Western Energy Services Corp. Releases Fourth Quarter and Year End 2016 Financial and Operating Results

CALGARY, ALBERTA--(Marketwired - Feb. 22, 2017) - Western Energy Services Corp. ("Western" or the "Company") (TSX:WRG) announces the release of its fourth quarter and year end 2016 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, 2016 and 2015 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 2016 Operating Results:

• Operating Revenue for the three months ended December 31, 2016 continued to be impacted by low commodity prices, which are still well below previous highs. Fourth quarter Operating Revenue increased by $1.2 million (or 3%) to $41.6 million in 2016 as compared to $40.4 million in 2015. In the contract drilling segment, Operating Revenue totalled $29.0 million in the fourth quarter of 2016 as compared to $27.0 million in the fourth quarter of 2015, an increase of 7%; while in the production services segment, Operating Revenue totalled $12.7 million for the three months ended December 31, 2016 as compared to $13.5 million in the fourth quarter of 2015, a decrease of 6%. Commodity prices began to recover in the fourth quarter of 2016, which combined with built up demand due to weather related delays in the third quarter of 2016, resulted in higher industry activity. However, higher utilization in the fourth quarter, offset by continued pricing pressure, impacted Operating Revenue in the contract drilling and production services segments as described below:
  • Drilling rig utilization - Operating Days (or "Drilling Rig Utilization") in Canada was 28% in the fourth quarter of 2016 compared to 20% in the fourth quarter of 2015, reflecting an 800 basis points ("bps") increase and the highest Drilling Rig Utilization experienced by the Company since the first quarter of 2015. Fourth quarter 2016 Drilling Rig Utilization represented a premium of 300 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 25%, whereas in the fourth quarter of 2015, Drilling Rig Utilization of 20% was the same as the industry average. The increase in the Company's utilization premium from 2015 is attributable to the efforts by the Company's marketing group to reposition the Company's rigs for existing and new customers. Despite increased activity, the highly competitive environment and commodity prices still well below previous highs, resulted in downward pricing pressure on all drilling rig classes, which reduced Operating Revenue per Revenue Day in the contract drilling segment in Canada by 24%, as compared to the fourth quarter of 2015;
  • In the United States, the Company had two drilling rigs operating during the quarter, one of which was working on a long term contract, resulting in Drilling Rig Utilization of 29% in the fourth quarter of 2016, as compared to 18% in the same period of the prior year. Operating Revenue per Revenue Day in the United States decreased by 35% in the fourth quarter of 2016 due to renegotiating the day rate, as a result of extending the term on the long term contract, coupled with pricing pressure on spot market rates; and
  • Well servicing utilization of 27% in the fourth quarter of 2016 compared to 25% in the same period of the prior year. Improvements in commodity prices, and built up demand due to weather related delays in the third quarter of 2016, helped improve activity quarter over quarter. However, pricing pressure in all areas continued and resulted in a 9% decrease in well servicing hourly rates, which led to a $0.5 million (or 5%) decrease in well servicing Operating Revenue in the period.
• Fourth quarter Adjusted EBITDA decreased by $4.1 million to $3.5 million in 2016 as compared to $7.6 million in the fourth quarter of 2015. The year over year change in Adjusted EBITDA is due to lower pricing in both the contract drilling and production services segments, offset partially by cost reduction measures, including a reduced headcount year over year, wage reductions to all employees and other cost control measures.
• Administrative expenses, excluding depreciation and stock based compensation, in the fourth quarter of 2016 decreased by $0.8 million (or 14%) to $5.0 million as compared to $5.8 million in the fourth quarter of 2015. The decrease in administrative expenses is due to a reduced employee headcount, a 10% rollback to all salaried employee wages and directors' fees implemented in the first quarter of 2016, as well as additional cost control measures.
• The Company incurred a net loss of $14.5 million in the fourth quarter of 2016 (a loss of $0.20 per basic common share) as compared to a net loss of $55.0 million in the same period in 2015 (a loss of $0.75 per basic common share). The change in the fourth quarter net loss in 2016, relative to the fourth quarter of 2015, can be attributed to the following:
  • Prior year impairment losses on property and equipment of $41.9 million and losses on asset decommissioning of $26.6 million recorded in the fourth quarter of 2015.
    
