Western Energy Services Corp. Releases Third Quarter 2017 Financial and Operating Results

Oct. 25, 2017, CALGARY /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its third quarter 2017 financial and operating results.  Additional information relating to the Company, including the Company's financial statements and management's discussion and analysis as at and for the three and nine months ended September 30, 2017 and 2016 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.

Third Quarter 2017 Operating Results:

• Operating Revenue in the third quarter of 2017 benefited from improved crude oil prices and resulted in higher customer spending and a corresponding increase in demand for Western's services. Third quarter Operating Revenue increased by $20.4 million (or 67%) to $51.1 million in 2017 as compared to $30.7 million in 2016. In the contract drilling segment, Operating Revenue totalled $38.7 million in the third quarter of 2017 as compared to $20.2 million in the third quarter of 2016, an increase of $18.5 million (or 92%); while in the production services segment, Operating Revenue totalled $12.4 million for the three months ended September 30, 2017 as compared to $10.5 million in the third quarter of 2016, an increase of $1.9 million (or 19%). Higher utilization in the third quarter of 2017, and improved pricing in all divisions, positively impacted Operating Revenue in the contract drilling and production services segments as described below:
• Drilling rig utilization – Operating Days ("Drilling Rig Utilization") in Canada averaged 36% in the third quarter of 2017 compared to an average of 20% in the third quarter of 2016, reflecting a 1,600 basis points ("bps") increase. Third quarter 2017 Drilling Rig Utilization represented a premium of 700 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 29%, whereas in the third quarter of 2016, Drilling Rig Utilization of 20% represented a 300 bps premium to the industry average. The increase in the Company's utilization premium to the industry average in the third quarter of 2017 is attributable to:
• the quality of Western's drilling rig fleet;
• the ability of the Company's rig crews;
• the efforts by the Company's marketing group to reposition rigs for existing and new customers; and
• a number of Western's customers increasing their capital budgets for 2017, as compared to 2016 when customer spending was limited

These factors, combined with improved commodity prices, resulted in higher demand for the Company's drilling rigs.  Operating Revenue per Billable Day in the third quarter of 2017 improved by 10% as compared to the same period in the prior year, as market conditions continued to improve;

• In the United States, four of the Company's five drilling rigs operated during the quarter, two of which were working on long term contracts, resulting in Drilling Rig Utilization of 59% in the third quarter of 2017, as compared to 32% in the same period of the prior year. Further, increased activity has led to improved pricing, as Operating Revenue per Billable Day in the United States improved by 4% in the third quarter of 2017 as compared to the third quarter of 2016; and
• Well servicing utilization of 27% in the third quarter of 2017 compared to 24% in the same period of the prior year. Improved market conditions resulted in a 4% increase in hourly rates during the third quarter of 2017, as compared to the same period in the prior year. Improved utilization and pricing, led to a $1.6 million (or 19%) increase in well servicing Operating Revenue in the period.
• Third quarter Adjusted EBITDA improved by $6.0 million to $6.9 million in 2017 as compared to $0.9 million in the third quarter of 2016. The year over year change in Adjusted EBITDA is due to higher activity and improved pricing across all divisions in 2017.
• Administrative expenses, excluding depreciation and stock based compensation, decreased by 2% in the third quarter of 2017 as compared to the second quarter of 2017 due to lower employee costs. Third quarter 2017 administrative expenses increased by $0.6 million (or 12%) to $5.4 million, as compared to $4.8 million in the third quarter of 2016 mainly due to higher employee related costs, coupled with one time professional fees incurred in the period.
• The Company incurred a net loss of $11.5 million in the third quarter of 2017 ($0.16 per basic common share) as compared to a net loss of $17.0 million in the same period in 2016 ($0.23 per basic common share). The change can be attributed to the following:
• A $6.0 million increase in Adjusted EBITDA due to higher utilization and pricing in both the contract drilling and production services segments;
• A $0.7 million decrease in stock based compensation expense due to a greater portion of the Company's outstanding stock options and restricted share units being fully vested in the quarter; and
• A $0.6 million decrease in depreciation expense due to lower capital spending and certain equipment being fully depreciated over the last four quarters.

