Western Energy Services Corp. Releases Fourth Quarter and Year End 2019 Financial and Operating Results

CALGARY, Feb. 27, 2020 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its fourth quarter and year end 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 years ended December 31, 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.

Fourth Quarter 2019 Operating Results:

• Fourth quarter revenue decreased by $17.3 million to $45.8 million in 2019 as compared to $63.1 million in 2018. In the contract drilling segment, revenue totalled $30.9 million in the fourth quarter of 2019, a decrease of $18.3 million (or 37%) as compared to $49.2 million in the fourth quarter of 2018. In the production services segment, revenue totalled $15.0 million for the three months ended December 31, 2019, as compared to $14.0 million for the three months ended December 31, 2018, an increase of $1.0 million (or 7%). While contract drilling day rates were higher in the United States and activity was higher 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 21% in the fourth quarter of 2019 compared to an average of 32% in the same period of the prior year, reflecting a 1,100 basis points ("bps") reduction. The decrease in activity was mainly attributable to mandated crude oil production curtailments in Alberta due to pipeline constraints, coupled with continued market uncertainty and as a result, customers reduced or cancelled their 2019 drilling programs. Fourth quarter 2019 Drilling Rig Utilization of 21% represented a discount of 200 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 23%¹, a decrease as compared to the fourth quarter of 2018 when Drilling Rig Utilization of 32% was 400 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 8.2% in the fourth quarter of 2019, as compared to 9.6% in the fourth quarter of 2018. Revenue per Billable Day decreased by 2% in the fourth quarter of 2019, as compared to the same period in the prior year, due to changes in the average rig mix and lower third party revenue as less fuel was purchased on behalf of the Company's customers;
• In the United States, six of the Company's eight drilling rigs worked during the quarter, two of which were operating on term contracts. Drilling Rig Utilization was 30% in the fourth quarter of 2019, compared to 71% in the fourth quarter of 2018, reflecting a 44% decrease in Operating Days. Revenue per Billable Day for the fourth quarter of 2019 improved by 12%, mainly due to a higher proportion of Operating Days related to the Company's high specification Duvernay class rigs in the Williston Basin in North Dakota, compared to the rigs working in the Permian Basin in Texas which worked at lower average day rates, while operating at a significantly lower cost; and
• In Canada, service rig utilization was 32% in the fourth quarter of 2019 compared to 28% 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 continued market uncertainty and mandated crude oil production curtailments in Alberta. Revenue per Service Hour increased during the fourth quarter of 2019 by 2%, as compared to the same period in the prior year, due to changes in the average rig mix. Higher utilization and pricing, led to well servicing revenue in the period increasing to $12.6 million, an improvement of $1.0 million (or 9%), as compared to the same period in the prior year.
• Administrative expenses decreased by $0.6 million (or 12%) to $4.2 million in the fourth quarter of 2019, as compared to $4.8 million in the fourth quarter of 2018, mainly due to lower rent expense as a result of the adoption of IFRS 16.
• The Company incurred a net loss of $52.2 million in the fourth quarter of 2019 ($0.56 per basic common share) as compared to a net loss of $9.5 million in the same period in 2018 ($0.10 per basic common share). The change can mainly be attributed to a property and equipment impairment loss of $54.0 million and a $2.3 million decrease in Adjusted EBITDA, offset partially by $12.2 million increase in income tax recovery and a $1.6 million decrease in depreciation expense due to certain assets being fully depreciated in the period.
• Fourth quarter Adjusted EBITDA decreased by $2.3 million (or 29%) to $5.6 million in 2019 as compared to $7.9 million in the fourth quarter of 2018. The year over year change in Adjusted EBITDA is due to lower contract drilling in Canada and the United States, lower oilfield rental equipment activity in Canada, $1.0 million of restructuring costs related to severance as the Company continues to monitor and align its costs with lower activity levels, offset partially by increased pricing in the United States and higher well servicing activity in Canada.
• As a result of continued market uncertainty and the related outlook for current and future oilfield services activity and pricing, the Company completed an impairment test for each of its cash generating units ("CGU") as at December 31, 2019. Based on the results of these tests, it was determined that property and equipment in the Company's contract drilling and oilfield rentals CGUs was impaired by $49.0 million and $5.0 million respectively.
• Fourth quarter 2019 additions to property and equipment of $2.9 million included $1.2 million related to expansion capital and $1.7 million of maintenance capital. In total, additions to property and equipment in the fourth quarter of 2019 decreased by $3.2 million (or 52%) from the $6.1 million incurred in the fourth quarter of 2018.
• Subsequent to December 31, 2019, on January 6, 2020, the Company announced a normal course issuer bid (the "Bid"), which has been filed with and accepted by the Toronto Stock Exchange. Pursuant to the Bid, Western may purchase for cancellation up to 5,200,000 common shares of the Company. The Bid commenced on January 14, 2020 and will terminate the earlier of: (i) January 13, 2021; and (ii) the date on which the maximum number of common shares are purchased pursuant to the Bid. 1,571,000 common shares for a total cost of approximately $0.5 million have been repurchased since the commencement of the Bid.