    Offsetting the above mentioned items are the following:
  • A $16.1 million decrease in income tax recovery due to the prior year impairment losses on property and equipment and losses on asset decommissioning;
  • An increase of $7.9 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; and
  • A $4.1 million decrease in Adjusted EBITDA due to lower pricing in both the contract drilling and production services segments.

• Fourth quarter 2016 capital expenditures of $2.7 million included $2.1 million of expansion capital and $0.6 million of maintenance capital. In total, capital spending in the fourth quarter of 2016 decreased by 18% from the $3.3 million incurred in the fourth quarter of 2015, as the Company deployed strategic expansion capital and incurred only necessary maintenance capital to preserve cash during the current slowdown in oilfield service activity.

2016 Operating Results:

• Operating Revenue in 2016 decreased by $99.6 million (or 46%) to $116.9 million, as compared to $216.5 million in the prior year. In the contract drilling segment, Operating Revenue totalled $78.9 million in 2016 compared to $150.2 million in the prior year; while in the production services segment, Operating Revenue totalled $38.1 million in 2016 compared to $66.6 million in the prior year. Operating Revenue in the contract drilling and production services segments for the year ended December 31, 2016 continued to be impacted by low commodity prices which resulted in decreased utilization and pricing as described below:
  • Drilling Rig Utilization in Canada of 17% for the year ended December 31, 2016, compared to 26% for the prior year, reflects a 35% decrease. Drilling Rig Utilization in 2016 was on par with the CAODC industry average of 17%, as compared to the 300 bps premium to the CAODC industry average realized in 2015. The change in the Company's utilization relative to the CAODC industry average is partially due to a number of Western's customers who typically have substantial drilling programs, significantly cutting their capital spending, particularly in the first three quarters of 2016. Additionally, changes in the industry rig mix, as competitors continue to decommission older and less competitive rigs in the Western Canadian Sedimentary Basin ("WCSB"), and add rigs that directly compete with Western's drilling rig fleet, impacts Western's relative utilization as compared to the CAODC industry average. Lower activity and increased competition resulted in downward pricing pressure on all drilling rig classes, which reduced Operating Revenue per Revenue Day in the contract drilling segment in Canada by 28% in 2016, as compared to 2015;
  • In the United States, Drilling Rig Utilization of 24% for the year ended December 31, 2016, compared to 29% in the prior year. Operating Revenue per Revenue Day in the United States decreased by 26% in 2016 due to renegotiating the day rate as a result of extending the term on a long term contract, coupled with pricing pressure on spot market rates; and
  • Well servicing utilization of 20% for the year ended December 31, 2016 compared to 30% in the prior year. Reduced activity as well as a 17% reduction in well servicing hourly rates, due to pricing pressure in all areas, resulted in a $25.1 million (or 45%) decrease in well servicing Operating Revenue in 2016.
• Adjusted EBITDA decreased by $54.7 million to $5.8 million in 2016, as compared to $60.5 million in 2015. The year over year decrease in Adjusted EBITDA is due to lower utilization and pricing in both the contract drilling and production services segments, offset by cost reduction measures, including a reduced headcount, wage reductions to all employees and other cost control measures.
• Administrative expenses in 2016, excluding depreciation and stock based compensation, decreased by $5.4 million (or 21%) to $20.0 million as compared to $25.4 million in 2015. The decrease in administrative expenses is due to a reduced employee headcount, a 10% rollback to all salaried employee wages and directors' fees implemented in the first quarter of 2016, coupled with additional cost control measures.
• As a result of the Company's review of estimated useful lives and methodology for depreciating its drilling and well service rig fleet and related equipment, effective April 1, 2016, Western changed the method for depreciating its drilling and well service rigs and related equipment from unit of production to straight line and changed certain estimates related to useful lives and salvage values. The change in depreciation methodology reflects the technological developments within the industry. The Company expects that straight line depreciation will better reflect the future economic benefit related to these assets, which are expected to depreciate over time instead of on a unit of production basis. Additionally, the change will result in idle or underutilized assets being depreciated more quickly in periods of low activity, better reflecting the cyclical nature of the oilfield service industry. These adjustments were applied prospectively and resulted in an increase of approximately $6.8 million and $28.1 million respectively, of additional depreciation expense for the three and twelve months ended December 31, 2016 over what would have been expensed had the previous assumptions using the unit of production methodology continued to be used in the periods.
• During the second quarter of 2016, the Company decommissioned one of its Cardium class drilling rigs, resulting in a loss on asset decommissioning of $5.2 million, and as a result at December 31, 2016 Horizon Drilling had a fleet of 51 drilling rigs.
• The Company incurred a net loss of $62.0 million for the year ended December 31, 2016 (a loss of $0.84 per basic common share) as compared to a net loss of $129.1 million for the year ended December 31, 2015 (a loss of $1.74 per basic common share). The change in net loss in 2016 can be attributed to the following:
  • A prior year goodwill impairment loss of $71.3 million recorded in the third quarter of 2015;
  • Prior year impairment losses on property and equipment of $41.9 million and losses on asset decommissioning of $26.6 million recorded in the fourth quarter of 2015, partially offset by losses on asset decommissioning of $5.2 million in 2016; and
  • A $9.5 million decrease in income tax expense due to lower taxable income for the year ended December 31, 2016, along with the impact of the Alberta corporate tax rate increase in 2015, which increased income tax expense in the prior period by approximately $6.0 million.
    
