Western Energy Services Corp. Releases Second Quarter 2019 Financial and Operating Results

CALGARY, July 24, 2019 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its second 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 six months ended June 30, 2019 and 2018 will be available on SEDAR at www.sedar.com.  Non-International Financial Reporting Standards ("Non-IFRS") measures, such as Operating Revenue, Gross Margin, Adjusted EBITDA and Operating Loss, and abbreviations for standard industry terms are included in this press release.  All amounts are denominated in Canadian dollars (CDN$) unless otherwise identified.

Second Quarter 2019 Operating Results:

• Second quarter Operating Revenue increased by $3.7 million to $34.7 million in 2019 as compared to $31.0 million in 2018.  In the contract drilling segment, Operating Revenue totalled $25.2 million in the second quarter of 2019, an increase of $3.4 million (or 16%) as compared to $21.8 million in the second quarter of 2018, and included US$1.3 million in shortfall commitment revenue.  In the production services segment, Operating Revenue totalled $9.6 million for the three months ended June 30, 2019, as compared to $9.2 million for the three months ended June 30, 2018, an increase of $0.4 million (or 4%).  Activity was higher for contract drilling in the United States and for well servicing in Canada; whereas lower contract drilling and oilfield rental equipment activity in Canada impacted Operating Revenue as described below:
• Drilling rig utilization – Operating Days ("Drilling Rig Utilization") in Canada decreased to 13% in the second quarter of 2019 compared to an average of 17% in the same period of the prior year, reflecting a 400 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 their 2019 drilling programs.  Second quarter 2019 Drilling Rig Utilization of 13% represented a discount of 100 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 14%, a decrease as compared to the second quarter of 2018 when Drilling Rig Utilization of 17% was consistent with 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, remained consistent at 8% in both the second quarter of 2019 and the second quarter of 2018.  Despite lower activity, pricing improved and resulted in a 4% increase in Operating Revenue per Billable Day in the second quarter of 2019, as compared to the same period in the prior year, as day rates on the Company's high specification Duvernay class and Montney class rigs have improved.
• In the United States, improved West Texas Intermediate ("WTI") prices led to six of the Company's eight drilling rigs working during the quarter, three 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.  As a result of a larger and more geographically diversified rig fleet in the second quarter of 2019, Operating Days increased by 104%, as compared to the same period in the prior year.  Furthermore, Drilling Rig Utilization improved to 46% in the second quarter of 2019, compared to 30% in the same period of the prior year.  While day rates on the Company's high specification Duvernay class rigs improved, Operating Revenue per Billable Day for the second quarter of 2019, excluding shortfall commitment revenue, decreased by 11% as the newly acquired Cardium class rig, which worked at a lower day rate and also has a significantly lower capital investment, decreased the average day rate in the United States; and
• In Canada, service rig utilization was 20% in the second quarter of 2019 compared to 16% 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.  While utilization improved, service rig Operating Revenue per Service Hour decreased during the second quarter of 2019 by 9%, 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 Operating Revenue in the period increasing to $7.6 million, an improvement of $0.7 million (or 10%), as compared to the same period in the prior year.
• Second quarter Adjusted EBITDA increased by $1.5 million (or 172%) to $2.4 million in 2019 as compared to $0.9 million in the second quarter of 2018.  The year over year change in Adjusted EBITDA is due to US$1.3 million in shortfall commitment revenue earned in the quarter and higher utilization for contract drilling in the United States, offset partially by lower Adjusted EBITDA in all Canadian divisions, as well as $0.4 million in costs related to establishing well servicing operations for Western Oilfield Services in the United States.
• Administrative expenses, excluding depreciation and stock based compensation, decreased by $0.3 million (or 7%) to $4.4 million, as compared to $4.7 million in the second 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 $10.1 million in the second quarter of 2019 ($0.11 per basic common share) as compared to a net loss of $15.5 million in the same period in 2018 ($0.17 per basic common share).  The change can be attributed to:
• A $1.5 million increase in Adjusted EBITDA, mainly due to US$1.3 million in shortfall commitment revenue; and
• A $3.6 million increase in income tax recovery due to the reduction in the provincial corporate tax rate that was substantively enacted by the Government of Alberta in the second quarter of 2019;

Offsetting the above mentioned items was:

• A $0.2 million increase in finance costs due to higher long term debt balances outstanding in the quarter; and
• A $0.1 million change in other items, which include gains and losses on foreign exchange and asset sales.
• Second quarter 2019 capital expenditures of $1.7 million consist primarily of maintenance capital.  In total, capital spending in the second quarter of 2019 decreased by $3.7 million from the $5.4 million incurred in the second quarter of 2018.