2019 Operating Results:

• Revenue in 2019 decreased by $40.0 million (or 17%) to $196.4 million as compared to $236.4 million in 2018. In the contract drilling segment, revenue totalled $140.8 million in 2019, including US$1.3 million of shortfall commitment revenue, and reflects a decrease of $43.1 million (or 23%) as compared to $183.9 million in 2018. In the production services segment, revenue totalled $55.9 million in 2019, as compared to $52.7 million in 2018, an increase of $3.2 million (or 6%). Activity was higher for well servicing in Canada; whereas lower contract drilling and oilfield rental equipment activity in Canada and lower activity in the United States impacted revenue as described below:
• Drilling Rig Utilization in Canada for the year ended December 31, 2019 decreased to 22%, compared to an average of 35% for the prior year, reflecting a 1,300 bps reduction. The decrease in activity was mainly attributable to mandated crude oil production curtailments in Alberta due to pipeline constraints, coupled with heightened market uncertainty and as a result, customers reduced or cancelled their 2019 drilling programs. Drilling Rig Utilization of 22% in 2019 was consistent with the CAODC industry average of 22%², whereas in 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 8.9% in 2019, as compared to 9.8% in 2018. Despite lower activity, revenue per Billable Day in 2019 was consistent with 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 in 2019, three of which were operating on term contracts. Additionally, US$1.3 million in shortfall commitment revenue was recognized in 2019. 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 in 2019, Operating Days increased by 21%, as compared to 2018. However, Drilling Rig Utilization decreased to 47% for the year ended December 31, 2019, compared to 51% in the prior year due to activity slowing in the United States. 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 year ended December 31, 2019 decreased by 3% as the rigs working in the Permian Basin in Texas worked at lower average day rates, while operating at a significantly lower cost and worked a higher proportion of Operating Days in 2019 than 2018; and
• In Canada, service rig utilization was 30% for the year ended December 31, 2019 compared to 25% in 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 in 2019 by 4%, compared to 2018 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 $46.2 million, an improvement of $4.8 million (or 12%), as compared to the prior year.
• Administrative expenses in 2019 decreased by $2.2 million (or 12%) to $16.7 million, as compared to $18.9 million in 2018, mainly due to lower rent expense as a result of the adoption of IFRS 16, coupled with lower employee related costs due to lower headcount, offset partially by severance costs described previously.
• The Company incurred a net loss of $81.0 million in 2019 ($0.88 per basic common share) as compared to a net loss of $41.1 million in 2018 ($0.45 per basic common share). The change can be attributed to:
• A $17.2 million increase in income tax recovery due to an increased loss before income taxes in the period due to the impairment of property and equipment and the decrease in the Alberta corporate tax rate substantively enacted in the second quarter of 2019;
• A $3.0 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 $0.3 million change in other items, which include gains and losses on foreign exchange and asset sales.
  Offsetting the above mentioned items were the $54.0 million impairment loss on property and equipment and the $7.4 million decrease in Adjusted EBITDA.

Offsetting the above mentioned items were the $54.0 million impairment loss on property and equipment and the $7.4 million decrease in Adjusted EBITDA.

