Western Energy Services Corp. Releases Fourth Quarter and Year End 2018 Financial and Operating Results

CALGARY, Feb. 13, 2019 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its fourth quarter and year end 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 years ended December 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.

Fourth Quarter 2018 Operating Results:

• Fourth quarter Operating Revenue decreased by $1.5 million to $57.8 million in 2018 as compared to $59.3 million in 2017.  In the contract drilling segment, Operating Revenue totalled $44.5 million in the fourth quarter of 2018, a decrease of $1.4 million (or 3%) as compared to $45.9 million in the fourth quarter of 2017.  In the production services segment, Operating Revenue totalled $13.3 million for the three months ended December 31, 2018, as compared to $13.4 million in the three months ended December 31, 2017, a decrease of $0.1 million (or 1%).  While pricing improved in the contract drilling segment and activity was higher for contract drilling in the United States and well servicing in Canada, lower contract drilling activity in Canada, decreased oilfield rental equipment activity, and lower pricing in the production services segment, impacted Operating Revenue as described below:
• Drilling rig utilization – Operating Days ("Drilling Rig Utilization") in Canada decreased to 32% in the fourth quarter of 2018 compared to an average of 38% in the same period of the prior year, reflecting a 600 basis points ("bps") reduction.  The decrease in activity was mainly attributable to record high differentials on Canadian crude oil realized in the fourth quarter of 2018 and heightened market uncertainty.  As a result, customers were quick to delay or cancel their drilling programs in the fourth quarter of 2018.  Fourth quarter 2018 Drilling Rig Utilization of 32% represented a premium of 400 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 28%, a decrease as compared to the fourth quarter of 2017 when Drilling Rig Utilization of 38% represented a premium of 1,000 bps to the industry average.  The decrease in the Company's utilization premium to the industry average in 2018 was 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 consistent at 10% in both the fourth quarter of 2018 and 2017.  Pricing continued to increase and resulted in a 4% improvement in Operating Revenue per Billable Day in the fourth quarter of 2018, as compared to the same period in the prior year.  The increase in pricing was a result of the Company being successful in steadily raising rates in 2018 prior to demand decreasing in the fourth quarter of 2018;
• In the United States, improved West Texas Intermediate ("WTI") prices led to six of the Company's seven drilling rigs operating during the quarter, three of which were working on long 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 at the end of the fourth quarter.  As a result of improved WTI pricing and a larger rig fleet, Operating Days increased by 29% in the fourth quarter of 2018, as compared to the same period in the prior year.  As a result, Drilling Rig Utilization improved to 71% in the fourth quarter of 2018, compared to 63% in the same period of the prior year.  Operating Revenue per Billable Day for the fourth quarter of 2018 improved by 10% as compared to the fourth quarter of 2017, as the improved commodity price environment led to increased demand and resulted in day rate increases on contracted rigs; and
• Service rig utilization was 28% in the fourth quarter of 2018 compared to 26% in the same period of the prior year.  The increase is due to continued marketing efforts to broaden the Company's customer base, despite customer programs being impacted significantly by record high crude oil differentials in the fourth quarter of 2018.  While utilization improved, service rig Operating Revenue per Service Hour decreased during the fourth quarter of 2018 by 6% as compared to the same period in the prior year, due to changes in the average rig mix.  Higher utilization, offset partially by lower pricing, led to well servicing Operating Revenue in the period increasing to $11.5 million, an improvement of $0.4 million (or 4%), as compared to the same period in the prior year.
• Fourth quarter Adjusted EBITDA decreased by $2.2 million (or 21%) to $7.9 million in 2018 as compared to $10.1 million in the fourth quarter of 2017.  The year over year change in Adjusted EBITDA is due to lower activity in the contract drilling segment in Canada, decreased oilfield rental equipment activity, and decreased well servicing hourly rates, which was offset partially by improved pricing in the contract drilling segment and higher utilization in the United States and well servicing in Canada.      
• Administrative expenses, excluding depreciation and stock based compensation, decreased by $1.0 million (or 17%) to $4.8 million, as compared to $5.8 million in the fourth quarter of 2017, mainly due to lower employee related costs.
• The Company incurred a net loss of $9.5 million in the fourth quarter of 2018 ($0.10 per basic common share) as compared to a net loss of $5.0 million in the same period in 2017 ($0.06 per basic common share).  The change can be attributed to the following:
• A $3.2 million decrease in income tax recovery due to the decrease in the federal corporate tax rates in the United States in 2017 from 35.0% to 21.0%, which resulted in a significant recovery in the prior period;
• A $2.2 million decrease in Adjusted EBITDA, mainly due to lower oilfield rental equipment activity and lower utilization in the contract drilling segment in Canada, offset partially by higher utilization in the United States and in well servicing in Canada; and
• A $0.6 million increase in other items, which include gains and losses on foreign exchange and asset sales.
  