Year to Date 2019 Operating Results:

• Operating Revenue for the six month period ended June 30, 2019 decreased by $7.4 million to $96.5 million as compared to $103.9 million for the six month period ended June 30, 2018.  In the contract drilling segment, Operating Revenue totalled $71.1 million for the six months ended June 30, 2019, including US$1.3 million of shortfall commitment revenue, and reflects a decrease of $8.0 million (or 10%) as compared to $79.1 million for the six months ended June 30, 2018.  In the production services segment, Operating Revenue totalled $25.5 million for the six months ended June 30, 2019, as compared to $25.0 million in the same period of the prior year, an increase of $0.5 million (or 2%).  Activity was higher for contract drilling in the United States and for well servicing in Canada; whereas lower contract drilling and oilfield rental equipment activity in Canada impacted Operating Revenue as described below:
• Drilling Rig Utilization in Canada for the six month period ended June 30, 2019 decreased to 23%, compared to an average of 34% for the six month period ended June 30, 2018, reflecting a 1,100 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 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 six months of 2018, Drilling Rig Utilization of 34% represented a 500 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 9.2% for the first six months of 2019, as compared to 9.6% in the same period of the prior year.  Despite lower activity, pricing reflects a 3% improvement in Operating Revenue per Billable Day in 2019, as compared to the same period in the prior year, as day rates have increased in all rig classes.
• In the United States, seven of the Company's eight drilling rigs worked year to date, three 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.  As a result of a larger and more geographically diversified rig fleet in the first six months of 2019, Operating Days increased by 73% in 2019, as compared to the same period in the prior year.  Furthermore, Drilling Rig Utilization improved to 55% for the six months ended June 30, 2019, compared to 40% in the same period of the prior year.  While day rates on the Company's high specification Duvernay class rigs improved, Operating Revenue per Billable Day for the six months ended June 30, 2019, excluding shortfall commitment revenue, decreased by 5% as the newly acquired Cardium class rig, which worked at a lower day rate and also has a significantly lower capital investment, decreased the average day rate in the United States; and
• In Canada, service rig utilization was 28% for the six months ended June 30, 2019 compared to 23% 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.  While utilization improved, service rig Operating Revenue per Service Hour decreased during the six months ended June 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 Operating Revenue in the period increasing to $21.4 million, an improvement of $1.5 million (or 8%), as compared to the same period in the prior year.
• Adjusted EBITDA for the six months ended June 30, 2019 decreased by $2.3 million (or 15%) to $13.7 million as compared to $16.0 million for the six months ended June 30, 2018.  The year over year change in Adjusted EBITDA is due to lower Adjusted EBITDA in all Canadian divisions, coupled with $0.8 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 and increased contract drilling activity in the United States.
• Administrative expenses, excluding depreciation and stock based compensation, for the six month period ended June 30, 2019 decreased by $1.2 million (or 12%) to $8.6 million, as compared to $9.8 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 $17.2 million for the six months ended June 30, 2019 ($0.19 per basic common share) as compared to a net loss of $21.4 million in the same period in 2018 ($0.23 per basic common share).  The change can be attributed to:
• A $4.9 million increase in income tax recovery due to the reduction in the provincial corporate tax rate that was substantively enacted by the Government of Alberta in the second quarter of 2019;
• A $0.5 million decrease in finance costs, 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;
• A $0.5 million decrease in stock based compensation expense;
• A $0.4 million decrease in depreciation expense due to certain assets being fully depreciated in the period; and
• A $0.2 million change in other items, which include gains and losses on foreign exchange and asset sales.

Offsetting the above mentioned items was a $2.3 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 capital expenditures of $3.9 million included $1.2 million of expansion capital and $2.7 million of maintenance capital.  In total, capital spending for the six months ended June 30, 2019 decreased by $6.2 million from the $10.1 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 six months ended June 30, 2019, the impact of IFRS 16 on Adjusted EBITDA was an increase of $0.8 million and $1.6 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 and finance costs.