• Adjusted EBITDA for the year ended December 31, 2019 decreased by $7.4 million (or 23%) to $24.2 million as compared to $31.6 million for the year ended December 31, 2018. The year over year change is mainly due to lower Adjusted EBITDA in Canadian contract drilling, coupled with $1.9 million related to restructuring costs related to severance as the Company continues to monitor and adjust its costs based on lower activity levels, lower rent expense as a result of the adoption of IFRS 16, and $1.4 million in costs related to establishing well servicing operations for Western Oilfield Services in the United States, which was offset partially by shortfall commitment revenue.
• As a result of continued market uncertainty and the related outlook for current and future oilfield services activity and pricing, the Company completed an impairment test for each of its CGUs as at December 31, 2019. Based on the results of these tests, it was determined that property and equipment in the Company's contract drilling and oilfield rentals CGUs were impaired by $49.0 million and $5.0 million respectively.
• Year to date additions to property and equipment of $8.0 million included $2.6 million of expansion capital and $5.4 million of maintenance capital. In total, additions to property and equipment for 2019 decreased by $12.0 million (or 60%) from the $20.0 million incurred in 2018. 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 months and year ended December 31, 2019, the impact of IFRS 16 on Adjusted EBITDA was an increase of $0.8 million and $3.3 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
(stated in thousands, except share and per share amounts)
	Three months ended December 31			Year ended December 31
Financial Highlights	2019	2018	Change	2019	2018	Change
Revenue	45,838	63,133	(27%)	196,408	236,410	(17%)
Adjusted EBITDA^(1)	5,584	7,916	(29%)	24,238	31,616	(23%)
Adjusted EBITDA as a percentage of revenue	12%	13%	(8%)	12%	13%	(8%)
Cash flow from operating activities	8,921	5,022	78%	31,718	33,231	(5%)
Additions to property and equipment	2,942	6,102	(52%)	7,968	19,960	(60%)
Net loss	(52,249)	(9,530)	448%	(81,030)	(41,060)	97%
– basic net loss per share	(0.56)	(0.10)	460%	(0.88)	(0.45)	96%
– diluted net loss per share	(0.56)	(0.10)	460%	(0.88)	(0.45)	96%
Weighted average number of shares
– basic	92,501,314	92,305,208	-	92,379,902	92,224,585	-
– diluted	92,501,314	92,305,208	-	92,379,902	92,224,585	-
Outstanding common shares as at period end	92,501,314	92,305,542	-	92,501,314	92,305,542	-
(1)  See "Non-IFRS measures" included in this press release.
	Three months ended December 31			Year ended December 31
Operating Highlights^(2)	2019	2018	Change	2019	2018	Change
Contract Drilling
Canadian Operations:
Contract drilling rig fleet:
– Average active rig count	11.4	18.1	(37%)	12.3	19.2	(36%)
– End of period	49	50	(2%)	49	50	(2%)
Revenue per Billable Day	22,023	22,474	(2%)	21,383	21,321	-
Revenue per Operating Day	24,725	25,166	(2%)	23,854	23,644	1%
Operating Days	932	1,487	(37%)	4,012	6,328	(37%)
Drilling rig utilization – Billable Days	23%	36%	(36%)	25%	38%	(34%)
Drilling rig utilization – Operating Days	21%	32%	(34%)	22%	35%	(37%)
CAODC industry average utilization – Operating Days^(3)	23%	28%	(18%)	22%	29%	(24%)
United States Operations:
Contract drilling rig fleet:
– Average active rig count	2.9	4.9	(41%)	4.4	3.4	29%
– End of period	8	7	14%	8	7	14%
Revenue per Billable Day (US$)	21,979	19,602	12%	20,460^(4)	21,109	(3%)
Revenue per Operating Day (US$)	26,596	22,011	21%	24,150^(4)	23,571	2%
Operating Days	224	403	(44%)	1,352	1,121	21%
Drilling rig utilization – Billable Days	37%	79%	(53%)	56%	57%	(2%)
Drilling rig utilization – Operating Days	30%	71%	(58%)	47%	51%	(8%)
Production Services
Canadian Operations:
Well servicing rig fleet:
– Average active rig count	20.1	18.8	7%	19.1	16.5	16%
– End of period	63	66	(5%)	63	66	(5%)
Revenue per Service Hour	680	669	2%	661	686	(4%)
Service Hours	18,494	17,247	7%	69,882	60,337	16%
Service rig utilization	32%	28%	14%	30%	25%	20%

(1)	See "Non-IFRS Measures" included in this press release.
(2)	See "Defined Terms" included in this press release.
(3)	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 drilling days.
(4)	Excludes shortfall commitment revenue from take or pay contracts of US$1.3 million for the year ended December 31, 2019.