Offsetting the above mentioned items is a $1.9 million decrease in income tax recovery due to improved earnings before taxes.

• Third quarter 2017 capital expenditures of $6.3 million included $4.0 million of expansion capital and $2.3 million of maintenance capital. In total, capital spending in the third quarter of 2017 increased by $5.6 million from the $0.7 million incurred in the third quarter of 2016. The Company incurred expansion capital mainly related to drilling rig upgrades in the third quarter of 2017, as well as necessary maintenance capital related to the higher activity in the period.
• Subsequent to September 30, 2017, on October 17, 2017 the Company closed the following financing transactions:
• A lending agreement with Alberta Investment Management Corporation ("AIMCo") providing for a $215.0 million second lien secured term loan facility (the "Second Lien Facility"). The Second Lien Facility is available in a single draw which will be used to repay a portion of the Company's outstanding 7⅞% senior unsecured notes (the "Senior Notes"). Interest will be payable semi-annually, at a rate of 7.25% per annum, on January 1 and July 1 each year. Amortization payments equal to 1% of the principal amount will be payable annually in quarterly installments beginning on July 1, 2018, with the balance due on maturity, five years from the draw date. In conjunction with the Second Lien Facility, Western has issued to AIMCo approximately 7.1 million warrants to purchase common shares of Western, at an exercise price of $1.77 per common share, which have a three year life and expire on October 17, 2020;
• A private placement with AIMCo (the "Private Placement") of 9.1 million common shares of Western at a price of $1.25 per common share, for aggregate gross proceeds of $11.4 million;
• A bought deal offering of common shares of Western with a syndicate of underwriters (the "Bought Deal") where the underwriters purchased 9.1 million common shares of Western at a price of $1.25 per common share, for aggregate gross proceeds of $11.4 million; and
• Completed a number of amendments to its Credit Facilities, including the following:
• Extended the maturity of its syndicated revolving credit facility (the "Revolving Facility") and its committed operating facility (the "Operating Facility" and together the "Credit Facilities") to December 17, 2020;
• Increased the limit of the Revolving Facility from $50.0 million to $70.0 million, while the $10.0 million Operating Facility limit remains unchanged;
• The interest coverage and current ratio covenants have been permanently removed;
• A debt service coverage ratio has been added, which is calculated based on EBITDA, as defined in the Credit Facilities agreement, divided by the sum of interest expense and scheduled long term debt principal repayments. This covenant will only be tested when the outstanding principal under the Credit Facilities exceeds $40.0 million or net book value of property and equipment is less than $500.0 million. If applicable, the debt service coverage ratio must meet or exceed 1.0 as at and prior to March 31, 2018, 1.25 as at June 30, 2018, 1.5 as at September 30, 2018 and December 31, 2018, and 2.0 thereafter; and
• The Revolving Facility will continue to include an accordion feature, whereby an incremental $50.0 million of borrowing would be available, subject to the approval of the lenders.

Western expects that the net proceeds of the Second Lien Facility, Private Placement and the Bought Deal, along with cash on hand and funds available under the Credit Facilities will be used to repay the Company's Senior Notes in the first quarter of 2018 when the Senior Notes will be redeemable at par.