  
• Offsetting the above mentioned items was a $1.0 million decrease in finance costs, due to lower total debt levels and a lower average interest rate.
• Fourth quarter 2018 capital expenditures of $6.1 million included $4.1 million of expansion capital and $2.0 million of maintenance capital.  In total, capital spending in the fourth quarter of 2018 increased by $0.2 million from the $5.9 million incurred in the fourth quarter of 2017.  The Company incurred expansion capital mainly related to drilling rig upgrades, including the acquisition and upgrade of one Cardium class rig in the Permian Basin, as well as required maintenance capital, in the fourth quarter of 2018.
• On December 12, 2018, the Company completed a number of amendments to its syndicated first lien credit facility (the "Revolving Facility") and its committed operating facility (the "Operating Facility" and together the "Credit Facilities"), including the following:
• Extended the maturity of its Credit Facilities to December 17, 2021;
• Elected to reduce the commitment under the Revolving Facility from $70.0 million to $50.0 million.  The commitment under the Operating Facility remains unchanged at $10.0 million;
• The minimum debt service coverage ratio financial covenant was removed; and
• A current ratio financial covenant was added whereby Western's current ratio, excluding the current portion of long term debt and accrued interest, must meet or exceed 1.15.

2018 Operating Results:

• Operating Revenue in 2018 decreased by $3.2 million (or 1%) to $215.8 million as compared to $219.0 million in 2017.  However, after normalizing for $6.4 million of shortfall commitment revenue recognized in the first quarter of 2017, Operating Revenue in 2018 improved by $3.2 million (or 2%).  In the contract drilling segment, Operating Revenue totalled $165.7 million in 2018, which after normalizing for $6.4 million of shortfall commitment revenue recognized in 2017, resulted in Operating Revenue improving by $5.4 million (or 3%).  In the production services segment, Operating Revenue totalled $50.3 million in 2018, as compared to $52.5 million in 2017, a decrease of $2.2 million (or 4%).  While on a year to date basis activity was lower in Canada, activity in the United States increased and pricing in all divisions improved which impacted Operating Revenue as described below:
• Drilling Rig Utilization in Canada for the year ended December 31, 2018 averaged 35%, compared to an average of 37% for the prior year, reflecting a 200 bps decrease.  The decrease in activity was due to some of Western's customers deferring or cancelling their drilling plans, particularly in the fourth quarter of 2018, amid high differentials on Canadian crude oil and low natural gas prices.  Drilling Rig Utilization of 35% in 2018 represented a premium of 600 bps to the CAODC industry average of 29%, whereas in 2017, Drilling Rig Utilization of 37% represented an 800 bps premium to the industry average.  The decrease in the Company's utilization premium to the industry average in 2018 was a function of a smaller industry rig fleet, as rigs continue to be decommissioned or moved 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, remained consistent at 10% in both 2018 and 2017.  While utilization decreased during 2018, pricing continued to increase and resulted in an 8% improvement in Operating Revenue per Billable Day in 2018, as compared to 2017.  The increase in pricing is a result of the Company being successful in steadily raising rates in 2018 prior to demand decreasing in the fourth quarter of 2018;
• In the United States, improved WTI prices led to six of the Company's seven drilling rigs operating during the year.  Late in the fourth quarter of 2018, the Company added a Cardium class drilling rig to its fleet in the United States, which began work in the Permian basin.  As a result of improved WTI pricing and a larger rig fleet, Operating Days increased by 16% in 2018, as compared to 2017.  While activity increased, Drilling Rig Utilization decreased marginally to 51% for the year ended December 31, 2018, as compared to 52% in the prior year, due to an increased rig fleet as two Cardium class drilling rigs were added to the fleet, one in late 2017 and the other in late 2018.  Operating Revenue per Billable Day in the United States improved by 5% in 2018, as compared to 2017, as the improved commodity price environment led to increased demand and resulted in day rate increases; and
• Service rig utilization of 25% for the year ended December 31, 2018 compared to 26% in the prior year.  Over the last nine months of 2018, well servicing activity improved over the same period of the prior year due to the continued marketing efforts to broaden the Company's customer base.  However, on a year over year basis, activity is down due to operating hours being lower in the first quarter of 2018.  Hourly rates improved in 2018, increasing by 1% as compared to the prior year, due to changes in the average rig mix and the Company working to increase rates across all areas.  Lower utilization, partially offset by improved pricing, led to a $1.2 million (or 3%) decrease in well servicing Operating Revenue in 2018.

