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

CALGARY, July 26, 2017 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its second 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 six months ended June 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.

Second Quarter 2017 Operating Results:

  • Operating Revenue in the second quarter of 2017 benefited from improved commodity prices and resulted in higher customer spending and a corresponding increase in demand for Western's services. Second quarter Operating Revenue increased by $18.1 million (or 146%) to $30.5 million in 2017 as compared to $12.4 million in 2016, with the prior period including $1.8 million in shortfall commitment revenue. In the contract drilling segment, Operating Revenue totalled $22.8 million in the second quarter of 2017 as compared to $7.4 million in the second quarter of 2016, an increase of $15.4 million (or 208%); while in the production services segment, Operating Revenue totalled $7.7 million for the three months ended June 30, 2017 as compared to $5.0 million in the second quarter of 2016, an increase of $2.7 million (or 54%). Higher utilization in the second quarter of 2017, and improved pricing in Canada, positively 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 averaged 19% in the second quarter of 2017 compared to an average of 3% in the second quarter of 2016, reflecting a 1,600 basis points ("bps") increase. Second quarter 2017 Drilling Rig Utilization represented a premium of 100 bps to the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 18%, whereas in the second quarter of 2016, Drilling Rig Utilization of 3% represented a 400 bps discount to the industry average. The increase in the Company's utilization premium to the industry average in the second 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 second quarter of 2017, improved by 1% as compared to the first quarter of 2017 which was aided by seasonal revenue due to cold weather during the winter drilling season, and by 6% 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 46% in the second quarter of 2017, as compared to 18% in the same period of the prior year. Operating Revenue per Billable Day in the United States decreased by 20% in the second quarter of 2017 due to changes in the mix of rigs working on spot day rates versus long term contracts, as compared to the second quarter of 2016 when the Company had one rig operating on a long term legacy contract; and
    • Well servicing utilization of 14% in the second quarter of 2017 compared to 11% in the same period of the prior year. As is typical of the second quarter in Canada, utilization was restricted by road bans in place due to wet weather. Improved market conditions resulted in an 11% increase in hourly rates during the second quarter of 2017, as compared to the same period in the prior year. Improved utilization and pricing, led to a $1.7 million (or 45%) increase in well servicing Operating Revenue in the period.
  • Second quarter Adjusted EBITDA improved by $2.1 million to $0.1 million in 2017 as compared to a loss of $2.0 million in the second quarter of 2016. Normalizing the prior year for $1.8 million of shortfall commitment revenue recognized in the second quarter of 2016, Adjusted EBITDA in the second quarter of 2017 improved by $3.9 million. The year over year change in Adjusted EBITDA is due to higher activity across all divisions in 2017 and improved pricing in the Canadian market.
  • Administrative expenses, excluding depreciation and stock based compensation, decreased by 5% in the second quarter of 2017 as compared to the first quarter of 2017, as employer paid statutory source deductions decreased as employees began reaching their annual limits. Second quarter 2017 administrative expenses increased by $0.8 million (or 18%) to $5.5 million, as compared to $4.7 million in the second quarter of 2016 due to higher employee related costs, offset partially by the realization of a full period of cost control measures undertaken in the prior year.
  • The Company incurred a net loss of $16.6 million in the second quarter of 2017 ($0.23 per basic common share) as compared to a net loss of $24.2 million in the same period in 2016 ($0.33 per basic common share). The change can be attributed to the following:
    • A prior period loss on asset decommissioning of $5.2 million in the contract drilling segment;
    • A $2.1 million increase in Adjusted EBITDA due to higher utilization in both the contract drilling and production services segments, coupled with improved pricing in Canada;
    • A $1.0 million decrease in depreciation expense due to lower capital spending and certain equipment being fully depreciated in the second half of 2016 and the first half of 2017; and
    • A $0.4 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 is a $2.1 million decrease in income tax recovery due to improved earnings before taxes.
  • Second quarter 2017 capital expenditures of $3.4 million included $1.7 million of expansion capital and $1.7 million of maintenance capital. In total, capital spending in the second quarter of 2017 increased by $3.0 million from the $0.4 million incurred in the second quarter of 2016. The Company incurred expansion capital mainly related to drilling rig upgrades in the second quarter of 2017, as well as necessary maintenance capital related to the higher activity in the period.