Year to Date 2017 Operating Results:

• Operating Revenue for the nine month period ended September 30, 2017 benefited from improved commodity prices and higher customer spending which resulted in a corresponding increase in demand for Western's services. For the nine months ended September 30, 2017, Operating Revenue increased by $84.4 million (or 112%) to $159.7 million as compared to $75.3 million for the nine months ended September 30, 2016. In the contract drilling segment, Operating Revenue totalled $120.8 million for the nine months ended September 30, 2017, an increase of $70.9 million (or 142%), as compared to $49.9 million in the same period of the prior year, and included $6.4 million in shortfall commitment revenue in 2017, as compared to $1.8 million in 2016; while in the production services segment, Operating Revenue totalled $39.1 million, an increase of $13.7 million (or 54%) as compared to $25.4 million in the same period of the prior year. Higher utilization for the nine months ended September 30, 2017, as compared to the same period of the prior year, offset by lower pricing in the contract drilling segment, impacted Operating Revenue in the contract drilling and production services segments as described below:
• Drilling Rig Utilization in Canada of 36% for the nine month period ended September 30, 2017, compared to 14% for the nine month period ended September 30, 2016, reflecting a 2,200 bps increase. Drilling Rig Utilization of 36% in 2017 represents a 700 bps premium to the CAODC industry average, whereas in the nine months ended September 30, 2016, Drilling Rig Utilization of 14% represented a 100 bps discount to the CAODC industry average. The increase in the Company's utilization premium in 2017 is attributable to:
• the quality of Western's drilling rig fleet;
• the ability of the Company's rig crews;
• the efforts by the Company's marketing group to reposition rigs for existing and new customers; and
• a number of Western's customers increasing their capital budgets for 2017, as compared to 2016 when customer spending was limite

These factors, combined with improved commodity prices, resulted in higher demand for the Company's drilling rigs. Additionally, Western continued to increase its market share in 2017. Western's 51 drilling rigs in Canada represent approximately 8% of the rigs registered with the CAODC, however Western's total operating days in 2017, represented 10% of the total industry Operating Days reported by the CAODC. Operating Revenue per Billable Day in the current period, was consistent with the same period in the prior year, decreasing by 1% as compared to the same period in the prior year.

• In the United States, four of the Company's five drilling rigs operated during the period, two of which were working on long term contracts, resulting in Drilling Rig Utilization of 48% for the nine months ended September 30, 2017, as compared to 22% in the same period of the prior year. Operating Revenue per Billable Day in the United States decreased by 12% for the nine months ended September 30, 2017 due to changes in the mix of rigs working on spot rates versus long term contracts, as compared to the same period of the prior year when the Company had one rig working on a long term legacy contract; and
• Well servicing utilization of 26% for the nine months ended September 30, 2017 compared to 17% in the same period of the prior year. Continued improvements in commodity prices helped improve activity year over year. Additionally, well servicing hourly rates increased by 2% for the nine months ended September 30, 2017, as compared to the nine months ended September 30, 2016. Improved utilization and pricing led to an $11.2 million (or 56%) increase in well servicing Operating Revenue in the period.
• Adjusted EBITDA for the nine months ended September 30, 2017 increased by $23.3 million to $25.6 million in 2017 as compared to $2.3 million for the nine months ended September 30, 2016. The year over year increase in Adjusted EBITDA is due to higher activity across all divisions, a $4.6 million increase in shortfall commitment revenue in 2017, and the Company's ability to safely and efficiently reactivate equipment and crews without incurring significant costs, including rigs that had been idle for an extended period of time. These factors were aided by improved pricing in the production services segment, which was partially offset by lower pricing in the contract drilling segment.
• Administrative expenses, excluding depreciation and stock based compensation, for the nine month period ended September 30, 2017 increased by $1.8 million (or 12%) to $16.8 million as compared to $15.0 million in the same period of the prior year. The increase in administrative expenses is mainly due to higher employee related costs, coupled with one time professional fees incurred in the period.
• The Company incurred a net loss of $32.5 million for the nine months ended September 30, 2017 ($0.44 per basic common share) as compared to a net loss of $47.5 million for the same period in 2016 ($0.64 per basic common share). The decrease in net loss can be attributed to the following:
• A $23.3 million increase in Adjusted EBITDA due to higher utilization in both the contract drilling and production services segments, and increased shortfall commitment revenue;
• A prior period loss on asset decommissioning of $5.2 million in the contract drilling segment;
• A $1.7 million decrease in stock based compensation expense, due to a greater portion of the Company's outstanding stock options and restricted share units being fully vested in the period; and
• A $0.7 million decrease in finance costs mainly due to the Company reducing its available Credit Facilities in 2016 from $195.0 million to $60.0 million, resulting in lower standby fees