Selected Financial Information
(stated in thousands, except share and per share amounts)
	Three months ended June 30				Six month ended June 30
Financial Highlights	2019	2018	Change		2019	2018	Change
Revenue	37,728	33,141	14%		103,503	114,398	(10%)
Operating Revenue^(1)	34,692	30,976	12%		96,465	103,941	(7%)
Gross Margin^(1)	6,792	5,562	22%		22,324	25,833	(14%)
Gross Margin as a percentage of Operating Revenue	20%	18%	11%		23%	25%	(8%)
Adjusted EBITDA^(1)	2,438	897	172%		13,686	16,009	(15%)
Adjusted EBITDA as a percentage of Operating Revenue	7%	3%	133%		14%	15%	(7%)
Cash flow from operating activities	17,501	26,313	(33%)		23,389	30,177	(22%)
Capital expenditures	1,691	5,426	(69%)		3,883	10,082	(61%)
Net loss	(10,128)	(15,475)	(35%)		(17,206)	(21,422)	(20%)
– basic net loss per share	(0.11)	(0.17)	(35%)		(0.19)	(0.23)	(17%)
– diluted net loss per share	(0.11)	(0.17)	(35%)		(0.19)	(0.23)	(17%)
Weighted average number of shares
– basic	92,307,042	92,178,383	-		92,306,939	92,177,719	-
– diluted	92,307,042	92,178,383	-		92,306,939	92,177,719	-
Outstanding common shares as at period end	92,307,042	92,179,281	-		92,307,042	92,179,281	-
(1)  See "Non-IFRS measures" included in this press release.
	Three months ended June 30				Six months ended June 30
Operating Highlights^(1)	2019	2018	Change		2019	2018	Change
Contract Drilling
Canadian Operations:
Contract drilling rig fleet:
– Average active rig count	7.0	9.2	(24%)		12.8	19.1	(33%)
– End of period	49	50	(2%)		49	50	(2%)
Operating Revenue per Billable Day	20,167	19,453	4%		19,664	19,113	3%
Operating Revenue per Operating Day	22,022	21,363	3%		21,988	21,218	4%
Operating Days	582	761	(24%)		2,075	3,112	(33%)
Drilling rig utilization – Billable Days	14%	18%	(22%)		26%	38%	(32%)
Drilling rig utilization – Operating Days	13%	17%	(24%)		23%	34%	(32%)
CAODC industry average utilization – Operating Days^(2)	14%	17%	(18%)		22%	29%	(24%)
United States Operations:
Contract drilling rig fleet:
– Average active rig count	4.3	2.1	105%		4.9	2.7	81%
– End of period	8	6	33%		8	6	33%
Operating Revenue per Billable Day (US$)	20,286^(3)	22,815	(11%)		19,968^(3)	21,040	(5%)
Operating Revenue per Operating Day (US$)	23,576^(3)	25,865	(9%)		23,402^(3)	23,356	-
Operating Days	338	166	104%		760	440	73%
Drilling rig utilization – Billable Days	54%	34%	59%		64%	45%	42%
Drilling rig utilization – Operating Days	46%	30%	53%		55%	40%	38%
Production Services
Canadian Operations: Well servicing rig fleet:
– Average active rig count	13.0	10.5	24%		18.0	15.5	16%
– End of period	63	66	(5%)		63	66	(5%)
Service rig Operating Revenue per Service Hour	655	723	(9%)		665	710	(6%)
Service Hours	11,646	9,588	21%		32,144	28,064	15%
Service rig utilization	20%	16%	25%		28%	23%	22%

(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 US$1.3 million for the three and six months ended June 30, 2019.

Financial Position at (stated in thousands)	June 30, 2019	December 31, 2018	June 30, 2018
Working capital	4,981	15,739	7,717
Property and equipment	591,935	615,395	634,812
Total assets	626,890	667,295	670,584
Long term debt	223,363	222,258	210,944

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 six months ended June 30, 2019 and 2018.