• Adjusted EBITDA for the year ended December 31, 2018 decreased by $4.1 million (or 11%) to $31.6 million as compared to $35.7 million in 2017.  However, after normalizing for the $6.4 million in shortfall commitment revenue recognized in the first quarter of 2017, Adjusted EBITDA improved by $2.3 million (or 8%) in 2018, as compared to the prior year.  The year over year decrease in Adjusted EBITDA is due to lower activity and shortfall commitment revenue in Canada, offset by improved pricing in all divisions and increased activity in the United States.
• Administrative expenses in 2018, excluding depreciation and stock based compensation, decreased by $3.7 million (or 16%) to $18.9 million, as compared to $22.6 million in 2017, mainly due to lower employee related costs.
• The Company incurred a net loss of $41.1 million in 2018 ($0.45 per basic common share) as compared to a net loss of $37.4 million in 2017 ($0.48 per basic common share).  The change can be attributed to the following:
• A $4.1 million decrease in Adjusted EBITDA, mainly due to lower shortfall commitment revenue; and
• A $4.9 million decrease in income tax recovery mainly due to the decrease in the federal corporate tax rates in the United States in 2017 from 35.0% to 21.0%, which resulted in a significant recovery in the prior period.
• Offsetting the above mentioned items was:
• A $1.5 million positive change in other items, of which $1.6 million related to transaction costs incurred in the prior period, coupled with gains and losses on foreign exchange and asset sales;
• A $2.9 million decrease in finance costs, due to lower total debt levels; and
• A $0.8 million decrease in stock based compensation expense.
• Year to date capital expenditures of $20.0 million included $11.5 million of expansion capital and $8.5 million of maintenance capital.  In total, capital spending in 2018 increased by $1.9 million from the $18.1 million incurred in 2017.  The Company incurred expansion capital mainly related to drilling rig upgrades including the purchase and upgrade of one Cardium class rig in the Permian Basin, as well as required maintenance capital in 2018.
• 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 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.  Annual amortization payments equal to 1% of the original principal amount are payable in quarterly installments, which began on July 1, 2018, with the balance due on January 31, 2023.