Offsetting the above mentioned items are the following:

• An increase of $7.4 million in depreciation expense due to the Company changing from unit of production to straight line depreciation for drilling and well servicing rigs effective April 1, 2016;
• A $3.5 million increase in other items, as the first quarter of 2016 included foreign exchange gains of $2.5 million, while the first quarter of 2017 included $1.6 million in transaction costs related to the unsuccessful acquisition of Savanna Energy Services Corp. ("Savanna"); and
• A $5.1 million decrease in income tax recovery due to improved earnings before taxes.
• Year to date capital expenditures of $12.2 million included $6.4 million of expansion capital and $5.8 million of maintenance capital. In total, capital spending for the nine months ended September 30, 2017 increased by $10.2 million from the $2.0 million incurred in the same period of 2016. The Company incurred expansion capital mainly related to drilling rig upgrades in the nine months ended September 30, 2017, which have contributed to the increase in cash flow from operating activities year to date, as well as necessary maintenance capital related to the higher activity in the period.

Selected Financial Information
(stated in thousands, except share and per share amounts)
		Three months ended Sept 30			Nine months ended Sept 30
Financial Highlights		2017	2016	Change	2017	2016	Change
Revenue		54,131	32,485	67%	171,660	79,312	116%
Operating Revenue^(1)		51,111	30,665	67%	159,733	75,258	112%
Gross Margin^(1)		12,299	5,685	116%	42,424	17,255	146%
Gross Margin as a percentage of Operating Revenue		24%	19%	26%	27%	23%	17%
Adjusted EBITDA^(1)		6,882	896	668%	25,628	2,269	1,029%
Adjusted EBITDA as a percentage of Operating Revenue		13%	3%	333%	16%	3%	433%
Cash flow from operating activities		1,609	909	77%	25,441	17,958	42%
Capital expenditures		6,349	651	875%	12,220	1,995	513%
Net loss		(11,478)	(16,973)	(32%)	(32,471)	(47,464)	(32%)
	-basic net loss per share	(0.16)	(0.23)	(30%)	(0.44)	(0.64)	(31%)
	-diluted net loss per share	(0.16)	(0.23)	(30%)	(0.44)	(0.64)	(31%)
Weighted average number of shares
	-basic	73,877,203	73,722,144	-	73,823,970	73,672,389	-
	-diluted	73,877,203	73,722,144	-	73,823,970	73,672,389	-
Outstanding common shares as at period end		73,974,594	73,795,266	-	73,974,594	73,795,266	-
(1) See "Non-IFRS measures" included in this press release.
		Three months ended Sept 30			Nine months ended Sept 30
Operating Highlights^(1)		2017	2016	Change	2017	2016	Change
Contract Drilling
Canadian Operations:
Contract drilling rig fleet:
	-Average active rig count	20.2	11.4	77%	20.3	8.0	154%
	-End of period	51	51	-	51	51	-
Operating Revenue per Billable Day		16,825	15,256	10%	17,109^(3)	17,206^(4)	(1%)
Operating Revenue per Operating Day		18,604	17,017	9%	18,862^(3)	19,224^(4)	(2%)
Operating Days		1,681	940	79%	5,027	1,959	157%
Drilling rig utilization - Billable Days		40%	22%	82%	40%	15%	167%
Drilling rig utilization - Operating Days		36%	20%	80%	36%	14%	157%
CAODC industry average utilization^(2)		29%	17%	71%	29%	15%	93%
United States Operations:
Contract drilling rig fleet:
	-Average active rig count	3.3	1.8	83%	2.8	1.3	115%
	-End of period	5	5	-	5	5	-
Operating Revenue per Billable Day (US$)		19,801	18,967	4%	19,763	22,515	(12%)
Operating Revenue per Operating Day (US$)		21,832	22,246	(2%)	22,850	25,923	(12%)
Operating Days		272	145	88%	656	306	114%
Drilling rig utilization - Billable Days		65%	37%	76%	56%	26%	115%
Drilling rig utilization - Operating Days		59%	32%	84%	48%	22%	118%
Production Services
Well servicing rig fleet:
	-Average active rig count	17.7	15.6	13%	17.3	11.4	52%
	-End of period	66	66	-	66	66	-
Service rig Operating Revenue per Service Hour		629	603	4%	661	646	2%
Service Hours		16,328	14,335	14%	47,296	31,123	52%
Service rig utilization		27%	24%	13%	26%	17%	53%