    Offsetting the above mentioned items are the following:
  • A $54.7 million decrease in Adjusted EBITDA due to lower utilization and pricing in both the contract drilling and production services segments;
  • An increase of $20.0 million in depreciation expense due to the Company changing from unit of production to straight line depreciation for drilling and well servicing rigs in the second quarter of 2016; and
  • A $2.1 million increase in finance costs, due to lower capitalized interest as a result of the completion of the 2014 rig build program in the prior year.

• Year to date capital expenditures of $4.7 million included $3.0 million of expansion capital and $1.7 million of maintenance capital. In total, capital spending for 2016 decreased by 86% from the $33.6 million incurred in 2015, as the Company deployed strategic expansion capital and incurred only necessary maintenance capital to preserve cash during the current slowdown in oilfield service activity.
• On April 27, 2016, the Company amended the covenants and elected to reduce its syndicated revolving credit facility (the "Revolving Facility") from $175.0 million to $40.0 million and reduced its previously uncommitted operating demand revolving loan of $20.0 million to a committed operating line (the "Operating Facility") totalling $10.0 million. Western's decision to reduce its Revolving and Operating Facilities (the "Credit Facilities") is estimated to save the Company $1.5 million in standby fees annually. On July 25, 2016, the Company added a lender to its syndicated Revolving Facility and increased the amount available by $10.0 million to $50.0 million, from $40.0 million previously.