Year to Date 2017 Operating Results:

  • Operating Revenue for the six month period ended June 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 six months ended June 30, 2017, Operating Revenue increased by $64.0 million (or 144%) to $108.6 million as compared to $44.6 million for the six months ended June 30, 2016. In the contract drilling segment, Operating Revenue totalled $82.0 million for the six months ended June 30, 2017, an increase of $52.3 million (or 176%), as compared to $29.7 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 $26.7 million, an increase of $11.8 million (or 79%) as compared to $14.9 million in the same period of the prior year. Higher utilization in the first half of 2017, as compared to the same period of the prior year, offset by lower pricing, impacted Operating Revenue in the contract drilling and production services segments as described below:
    • Drilling Rig Utilization in Canada of 36% for the six month period ended June 30, 2017, compared to 11% for the six month period ended June 30, 2016, reflecting a 2,500 bps increase. Drilling Rig Utilization of 36% in 2017 represents a 700 bps premium to the CAODC industry average, whereas in the first six months of 2016, Drilling Rig Utilization of 11% represented a 300 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 limited.
    • 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, decreased by 9% as compared to the same period in the prior year. However, pricing began to improve in the second quarter of 2017, trending higher as incremental projects were awarded, resulting in an increase of 1% over the first quarter of 2017 which was aided by seasonal revenue due to cold weather during the winter drilling season.
    • 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 42% for the six months ended June 30, 2017, as compared to 18% in the same period of the prior year. Operating Revenue per Billable Day in the United States decreased by 24% in the first six months of 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 six months ended June 30, 2017 compared to 14% in the same period of the prior year. Continued improvements in commodity prices helped improve activity year over year. Well servicing hourly rates decreased by 1% for the six months ended June 30, 2017, as compared to the six months ended June 30, 2016. However, pricing has begun to improve as activity increases resulting in improved year over year pricing in the second quarter of 2017. Improved utilization and constant pricing led to a $9.5 million (or 83%) increase in well servicing Operating Revenue in the period.
  • Adjusted EBITDA for the six months ended June 30, 2017 increased by $17.3 million to $18.7 million in 2017 as compared to $1.4 million for the six months ended June 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 partially offset by lower average pricing in both the contract drilling and production services segments.
  • Administrative expenses, excluding depreciation and stock based compensation, for the six month period ended June 30, 2017 increased by $1.2 million (or 12%) to $11.4 million as compared to $10.2 million in the same period of the prior year. The increase in administrative expenses is due to higher employee related costs, offset partially by the realization of a full period of cost control measures undertaken in the prior year.
  • The Company incurred a net loss of $21.0 million for the six months ended June 30, 2016 ($0.28 per basic common share) as compared to a net loss of $30.5 million for the same period in 2016 ($0.41 per basic common share). The decrease in net loss can be attributed to the following:
    • A $17.3 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; and
    • A $0.5 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.
  • Offsetting the above mentioned items are the following:
    • 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;
    • A $3.6 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 $3.1 million decrease in income tax recovery due to improved earnings before taxes.
  • Year to date capital expenditures of $5.9 million included $2.3 million of expansion capital and $3.6 million of maintenance capital. In total, capital spending for the six months ended June 30, 2017 increased by $4.6 million from the $1.3 million incurred in the same period of 2016. The Company incurred expansion capital mainly related to drilling rig upgrades in the first half of 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 June 30


Six months ended June 30

Financial Highlights

2017

2016

Change


2017

2016

Change

Revenue

33,307

12,890

158%


117,529

46,827

151%

Operating Revenue(1)

30,469

12,393

146%


108,622

44,593

144%

Gross Margin(1)

5,667

2,703

110%


30,125

11,570

160%

Gross Margin as a percentage of Operating Revenue

19%

22%

(14%)


28%

26%

8%

Adjusted EBITDA(1)

121

(1,990)

(106%)


18,746

1,374

1,264%

Adjusted EBITDA as a percentage of Operating Revenue

-

(16%)

(100%)


17%

3%

467%

Cash flow from operating activities

20,659

8,444

145%


23,832

17,049

40%

Capital expenditures

3,435

423

712%


5,871

1,344

337%

Net loss

(16,628)

(24,172)

(31%)


(20,993)

(30,491)

(31%)


-basic net loss per share

(0.23)

(0.33)

(30%)


(0.28)

(0.41)

(32%)


-diluted net loss per share

(0.23)

(0.33)

(30%)


(0.28)

(0.41)

(32%)

Weighted average number of shares









-basic

73,797,866

73,648,192

-


73,796,911

73,647,241

-


-diluted

73,797,866

73,648,192

-


73,796,911

73,647,241

-

Outstanding common shares as at period end

73,798,126

73,648,484

-


73,798,126

73,648,484

-

(1)  See "Non-IFRS measures" included in this press release.