(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 nine months ended September 30, 2017.
(4)	Excludes shortfall commitment revenue from take or pay contracts of $1.8 million for the nine months ended September 30, 2016.

Financial Position at (stated in thousands)		September 30, 2017	December 31, 2016	September 30, 2016
Working capital		46,184	51,118	55,259
Property and equipment		663,542	708,567	720,554
Total assets		737,385	793,525	794,170
Long term debt		264,958	264,070	264,118

Western is an oilfield service company focused on three core business lines: contract drilling, well servicing and oilfield rental equipment services.  Western provides contract drilling services through its division, Horizon Drilling ("Horizon") in Canada, and its wholly owned subsidiary, Stoneham Drilling Corporation ("Stoneham") in the United States ("US").  Western provides well servicing and oilfield rental equipment services in Canada through its wholly owned subsidiary Western Production Services Corp. ("Western Production Services").  Western Production Services' division, Eagle Well Servicing ("Eagle") provides well servicing operations, while its division, Aero Rental Services ("Aero") provides oilfield rental equipment services.  Financial and operating results for Horizon and Stoneham are included in Western's contract drilling segment, while financial and operating results for Eagle and Aero are included in Western's production services segment.       

Western has a drilling rig fleet of 56 rigs specifically suited for drilling horizontal wells of increased complexity.  Western is currently the fifth largest drilling contractor in Canada, based on the CAODC registered rigs, with a fleet of 51 rigs operating through Horizon.  Of the Canadian fleet, 24 are classified as Cardium class rigs, 19 as Montney class rigs and eight as Duvernay class rigs.  As compared to the Cardium class rigs, the Montney class rigs have a larger hookload, while the Duvernay class rigs have the largest hookload allowing the rig to support more drill pipe downhole.  Additionally, Western has five Duvernay class triple drilling rigs deployed in the United States operating through Stoneham.  Western is also the sixth 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.  West Texas Intermediate ("WTI") on average was relatively constant in the third quarter of 2017 as compared to the second quarter of 2017, however was 7% higher compared to the same period in the prior year.  For Western's Canadian customers, the impact of foreign exchange rates when translating WTI into the Canadian equivalent, resulted in only a 3% increase for the three months ended September 30, 2017, as compared to the same period in the prior year.  Additionally, in the third quarter of 2017, Western Canadian Select ("WCS") on average declined by 1% as compared to the second quarter of 2017, however improved by 18% as compared to the same period of the prior year.  For the nine months ended September 30, 2017, WTI was 19% higher than the same period of the prior year.  Similarly, WCS also improved for the nine months ended September 30, 2017, increasing by 34% as compared to the nine months ended September 30, 2016.   Canadian natural gas prices, such as AECO, declined quarter over quarter, decreasing on average by 41% from the second quarter of 2017 to the third quarter of 2017.  Further, AECO decreased in the third quarter of 2017 as compared to the same period of the prior year, decreasing by 31%, however for the nine month period ending September 30, 2017 AECO improved by 29% as compared to the same period in the prior year.  The following table summarizes average crude oil and natural gas prices, as well as average foreign exchange rates for the three and nine months ended September 30, 2017 and 2016.