	Three months ended June 30				Six months ended June 30
	2019	2018	Change		2019	2018	Change
Average crude oil and natural gas prices^(1)(2)
Crude Oil
West Texas Intermediate (US$/bbl)	59.84	67.88	(12%)		57.33	65.38	(12%)
Western Canadian Select (CDN$/bbl)	65.75	62.81	5%		61.20	55.78	10%
Natural Gas
30 day Spot AECO (CDN$/mcf)	1.08	1.18	(8%)		1.82	1.59	14%
Average foreign exchange rates^(2)
US dollar to Canadian dollar	1.34	1.29	4%		1.33	1.28	4%
(1) See "Abbreviations" included in this press release.
(2) Source: Sproule

WTI on average declined for both the three and six months ended June 30, 2019 by 12%, compared to the same periods in the prior year.  However, pricing on Canadian crude oil increased for both the three and six months ended June 30, 2019, as 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, coupled with a weaker Canadian dollar.  As a result, the price for Western Canadian Select ("WCS") increased by 5% and 10% respectively, for the three and six months ended June 30, 2019.  Natural gas prices in Canada were volatile and declined for the three months ended June 30, 2019, as the 30 day spot AECO price decreased by 8% over the same period in the prior year; however, for the six months ended June 30, 2019, the 30 day spot AECO price improved by 14%, compared to the same period of the prior year.        

In the United States, market conditions have remained relatively stable in 2019.  As reported by Baker Hughes, a GE Company, the average number of active drilling rigs in the United States decreased by 5% in the second quarter of 2019 as compared to the same period in the prior year, while for the six months ended June 30, 2019, active drilling rigs increased by approximately 2% as compared to the same period in the prior year.  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 CAODC reported that for drilling in Canada, the total number of Operating Days in the WCSB decreased by approximately 25% and 31% respectively, for the three and six months ended June 30, 2019, as compared to the same periods in the prior year.

Outlook

Currently, 19 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.

Western's capital budget for 2019 remains unchanged and is expected to total $15 million with $2 million allocated for expansion capital and $13 million for maintenance capital.  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 the announced 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 decrease in 2019.  Controlling fixed costs and maintaining balance sheet flexibility are priorities for the Company, as prices for Western's services remain below historical levels.  However, 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 June 30, 2019, Western had $5.2 million drawn on its $60.0 million credit facilities, consisting of its syndicated first lien credit facility (the "Revolving Facility") and its committed operating facility (the "Operating Facility" and together the "Credit Facilities"), which mature on December 17, 2021 and currently has $212.3 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.  These Non-IFRS measures are identified and defined as follows:

Operating Revenue

Management believes that 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.  The closest IFRS measure would be revenue.

Gross Margin

Management believes that 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 closest IFRS measure would be net income.

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 June 30			Six months ended June 30
(stated in thousands)		2019	2018		2019	2018
Operating Revenue
Drilling		25,184	21,791		71,068	79,141
Production services		9,559	9,227		25,539	24,962
Less: inter-company eliminations		(51)	(42)		(142)	(162)
		34,692	30,976		96,465	103,941
Third party charges		3,042	2,165		7,050	10,457
Less: inter-company eliminations		(6)	-		(12)	-
Revenue		37,728	33,141		103,503	114,398
Less: operating expenses		(46,835)	(44,081)		(112,862)	(121,566)
Add:
Depreciation – operating		15,817	16,313		31,550	32,704
Stock based compensation – operating		82	189		133	297
Gross Margin		6,792	5,562		22,324	25,833

Adjusted EBITDA

Management believes that 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.  The closest IFRS measure would be net income. 

Operating Earnings (Loss)

Management believes that Operating Earnings (Loss) 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 closest IFRS measure would be net income.

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 Loss:

		Three months ended June 30		Six months ended June 30
(stated in thousands)		2019	2018	2018	2019
Net loss		(10,128)	(15,475)	(17,206)	(21,422)
Add:
Finance costs		4,700	4,493	9,376	9,873
Income tax recovery		(8,807)	(5,153)	(11,329)	(6,395)
Depreciation – operating		15,817	16,313	31,550	32,704
Depreciation – administrative		655	286	1,298	545
EBITDA		2,237	464	13,689	15,305
Add:
Stock based compensation – operating		82	189	133	297
Stock based compensation – administrative		58	254	181	504
Other items		61	(10)	(317)	(97)
Adjusted EBITDA		2,438	897	13,686	16,009
Less:
Depreciation – operating		(15,817)	(16,313)	(31,550)	(32,704)
Depreciation – administrative		(655)	(286)	(1,298)	(545)
Operating Loss		(14,034)	(15,702)	(19,162)	(17,240)

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 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 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.

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

http://www.westernenergyservices.com