Selected Financial Information
(stated in thousands, except share and per share amounts)
		Three months ended December 31			Year ended December 31
Financial Highlights		2016	2015	Change	2016	2015	Change
Revenue		45,126	42,678	6%	124,438	227,524	(45%)
Operating Revenue(1)		41,649	40,458	3%	116,907	216,485	(46%)
Gross Margin(1)		8,507	13,372	(36%)	25,762	85,951	(70%)
Gross Margin as a percentage of Operating Revenue		20%	33%	(39%)	22%	40%	(45%)
Adjusted EBITDA(1)		3,506	7,573	(54%)	5,775	60,545	(90%)
Adjusted EBITDA as a percentage of Operating Revenue		8%	19%	(58%)	5%	28%	(82%)
Cash flow from operating activities		(1,327)	11,139	(112%)	16,631	90,955	(82%)
Capital expenditures		2,724	3,259	(16%)	4,719	33,562	(86%)
Net loss		(14,509)	(55,010)	(74%)	(61,973)	(129,139)	(52%)
	-basic net loss per share	(0.20)	(0.75)	(73%)	(0.84)	(1.74)	(52%)
	-diluted net loss per share	(0.20)	(0.75)	(73%)	(0.84)	(1.74)	(52%)
Weighted average number of shares
	-basic	73,795,896	73,655,198	-	73,703,437	74,238,320	(1%)
	-diluted	73,795,896	73,655,198	-	73,703,437	74,238,320	(1%)
Outstanding common shares as at period end		73,795,944	73,646,292	-	73,795,944	73,646,292	-
Dividends declared		-	3,682	(100%)	-	20,392	(100%)
(1) See "Non-IFRS measures" included in this press release.
		Three months ended December 31			Year ended December 31
Operating Highlights		2016	2015	Change	2016	2015	Change
Contract Drilling
Canadian Operations:
Contract drilling rig fleet:
-Average active rig count(1)		16.2	11.4	42%	10.0	14.3	(30%)
-End of period		51	52	(2%)	51	52	(2%)
Operating Revenue per Revenue Day(1)		16,657	22,038	(24%)	16,984(3)	23,458	(28%)
Operating Revenue per Operating Day(1)		18,811	24,228	(22%)	19,058(3)	25,821	(26%)
Operating Days(1)		1,317	955	38%	3,276	4,748	(31%)
Drilling rig utilization - Revenue Days(1)		32%	22%	45%	20%	29%	(31%)
Drilling rig utilization - Operating Days(1)		28%	20%	40%	17%	26%	(35%)
CAODC industry average utilization(1) (2)		25%	20%	25%	17%	23%	(26%)
United States Operations:
Contract drilling rig fleet:
-Average active rig count(1)		1.7	1.0	70%	1.4	1.6	(13%)
-End of period		5	5	-	5	5	-
Operating Revenue per Revenue Day (US$)(1)		20,197	31,350	(36%)	21,805	29,483(4)	(26%)
Operating Revenue per Operating Day (US$)(1)		23,440	34,217	(31%)	25,166	33,166(4)	(24%)
Operating Days(1)		134	84	60%	440	526	(16%)
Drilling rig utilization - Revenue Days(1)		34%	20%	70%	28%	32%	(13%)
Drilling rig utilization - Operating Days(1)		29%	18%	61%	24%	29%	(17%)
Production Services
Well servicing rig fleet:
-Average active rig count(1)		17.6	16.7	5%	12.9	19.5	(34%)
-End of period		66	66	-	66	66	-
Service Rig Operating Revenue per Service Hour(1)		638	703	(9%)	643	779	(17%)
Service Hours(1)		16,182	15,352	5%	47,305	71,225	(34%)
Service rig utilization(1)		27%	25%	8%	20%	30%	(33%)
(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 $1.8 million for the year ended December 31, 2016.
(4) Excludes shortfall commitment and standby revenue from take or pay contracts of US$4.5 million for the year ended December 31, 2015.