			Three months ended Sept 30				Nine months ended Sept 30
			2017	2016	Change		2017	2016	Change
Average crude oil and natural gas prices^(1)(2)
Crude Oil
West Texas Intermediate (US$/bbl)			48.16	44.88	7%		49.32	41.44	19%
Western Canadian Select (CDN$/bbl)			47.27	40.00	18%		49.62	37.09	34%
Natural Gas
30 day Spot AECO (CDN$/mcf)			1.65	2.38	(31%)		2.40	1.86	29%
Average foreign exchange rates^(2)
US dollar to Canadian dollar			1.25	1.30	(4%)		1.31	1.32	(1%)

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

Improved commodity prices in 2017 has led to a corresponding increase in the demand for oilfield services in both Canada and the United States.  The CAODC reported that for drilling in Canada, the total number of Operating Days in the Western Canadian Sedimentary Basin ("WCSB") increased approximately 41% and 72% for the three and nine months ended September 30, 2017 respectively, as compared to the same periods in the prior year.  Similarly, as reported by Baker Hughes, a GE Company, the number of active drilling rigs in the United States increased approximately 97% and 77% for the three and nine months ended September 30, 2017 respectively, as compared to the same periods in the prior year.

Outlook

Currently, 22 of Western's drilling rigs are operating.  Five of Western's 56 drilling rigs (or 9%) are under long term take or pay contracts, with two expected to expire in 2018, two expected to expire in 2019 and one expected to expire in 2020.  These contracts each typically generate between 250 and 350 Billable Days per year.

Western's capital budget for 2017 remains unchanged and totals approximately $20 million comprised of $8 million in expansion capital and $12 million in maintenance capital.  The majority of the capital budget relates to expansion capital in the contract drilling segment related to drilling rig upgrades that offer compelling economics.  Western believes the revised 2017 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 any required adjustments to its capital program as customer demand changes.  Approximately $2 million from the revised 2017 capital budget is expected to be carried forward into 2018.

Since hitting 10 year lows in the first quarter of 2016, commodity prices, while remaining well below previous highs, have improved.  As such, North American drilling rig counts have begun to recover and the Company is expecting increased year over year activity levels throughout the remainder of 2017.  However, improved pricing for the Company's services has lagged the recovery in activity and is expected to occur gradually as rates are typically increased for rigs and drilling programs on an individual basis rather than universally.  Improving gross margin is a priority for the Company and, as has been demonstrated over the last two quarters, Western is working to implement higher rates with each rig that is awarded work.  Prices for Western's services below historical levels will continue to impact Adjusted EBITDA and cash flow from operating activities in the near term.  However, Western's variable cost structure and a prudent capital budget will aid in preserving balance sheet strength.  In addition to $39.6 million in cash and cash equivalents at September 30, 2017, Western currently has $80.0 million of available credit under its undrawn amended Credit Facilities, which do not mature until December 17, 2020.  Additionally, Western plans to repay the Senior Notes in the first quarter of 2018 with proceeds from the Second Lien Facility, Private Placement and the Bought Deal completed subsequent to September 30, 2017, along with cash on hand and funds available under the Credit Facilities.  Completing these financing transactions will lower Western's total debt and leverage metrics, decrease Western's effective interest rates and extend the maturity on all of Western's long term debt.  Additionally, Western will save approximately $5.3 million annually in cash interest expense, due to the decreased total debt level and lower interest rate on the Second Lien Facility, as compared to the existing Senior Notes. 

Oilfield service activity in Canada will be impacted by the development of resource plays in Alberta and northeast British Columbia including those related to increased crude oil transportation capacity through pipeline development, increased environmental regulations including the implementation of a carbon tax in Alberta, and decreased foreign investment into Canada.  Currently, the largest challenges facing the oilfield service industry are continued customer spending constraints as a result of lower commodity prices and the increasing challenge of staffing field crews, particularly in the well servicing division.  Western's view is 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 slowdown in oilfield service activity.