Selected Financial Information
(stated in thousands, except share and per share amounts)
	Three months ended December 31				Year ended December 31
Financial Highlights	2018	2017	Change		2018	2017	Change
Revenue	63,133	66,515	(5%)		236,410	238,175	(1%)
Operating Revenue^(1)	57,806	59,255	(2%)		215,818	218,988	(1%)
Gross Margin^(1)	12,677	15,886	(20%)		50,535	58,310	(13%)
Gross Margin as a percentage of Operating Revenue	22%	27%	(19%)		23%	27%	(15%)
Adjusted EBITDA^(1)	7,916	10,067	(21%)		31,616	35,695	(11%)
Adjusted EBITDA as a percentage of Operating Revenue	14%	17%	(18%)		15%	16%	(6%)
Cash flow from operating activities	5,022	(800)	(728%)		33,231	24,641	35%
Capital expenditures	6,102	5,912	3%		19,960	18,132	10%
Net loss	(9,530)	(4,974)	92%		(41,060)	(37,445)	10%
– basic net loss per share	(0.10)	(0.06)	67%		(0.45)	(0.48)	(6%)
– diluted net loss per share	(0.10)	(0.06)	67%		(0.45)	(0.48)	(6%)
Weighted average number of shares
– basic	92,305,208	88,812,216	4%		92,224,585	77,601,827	19%
– diluted	92,305,208	88,812,216	4%		92,224,585	77,601,827	19%
Outstanding common shares as at period end	92,305,542	92,175,598	-		92,305,542	92,175,598	-
(1)  See "Non-IFRS measures" included in this press release.
	Three months ended December 31				Year ended December 31
Operating Highlights^(1)	2018	2017	Change		2018	2017	Change
Contract Drilling
Canadian Operations:
Contract drilling rig fleet:
– Average active rig count	18.1	21.6	(16%)		19.2	20.6	(7%)
– End of period	50	50	-		50	50	-
Operating Revenue per Billable Day	19,622	18,807	4%		18,922	17,558^(3)	8%
Operating Revenue per Operating Day	21,973	21,100	4%		20,984	19,446^(3)	8%
Operating Days	1,487	1,774	(16%)		6,328	6,801	(7%)
Drilling rig utilization – Billable Days	36%	43%	(16%)		38%	41%	(7%)
Drilling rig utilization – Operating Days	32%	38%	(16%)		35%	37%	(5%)
CAODC industry average utilization – Operating Days^(2)	28%	28%	-		29%	29%	-
United States Operations:
Contract drilling rig fleet:
– Average active rig count	4.9	4.0	23%		3.4	3.1	10%
– End of period	7	6	17%		7	6	17%
Operating Revenue per Billable Day (US$)	19,756	18,038	10%		20,227	19,198	5%
Operating Revenue per Operating Day (US$)	22,183	21,265	4%		22,586	22,338	1%
Operating Days	403	313	29%		1,121	969	16%
Drilling rig utilization – Billable Days	79%	75%	5%		57%	61%	(7%)
Drilling rig utilization – Operating Days	71%	63%	13%		51%	52%	(2%)
Production Services
Well servicing rig fleet:
– Average active rig count	18.8	17.0	11%		16.5	17.2	(4%)
– End of period	66	66	-		66	66	-
Service rig Operating Revenue per Service Hour	667	708	(6%)		683	673	1%
Service Hours	17,247	15,650	10%		60,337	62,946	(4%)
Service rig utilization	28%	26%	9%		25%	26%	(4%)

(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 year ended December 31, 2017.

Financial Position at (stated in thousands)	December 31, 2018	December 31, 2017	Change
Working capital	15,739	62,866	(75%)
Property and equipment	615,395	652,828	(6%)
Total assets	667,295	760,504	(12%)
Long term debt	222,258	265,219	(16%)

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 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 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 December 31, 2018 and 2017 and for the years ended December 31, 2018 and 2017.

	Three months ended December 31			Year ended December 31
	2018	2017	Change	2018	2017	Change
Average crude oil and natural gas prices^(1)(2)
Crude Oil
West Texas Intermediate (US$/bbl)	59.32	55.28	7%	64.95	50.81	28%
Western Canadian Select (CDN$/bbl)	33.91	49.10	(31%)	49.97	49.49	1%
Natural Gas
30 day Spot AECO (CDN$/mcf)	1.61	1.67	(4%)	1.53	2.23	(31%)
Average foreign exchange rates^(2)
US dollar to Canadian dollar	1.32	1.27	4%	1.30	1.30	-

(1)	See "Abbreviations" included in this press release.
(2)	Source: Bloomberg

WTI on average improved by 7% and 28% for the three months and year ended December 31, 2018 respectively, compared to the same periods in the prior year.  However, pricing on Canadian crude oil collapsed in the fourth quarter of 2018, resulting in record differentials.  As a result, the price for Western Canadian Select ("WCS") decreased by 31% for the three months ended December 31, 2018, as compared to the same period in the prior year, while on a year over year basis WCS improved by only 1%.  The United States dollar to Canadian dollar foreign exchange rate remained constant year over year, though the weakening of the Canadian dollar in the fourth quarter of 2018 had a slightly positive effect on the cash flows of Western's Canadian customers, when selling United States dollar denominated commodities.  Natural gas prices declined for both the three months and year ended December 31, 2018, as the 30 day spot AECO price decreased by 4% and 31% respectively, over the same periods of the prior year, however fourth quarter 2018 average AECO prices improved by 28% as compared to the third quarter of 2018.       