Financial Position at (stated in thousands)	December 31, 2016	December 31, 2015	Change
Working capital	51,118	70,679	(28%)
Property and equipment	708,567	773,647	(8%)
Total assets	793,525	876,608	(9%)
Long term debt	264,070	264,155	-

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"). On December 28, 2015, Western wound up its partnership, Western Energy Services Partnership (the "Partnership"), and rolled all of the Partnership's assets into IROC Drilling and Production Services Corp., which then changed its name to Western Production Services Corp. ("Western Production Services"). As a result, Western now provides well servicing operations in Canada through Western Production Services' division, Eagle Well Servicing ("Eagle") and oilfield rental equipment services in Canada through Western Production Services' division, Aero Rental Services ("Aero"). Financial and operating results for Horizon and Stoneham are included in Western's contract drilling segment, while Eagle and Aero's financial and operating results 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 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 classified 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 third largest well servicing company in Canada, based on CAODC registered rigs, 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. While commodity prices improved in the fourth quarter of 2016, they were still well below previous highs and overall performance of the Company throughout 2016 was impacted by the continued low crude oil and natural gas price environment. West Texas Intermediate ("WTI") on average improved in the fourth quarter of 2016 as compared to the third quarter of 2016, increasing by 10%, and was 17% higher compared to the same period in the prior year. However, for the year ended December 31, 2016, WTI on average was 11% lower than 2015. Canadian natural gas prices, such as AECO, improved quarter over quarter, increasing on average by 31% from the third quarter of 2016 to the fourth quarter of 2016. For the three months ended December 31, 2016, AECO increased on average by 25% as compared to the same period in the prior year, however remained 20% lower for the year ended December 31, 2016, as compared to 2015. 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, 2016 and 2015 and for the years ended December 31, 2016 and 2015.

	Three months ended December 31			Year ended December 31
	2016	2015	Change	2016	2015	Change
Average crude oil and natural gas prices(1)(2)
Crude Oil
West Texas Intermediate (US$/bbl)	49.16	42.18	17%	43.37	48.80	(11%)
Western Canadian Select (CDN$/bbl)	45.84	36.86	24%	39.27	44.83	(12%)
Natural Gas
30 day Spot AECO (CDN$/mcf)	3.11	2.48	25%	2.18	2.71	(20%)
Average foreign exchange rates(2)
US dollar to Canadian dollar	1.33	1.34	(1%)	1.32	1.28	3%
(1) See "Abbreviations" included in this press release.
(2) Source: Bloomberg

The significant reduction in commodity prices has led to a corresponding decrease 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 WCSB decreased approximately 31% in 2016, as compared to 2015. Similarly, as reported by Baker Hughes Incorporated, the number of active drilling rigs in the United States decreased approximately 51% in 2016, as compared to 2015.

Outlook

Currently, 34 of Western's drilling rigs are operating and four of Western's 56 drilling rigs (or 7%) are under long term take or pay contracts, with two of these contracts expected to expire in 2017, and two expected to expire in 2018. These contracts each typically generate between 250 and 350 Revenue Days per year.

Western's capital budget for 2017 is expected to total $13 million, with $2 million allocated for expansion capital and $11 million for maintenance capital. Western believes the 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. The following table summarizes the capital spending incurred in 2016 and the total 2017 capital budget:

Capital Expenditures (stated in millions)	Revised 2016 Budget Announced February 25, 2016	Incremental Approved Capital Expenditures	Capital Expenditures Year Ended December 31, 2016	Cancellations 2016		Carry Forward Capital Spending 2017	Budgeted Capital Expenditures Year Ended December 31, 2017	Total 2017 Budget
Expansion	2	2	(3)	-		1	1	2
Maintenance	5	1	(2)	(3)		1	10	11
Total Capital Expenditures	7	3	(5)	(3)		2	11	13

Since hitting 10 year lows in the first quarter of 2016, commodity prices, while remaining well below previous highs, have improved significantly, particularly during the fourth quarter of 2016. As such, North American drilling rig counts have begun to recover and the Company is expecting increased year over year activity levels in 2017. However, improved pricing for the Company's services is expected to lag the recovery in activity. Improving gross margin is a priority for the Company, as the worst of the downturn in crude oil and natural gas prices appears to have past. Low prices for Western's services 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 $44.6 million in cash and cash equivalents at December 31, 2016, Western has $60.0 million undrawn on the Company's Credit Facilities, which do not mature until December 17, 2018 and no principal repayments due on the Senior Notes until they mature on January 30, 2019.