2017 Third Quarter Financial and Operating Results Conference Call and Webcast

Western has scheduled a conference call and webcast to begin promptly at 9:00 a.m. MDT (11:00 a.m. EDT) on Thursday, October 26, 2017.

The conference call dial-in number is 1-888-231-8191.

A live webcast of the conference call will be accessible on Western's website at www.wesc.ca by selecting "Investors", then "Webcasts".  Shortly after the live webcast, an archived version will be available for approximately 14 days.

An archived recording of the conference call will also be available approximately two hours after the completion of the call until November 9, 2017 by dialing 1-855-859-2056, passcode 95867128.

Non-IFRS Measures

Western uses certain measures in this press release which do not have any standardized meaning as prescribed by International Financial Reporting Standards ("IFRS").  These measures, which are derived from information reported in the condensed consolidated financial statements, may not be comparable to similar measures presented by other reporting issuers.  These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding the Company.  These Non-IFRS measures are identified and defined as follows:

Operating Revenue

Management believes that in addition to revenue, Operating Revenue is a useful supplemental measure as it provides an indication of the revenue generated by Western's principal operating activities, excluding flow through third party charges such as rig fuel, which at the customer's request may be paid for initially by Western, then recharged in its entirety to Western's customers.

Gross Margin

Management believes that in addition to net income, Gross Margin is a useful supplemental measure as it provides an indication of the results generated by Western's principal operating activities prior to considering administrative expenses, depreciation and amortization, stock based compensation, how those activities are financed, the impact of foreign exchange, how the results are taxed, how funds are invested, and how non-cash items and one-time gains and losses affect results.

The following table provides a reconciliation of revenue under IFRS, as disclosed in the condensed consolidated statements of operations and comprehensive income, to Operating Revenue and Gross Margin:

		Three months ended Sept 30			Nine months ended Sept 30
(stated in thousands)		2017	2016		2017	2016
Operating Revenue
	Drilling	38,711	20,210		120,754	49,922
	Production services	12,411	10,460		39,094	25,354
	Less: inter-company eliminations	(11)	(5)		(115)	(18)
		51,111	30,665		159,733	75,258
Third party charges		3,020	1,820		11,927	4,054
Revenue		54,131	32,485		171,660	79,312
Less: operating expenses		(58,049)	(43,601)		(178,419)	(103,904)
Add:
	Depreciation – operating	16,196	16,712		48,989	41,352
	Stock based compensation – operating	21	89		194	495
Gross Margin		12,299	5,685		42,424	17,255

Adjusted EBITDA

Management believes that in addition to net income, earnings before interest and finance costs, taxes, depreciation and amortization, other non-cash items and one-time gains and losses ("Adjusted EBITDA") is a useful supplemental measure as it provides an indication of the results generated by the Company's principal operating segments similar to Gross Margin but also factors in the cash administrative expenses incurred in the period.

Operating Earnings

Management believes that in addition to net income, Operating Earnings is a useful supplemental measure as it provides an indication of the results generated by the Company's principal operating segments similar to Adjusted EBITDA but also factors in the depreciation expense incurred in the period.