In the United States, improved market conditions in 2018 have led to a corresponding increase in the demand for oilfield services.  As reported by Baker Hughes, a GE Company, the average number of active drilling rigs in the United States increased approximately 18% in 2018 as compared to 2017.  However, market conditions in Canada did not improve.  Higher WTI prices were largely offset by increased differentials on Canadian crude oil, which hit record highs in the fourth quarter of 2018, prior to narrowing upon the announcement of mandatory crude oil production curtailments by the Government of Alberta.  This intervention increased market uncertainty, so the higher pricing did not correspond to higher activity.  Additionally, the 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 3% in 2018 as compared to 2017.

Outlook

Currently, 27 of Western's drilling rigs are operating.  Six of Western's 57 drilling rigs (or 11%) are under long term take or pay contracts, with three 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, have resulted in the announced capital budgets for Western's Canadian customers decreasing year over year in 2019 compared to 2018.  As such, 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 in Canada into more active resource plays in the United States.  Early in 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.  As at December 31, 2018, Western had $11.9 million drawn on its $60.0 million Credit Facilities, which mature on December 17, 2021 and currently has $213.4 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, 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 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.  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 consolidated statements of operations and comprehensive income, to Operating Revenue and Gross Margin:

	Three months ended December 31				Year ended December 31
(stated in thousands)	2018	2017			2018	2017
Operating Revenue
Drilling	44,498	45,906			165,684	166,660
Production services	13,283	13,362			50,345	52,456
Less: inter-company eliminations	25	(13)			(211)	(128)
	57,806	59,255			215,818	218,988
Third party charges	5,364	7,260			20,629	19,187
Less: inter-company eliminations	(37)	-			(37)	-
Revenue	63,133	66,515			236,410	238,175
Less: operating expenses	(66,675)	(66,933)			(251,378)	(245,352)
Add:
Depreciation – operating	16,161	16,238			65,097	65,227
Stock based compensation – operating	58	66			406	260
Gross Margin	12,677	15,886			50,535	58,310

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 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 December 31				Year ended December 31
(stated in thousands)		2018	2017		2018	2017
Net loss		(9,530)	(4,974)		(41,060)	(37,445)
Add:
Finance costs		4,603	5,598		19,050	21,950
Income tax recovery		(3,641)	(6,842)		(13,634)	(18,555)
Depreciation – operating		16,161	16,238		65,097	65,227
Depreciation – administrative		270	284		1,084	1,213
EBITDA		7,863	10,304		30,537	32,390
Add:
Stock based compensation – operating		58	66		406	260
Stock based compensation – administrative		96	397		772	1,689
Other items		(101)	(700)		(99)	1,356
Adjusted EBITDA		7,916	10,067		31,616	35,695
Subtract:
Depreciation – operating		(16,161)	(16,238)		(65,097)	(65,227)
Depreciation – administrative		(270)	(284)		(1,084)	(1,213)
Operating Loss		(8,515)	(6,455)		(34,565)	(30,745)

Net Debt

Management believes that Net Debt is a useful supplemental measure as it provides an indication of the Company's total debt after incorporating cash and cash equivalents.  The closest IFRS measure would be long term debt.

The following table provides a reconciliation of long term debt under IFRS, as disclosed in the consolidated balance sheets to Net Debt:

(stated in thousands)			December 31, 2018	December 31, 2017
Long term debt			222,258	265,219
Current portion of long term debt			1,822	475
Less: cash and cash equivalents			(3,960)	(48,825)
Net Debt			220,120	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");
• 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", "propose", "anticipate", "believe", "estimate", "plan", "potential", "continue", "working 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 Operating Days typically generated from the Company's contracts); the Company's expansion and maintenance capital plans for 2019; the Company's liquidity needs including the ability of current capital resources to cover Western's financial obligations and the 2019 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; expectations as to the increase in crude oil transportation capacity through pipeline development; expectations as to the benefits of the proposed liquefied natural gas expansion in British Columbia; the future deployment of rigs; the potential impact of changes to environmental laws and regulations and the price on carbon emissions; 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, 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 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 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.wesc.ca