Financial Position at (stated in thousands)	December 31, 2019	December 31, 2018	December 31, 2017
Working capital	7,031	15,739	62,866
Property and equipment	511,052	615,395	652,828
Total assets	550,537	667,295	760,504
Long term debt	228,274	222,258	265,219

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 rigs³, 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, based on the CAODC registered rigs⁴, 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 months ended December 31, 2019 and 2018 and for the years ended December 31, 2019 and 2018.

	Three months ended December 31			Year ended December 31
	2019	2018	Change	2019	2018	Change
Average crude oil and natural gas prices^(1)(2)
Crude Oil
West Texas Intermediate (US$/bbl)	56.96	58.82	(3%)	57.02	64.76	(12%)
Western Canadian Select (CDN$/bbl)	54.29	36.01	51%	58.77	52.34	12%
Natural Gas
30 day Spot AECO (CDN$/mcf)	2.42	1.58	53%	1.76	1.50	17%
Average foreign exchange rates^(2)
US dollar to Canadian dollar	1.32	1.32	-	1.33	1.30	2%

(1)	See "Abbreviations" included in this press release.
(2)	Source: Sproule December 31, 2019 Price Forecast, Historical Prices.

West Texas Intermediate ("WTI") on average declined for the three months and year ended December 31, 2019 respectively, compared to the same periods in the prior year. However, pricing on Western Canadian Select ("WCS") crude oil increased by 51% in the fourth quarter of 2019 and by 12% year over year respectively, compared to the same periods in the prior year, due to improved price differentials as a result of the mandated crude oil production curtailments implemented by the Government of Alberta. Natural gas prices in Canada increased for both the three months and year ended December 31, 2019, as the 30 day spot AECO price increased by 53% and 17% respectively, over the same periods of the prior year. The US dollar to the Canadian dollar foreign exchange rate remained constant quarter over quarter, though weakened for the year ended December 31, 2019 which had a slightly positive effect on the cash flows of Western's Canadian customers, when selling US dollar denominated commodities.

In the United States, industry activity has decreased in 2019, particularly in the fourth quarter. As reported by Baker Hughes Company⁵, the number of active drilling rigs in the United States decreased year over year by approximately 26%. 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 CAODC⁶ reported that for drilling in Canada, the total number of Operating Days in the WCSB decreased by approximately 30% in 2019 as compared to 2018, as a result of a 13% decrease in the industry rig count year over year.

Outlook

Currently, 15 of Western's drilling rigs are operating. Three of Western's 57 drilling rigs (or 5%) are under term take or pay contracts, with 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 2020 is expected to total approximately $8 million, with $1 million allocated for expansion capital and $7 million for maintenance capital. Western believes the 2020 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 2020 capital budgets for Western's Canadian customers decreasing year over year. As such, year over year activity levels in Canada are expected to be consistent with 2019 levels.  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. 

As at December 31, 2019, Western had $12.3 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 $211.2 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 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 consolidated statements of operations and comprehensive income, to Adjusted EBITDA:

	Three months ended December 31		Year ended December 31
(stated in thousands)	2019	2018	2019	2018
Net loss	(52,249)	(9,530)	(81,030)	(41,060)
Income tax recovery	(15,786)	(3,641)	(30,772)	(13,634)
Loss before income taxes	(68,035)	(13,171)	(111,802)	(54,694)
Add (deduct):
Depreciation	14,848	16,431	63,167	66,181
Stock based compensation	127	154	586	1,178
Finance costs	4,645	4,603	18,697	19,050
Other items	(1)	(101)	(410)	(99)
Impairment of property and equipment	54,000	-	54,000	-
Adjusted EBITDA	5,584	7,916	24,238	31,616

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 2020 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 2020 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; and the amount and timing of purchases of common shares under the Bid.

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, 2019 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: CAODC, monthly Contractor Summary.
2	Source: CAODC, monthly Contractor Summary.
3	Source: CAODC Contractor Summary as at February 27, 2020.
4	Source: CAODC Fleet List as at February 27, 2020.
5	Source: Baker Hughes Company, 2019 Rig Count monthly press releases.
6	Source: CAODC, monthly Contractor Summary.

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

Related Links

https://www.wesc.ca/