated from the Company's contracts); the Company's expansion and maintenance capital plans for 2018; the Company's liquidity needs including the ability of current capital resources to cover Western's financial obligations and the 2018 capital budget; the use and availability of the Company's Credit Facilities; pricing for Western's services and impact on Adjusted EBITDA; the Company's ability to maintain certain covenants under its Credit Facilities; the future declaration of dividends; expectations as to the increase in crude oil transportation capacity through pipeline development; the potential impact of changes to environmental laws and regulations and the implementation of a price on carbon emissions in Alberta; the expectation of continued investment in the Canadian crude oil and natural gas industry; expectations relating to producer spending, 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; crude oil transport and pipeline approval and development; the Company's ability to finance its operations; 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; 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 commodity prices will remain low, 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 included in Western's annual information form 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.
SOURCE Western Energy Services Corp.
Alex R.N. MacAusland, President and CEO, or Jeffrey K. Bowers, Senior VP Finance and CFO at 403.984.5916
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