Three months ended June 30


Six months ended June 30

Operating Highlights(1)

2017

2016

 Change


2017

2016

Change

Contract Drilling








Canadian Operations:








Contract drilling rig fleet:









-Average active rig count

10.3

1.8

472%


20.3

6.3

222%


-End of period

51

51

-


51

51

-

Operating Revenue per Billable Day

17,411

16,441(3)

6%


17,252(4)

19,001(3)

(9%)

Operating Revenue per Operating Day

19,009

17,369(3)

9%


18,992(4)

21,260(3)

(11%)

Operating Days

859

157

447%


3,345

1,018

229%

Drilling rig utilization - Billable Days

20%

4%

400%


40%

12%

233%

Drilling rig utilization - Operating Days

19%

3%

533%


36%

11%

227%

CAODC industry average utilization(2)

18%

7%

157%


29%

14%

107%









United States Operations:








Contract drilling rig fleet:









-Average active rig count

2.7

1.0

170%


2.5

1.0

150%


-End of period

5

5

-


5

5

-

Operating Revenue per Billable Day (US$)

19,545

24,568

(20%)


19,738

25,832

(24%)

Operating Revenue per Operating Day (US$)

23,235

27,092

(14%)


23,573

29,240

(19%)

Operating Days

208

83

151%


384

161

139%

Drilling rig utilization - Billable Days

54%

20%

170%


51%

20%

155%

Drilling rig utilization - Operating Days

46%

18%

156%


42%

18%

133%









Production Services








Well servicing rig fleet:









-Average active rig count

9.4

7.0

34%


17.1

9.2

86%


-End of period

66

66

-


66

66

-

Service Rig Operating Revenue per Service Hour

652

589

11%


678

682

(1%)

Service Hours

8,511

6,402

33%


30,968

16,788

84%

Service rig utilization

14%

11%

27%


26%

14%

86%

(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 three and six months ended June 30, 2016.

(4)

Excludes shortfall commitment revenue from take or pay contracts of $6.4 million for the six months ended June 30, 2017.

 





Financial Position at (stated in thousands)

June 30, 2017

December 31, 2016

June 30, 2016

Working capital

51,730

51,118

60,278

Property and equipment

677,465

708,567

735,765

Total assets

758,278

793,525

814,757

Long term debt

264,702

264,070

264,145

 

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.  While commodity prices regressed in the latter part of the second quarter of 2017, they still improved year over year for the three and six months ended June 30, 2017.  Overall performance of the Company for the three and six months ended June 30, 2017 was impacted by low crude oil and natural gas prices, which remain well below previous highs.  West Texas Intermediate ("WTI") on average declined by 7% in the second quarter of 2017 as compared to the first quarter of 2017, however was 6% higher compared to the same period in the prior year.  Additionally, in the second quarter of 2017, Western Canadian Select on average remained constant as compared to the first quarter of 2017, however improved by 21% as compared to the same period of the prior year.  Canadian natural gas prices, such as AECO, improved quarter over quarter, increasing on average by 3% from the first quarter of 2017 to the second quarter of 2017.  Further, AECO nearly doubled in the second quarter of 2017 as compared to the same period of the prior year, increasing by 99%.  The following table summarizes average crude oil and natural gas prices, as well as average foreign exchange rates for the three and six months ended June 30, 2017 and 2016.





Three months ended June 30

Six months ended June 30


2017

2016

Change

2017

2016

Change

Average crude oil and natural gas prices(1)(2)














Crude Oil







West Texas Intermediate (US$/bbl)

48.11

45.53

6%

49.87

39.69

26%

Western Canadian Select (CDN$/bbl)

51.35

42.31

21%

50.85

34.49

47%








Natural Gas







30 day Spot AECO (CDN$/mcf)

2.78

1.40

99%

2.74

1.61

70%








Average foreign exchange rates(2)







US dollar to Canadian dollar

1.34

1.29

4%

1.33

1.33

-


(1)

See "Abbreviations" included in this press release.