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 foreign investment into Canada. Currently, the largest challenges facing the oilfield service industry are 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.

2016 Fourth Quarter and Year End Results Conference Call and Webcast

Western has scheduled a conference call and webcast to begin at 10:00 a.m. MST (12:00 p.m. EST) on Thursday, February 23, 2017. The conference call dial-in number is 1-800-769-8320.

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 one hour after the completion of the call until March 9, 2017 by dialing 1-800-408-3053 or 905-694-9451, passcode 5621414.

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 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, 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 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)		2016	2015	2016	2015
Operating Revenue
	Drilling	28,965	26,978	78,887	150,252
	Production services	12,710	13,525	38,064	66,550
	Less: inter-company eliminations	(26)	(45)	(44)	(317)
		41,649	40,458	116,907	216,485
Third party charges		3,477	2,220	7,531	11,039
Revenue		45,126	42,678	124,438	227,524
Less: operating expenses		(53,308)	(37,974)	(157,212)	(179,843)
Add:
	Depreciation - operating	16,551	8,433	57,903	37,473
	Stock based compensation - operating	138	235	633	797
Gross Margin		8,507	13,372	25,762	85,951

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 income 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 Earnings (Loss):

		Three months ended December 31		Year ended December 31
(stated in thousands)		2016	2015	2016	2015
Net loss		(14,509)	(55,010)	(61,973)	(129,139)
Add:
	Finance costs	5,478	5,412	22,522	20,441
	Income tax recovery	(5,183)	(21,273)	(21,955)	(12,548)
	Depreciation - operating	16,551	8,433	57,903	37,473
	Depreciation - administrative	365	616	1,569	1,994
EBITDA		2,702	(61,822)	(1,934)	(81,779)
Add:
	Stock based compensation - operating	138	235	633	797
	Stock based compensation - administrative	484	921	3,135	3,520
	Impairment of goodwill	-	-	-	71,256
	Impairment of property and equipment	-	41,862	-	41,862
	Loss on asset decommissioning	265	26,598	5,490	26,598
	Other items	(83)	(221)	(1,549)	(1,709)
Adjusted EBITDA		3,506	7,573	5,775	60,545
Subtract:
	Depreciation - operating	(16,551)	(8,433)	(57,903)	(37,473)
	Depreciation - administrative	(365)	(616)	(1,569)	(1,994)
Operating Earnings (Loss)		(13,410)	(1,476)	(53,697)	21,078

Net 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, 2016	December 31, 2015
Long term debt	264,070	264,155
Current portion of long term debt	684	761
Less: cash and cash equivalents	(44,597)	(58,445)
Net Debt	220,157	206,471

Defined Terms:

Average active rig count (contract drilling): Calculated as drilling rig utilization - Revenue Days multiplied by the average number of drilling rigs in the Company's fleet for the quarter or year.

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 quarter or year.

Drilling rig utilization - Operating Days (or "Drilling Rig Utilization"): Calculated based on Operating Days divided by total available days.

Drilling rig utilization - Revenue Days: Calculated based on Revenue Days divided by total available days.

Operating Days: Defined as contract drilling days, calculated on a spud to rig release basis. Revenue Days: Defined as Operating Days plus rig mobilization days.

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, 366 days per year in 2016 (2015: 365 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", "contemplate", "pro forma", 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 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; the Company's ability to maintain certain covenants under its Credit Facility; the future declaration of dividends; expectations as to the increase in crude oil transportation capacity through pipeline development; changes to environmental laws and regulations; the implementation of a carbon tax in Alberta; the expectation of continued foreign investment into the Canadian crude oil and natural gas industry; the expectation that producer spending constraints, and finding and maintaining enough field crew members will continue to be large challenges facing the Company in 2017 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, including but not limited to the ability to refinance its Senior Notes; 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 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.