The following table provides a reconciliation of net loss under IFRS, as disclosed in the condensed consolidated statements of operations and comprehensive income, to earnings before interest and finance costs, taxes, depreciation and amortization ("EBITDA"), Adjusted EBITDA and Operating Loss:

		Three months ended Sept 30			Nine months ended Sept 30
(stated in thousands)		2017	2016		2017	2016
Net loss		(11,478)	(16,973)		(32,471)	(47,464)
Add:
	Finance costs	5,521	5,708		16,352	17,044
	Income tax recovery	(4,071)	(6,043)		(11,713)	(16,772)
	Depreciation – operating	16,196	16,712		48,989	41,352
	Depreciation – administrative	300	378		929	1,204
EBITDA		6,468	(218)		22,086	(4,636)
Add:
	Stock based compensation – operating	21	89		194	495
	Stock based compensation – administrative	158	759		1,292	2,651
	Loss on asset decommissioning	-	-		-	5,225
	Other items	235	266		2,056	(1,466)
Adjusted EBITDA		6,882	896		25,628	2,269
Subtract:
	Depreciation – operating	(16,196)	(16,712)		(48,989)	(41,352)
	Depreciation – administrative	(300)	(378)		(929)	(1,204)
Operating Loss		(9,614)	(16,194)		(24,290)	(40,287)

Net Debt

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

(stated in thousands)				September 30, 2017	December 31, 2016
Long term debt				264,958	264,070
Current portion of long term debt				500	684
Less: cash and cash equivalents				(39,576)	(44,597)
Net Debt				225,882	220,157

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 in 2017 (2016: 366 days).

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");
• West Texas Intermediate ("WTI"); and
• Western Canadian Sedimentary Basin ("WCSB").

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 such statements and disclosures, other than those of historical fact, which address activities, events, outcomes, results or developments that Western anticipates or expects may, or will occur in the future (in whole or part) should be considered forward-looking information.  In some cases forward-looking information can be identified by terms such as "forecast", "future", "may", "will", "expect", "anticipate", "believe", "potential", "enable", "plan", "continue", or other comparable terminology.

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 2017; the Company's liquidity needs including the ability of current capital resources to cover Western's financial obligations and the 2017 capital budget; the expected use of proceeds of the Second Lien Facility, Private Placement and the Bought Deal; the Company's expected sources of funding to support such capital plans and the Company's ability to adjust capital spending for the remainder of 2017 if market conditions, including customer demand changes; the expected benefits from cost control measures; the use and availability of the Company's Credit Facilities; pricing for Western's services and impact on Adjusted EBITDA; the Company's ability to maintain certain covenants under its Credit Facilities; the future declaration of dividends; expectations as to the increase in crude oil transportation capacity through pipeline development; the potential impact of changes to environmental laws and regulations and the implementation of a carbon tax in Alberta; the expectation of continued foreign investment into the Canadian crude oil and natural gas industry; expectations relating to producer spending, and the Company's ability to find and maintain enough field crew members and the Company's change to its depreciation assumptions.

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; fluctuations in the price and demand for crude oil and natural gas; the continued low levels of and pressures on commodity pricing; the continued business relationship between the Company and its significant customers; general economic and financial market conditions; crude oil transport and pipeline approval and development; the Company's ability to finance its operations; the effects of seasonal and weather conditions on operations and facilities; the competitive environment to which the various business segments are, or may be, exposed in all aspects of their business; the ability of the Company's various business segments to access equipment (including spare parts and new technologies); changes in laws or regulations; currency exchange fluctuations; the ability of the Company to attract and retain skilled labour and qualified management; the ability to retain and attract significant customers; and other unforeseen conditions which could impact the use of services supplied by Western including Western's ability to respond to such 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 the demand for oilfield services will not continue to improve for the remainder of 2017 and that commodity prices will remain low, and other general industry, economic, market and business conditions.  Readers are cautioned that the foregoing list of risks, uncertainties and assumptions are not exhaustive.  Additional information on these and other risk factors that could affect Western's operations and financial results are included in Western's annual information form which may be accessed through the SEDAR website at www.sedar.com.  The forward-looking statements and information contained in this press release are made as of the date hereof and Western does not undertake any obligation to update publicly or revise any forward-looking statements and information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

SOURCE Western Energy Services Corp.

Alex R.N. MacAusland, President and CEO, or Jeffrey K. Bowers, Senior VP Finance and CFO at 403.984.5916

Related Links

http://www.wesc.ca