(2)

Source: Bloomberg

 

Year over year improvement in 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 142% and 91% respectively, for the three and six months ended June 30, 2017, as compared to the same periods in the prior year.  Similarly, as reported by Baker Hughes Incorporated, the number of active drilling rigs in the United States increased approximately 112% and 67% respectively, for the three and six months ended June 30, 2017, as compared to the same periods in the prior year.

Outlook

Currently, 24 of Western's drilling rigs are operating.  Four of Western's 56 drilling rigs (or 7%) are under long term take or pay contracts, with three expected to expire in 2018 and one expected to expire in 2020.  These contracts each typically generate between 250 and 350 Billable Days per year.

Western's revised capital budget for 2017 totals approximately $20 million comprised of $8 million in expansion capital and $12 million in maintenance capital.  The revised capital budget reflect a net increase of $7 million from Western's previously announced budget of $13 million.  The following table summarizes the changes in the 2017 capital budget: 





Capital Expenditures          

(stated in millions)

2017 Budget
Announced
January 9, 2017

Incremental
Approved Capital
Expenditures

Revised
2017 Budget

Expansion

2

6

8

Maintenance

11

1

12

Total Capital Expenditures

13

7

20

 

The majority of the increase in the capital budget relates to expansion capital in the contract drilling segment related to drilling rig upgrades that offer compelling economics.  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.

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 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 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 $52.6 million in cash and cash equivalents, at June 30, 2017, Western has $60.0 million undrawn on its syndicated revolving credit facility and its committed operating line (the "Credit Facilities"), which do not mature until December 17, 2018.  Additionally, Western has no principal repayments due on the $265.0 million 7⅞% senior unsecured notes (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 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 Second Quarter Financial and Operating Results Conference Call and Webcast

Western has scheduled a conference call and webcast to begin promptly at 10:00 a.m. MDT (12:00 p.m. EDT) on Thursday, July 27, 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 August 8, 2017 by dialing 1-855-859-2056, passcode 54606825.

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 June 30

Six months ended June 30

(stated in thousands)

2017

2016

2017

2016

Operating Revenue






Drilling

22,807

7,388

82,043

29,712


Production services

7,670

5,008

26,683

14,894


Less: inter-company eliminations

(8)

(3)

(104)

(13)


30,469

12,393

108,622

44,593

Third party charges

2,838

497

8,907

2,234

Revenue

33,307

12,890

117,529

46,827

Less: operating expenses

(44,128)

(27,814)

(120,370)

(60,303)

Add:






Depreciation – operating

16,412

17,329

32,793

24,640


Stock based compensation – operating

76

298

173

406

Gross Margin

5,667

2,703

30,125

11,570

 

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 June 30


Six months ended June 30

(stated in thousands)

2017

2016


2017

2016

Net loss

(16,628)

(24,172)


(20,993)

(30,491)

Add:







Finance costs

5,419

5,798


10,831

11,336


Income tax recovery

(6,154)

(8,234)


(7,642)

(10,729)


Depreciation – operating

16,412

17,329


32,793

24,640


Depreciation – administrative

307

406


629

826

EBITDA

(644)

(8,873)


15,618

(4,418)

Add:







Stock based compensation – operating

76

298


173

406


Stock based compensation – administrative

565

962


1,134

1,893


Loss on asset decommissioning

-

5,225


-

5,225

  Other items

124

398


1,821

(1,732)

Adjusted EBITDA

121

(1,990)


18,746

1,374

Subtract:







Depreciation – operating

(16,412)

(17,329)


(32,793)

(24,640)


Depreciation – administrative

(307)

(406)


(629)

(826)

Operating Loss

(16,598)

(19,725)


(14,676)

(24,092)

 

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)

June 30, 2017

December 31, 2016

Long term debt

264,702

264,070

Current portion of long term debt

527

684

Less: cash and cash equivalents

(52,649)

(44,597)

Net Debt

212,580

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 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.

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", "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; 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, 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 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.

For further information: please contact: Alex R.N. MacAusland, President and CEO; or Jeffrey K. Bowers, Senior VP Finance and CFO at 403.984.5916

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