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Western Energy Services Corp. Releases Second Quarter 2018 Financial and Operating Results

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Western Energy Services Corp. Releases Second Quarter 2018 Financial and Operating Results

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CALGARY, July 25, 2018 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX:WRG) announces the release of its second quarter 2018 financial and operating results.  Additional information relating to the Company, including the Company's financial statements and management's discussion and analysis as at and for the three and six months ended June 30, 2018 and 2017 will be available on SEDAR at www.sedar.com.  Non-International Financial Reporting Standards ("Non-IFRS") measures and abbreviations for standard industry terms are included in this press release.  All amounts are denominated in Canadian dollars (CDN$) unless otherwise identified.

Second Quarter 2018 Operating Results:

  • Second quarter Operating Revenue improved by $0.5 million to $31.0 million in 2018 as compared to $30.5 million in 2017. In the contract drilling segment, Operating Revenue totalled $21.8 million in the second quarter of 2018, a decrease of $1.0 million (or 4%) as compared to $22.8 million in the second quarter of 2017, while in the production services segment, Operating Revenue totalled $9.2 million for the three months ended June 30, 2018, as compared to $7.7 million in the three months ended June 30, 2017, an increase of $1.5 million (or 20%). While activity was lower in the contract drilling segment, improved pricing in all divisions, as well as higher utilization in the production services segment impacted Operating Revenue as described below:
    • Drilling rig utilization – Operating Days ("Drilling Rig Utilization") in Canada averaged 17% in the second quarter of 2018 compared to an average of 19% in the second quarter of 2017, reflecting a 200 basis points ("bps") decrease. The decrease in activity is attributable to some of Western's customers deferring their drilling programs in the second quarter of 2018 to the latter half of 2018. Second quarter 2018 Drilling Rig Utilization of 17% was consistent with the Canadian Association of Oilwell Drilling Contractors ("CAODC") industry average of 17%, whereas in the second quarter of 2017, Drilling Rig Utilization of 19% represented a premium of 100 bps to the industry average. The decrease in the Company's utilization premium to the industry average in the second quarter of 2018 is a function of a smaller industry rig fleet, as rigs continue to be decommissioned or moved out of the Western Canadian Sedimentary Basin ("WCSB"). Western's market share, represented by the Company's Operating Days as a percentage of the CAODC's total Operating Days in the WCSB, remained relatively consistent at 8.0% in the second quarter of 2018, as compared to 8.4% in the second quarter of 2017. While utilization decreased during the quarter, pricing continued to increase and resulted in a 12% improvement in Operating Revenue per Billable Day in the second quarter of 2018, as compared to the same period in the prior year. The increase in pricing is a result of the Company being successful in steadily raising rates over the last twelve months as the energy industry continues to recover from a multi-year downturn;
    • In the United States, two of the Company's six drilling rigs operated throughout the quarter on long term contracts, resulting in Drilling Rig Utilization of 30% in the second quarter of 2018, as compared to 46% in the same period of the prior year. The decrease in Drilling Rig Utilization is mainly due to one rig being out of service during the second quarter of 2018 as upgrades were completed. This rig began work near the end of the second quarter of 2018 on a long term contract. Operating Revenue per Billable Day improved during the second quarter of 2018 by 17% as compared to the second quarter of 2017, mainly due to changes in the average rig mix, higher day rates and standby revenue earned during the quarter on a third drilling rig that began operating on a long term contract near the end of the second quarter; and
    • Well servicing utilization was 16% in the second quarter of 2018 compared to 14% in the same period of the prior year, due to increased demand in a number of areas where the Company operates. Hourly rates improved during the second quarter of 2018, increasing by 11% as compared to the same period in the prior year, due to the Company actively increasing hourly rates and changes in the average rig mix. Higher utilization and improved pricing, led to a $1.4 million (or 25%) increase in well servicing Operating Revenue in the period.
  • Second quarter Adjusted EBITDA increased by $0.8 million (or 641%) to $0.9 million in the second quarter of 2018 as compared to $0.1 million in the second quarter of 2017. The year over year change in Adjusted EBITDA is due to improved pricing in all divisions, as well as higher well servicing activity, which was partially offset by lower Drilling Rig Utilization.
  • Administrative expenses, excluding depreciation and stock based compensation, decreased by $0.8 million (or 15%) to $4.7 million, as compared to $5.5 million in the second quarter of 2017, mainly due to lower employee related costs.
  • The Company incurred a net loss of $15.5 million in the second quarter of 2018 ($0.17 per basic common share) as compared to a net loss of $16.6 million in the same period in 2017 ($0.23 per basic common share). The change can be attributed to the following:
    • A $0.9 million decrease in finance costs, due to lower total debt levels;
    • A $0.8 million increase in Adjusted EBITDA, mainly due to improved pricing in all divisions;
    • A $0.2 million decrease in stock based compensation expense as fewer unvested stock options and equity settled restricted share units were outstanding in the quarter; and
    • A $0.1 million positive change in other items, which include gains and losses on foreign exchange and asset sales.

Offsetting the above mentioned items was a $1.0 million decrease in income tax recovery due to improved earnings before taxes.

  • Second quarter 2018 capital expenditures of $5.4 million included $3.8 million of expansion capital and $1.6 million of maintenance capital. In total, capital spending in the second quarter of 2018 increased by $2.0 million from the $3.4 million incurred in the second quarter of 2017. The Company incurred expansion capital mainly related to drilling rig upgrades, as well as required maintenance capital, in the second quarter of 2018.

Year to Date 2018 Operating Results:

  • Operating Revenue for the six month period ended June 30, 2018 decreased by $4.7 million (or 4%) to $103.9 million as compared to $108.6 million for the six month period ended June 30, 2017. However, after normalizing for $6.4 million of shortfall commitment revenue recognized in the first quarter of 2017, Operating Revenue for the six months ended June 30, 2018 improved by $1.7 million (or 2%). In the contract drilling segment, Operating Revenue totalled $79.1 million for the six months ended June 30, 2018, which after normalizing for $6.4 million of shortfall commitment revenue recognized in 2017, resulted in Operating Revenue improving by $3.5 million (or 5%). In the production services segment, Operating Revenue totalled $25.0 million for the six months ended June 30, 2018, as compared to $26.7 million in the same period of the prior year, a decrease of $1.7 million (or 6%). While on a year to date basis activity was lower in Canada, pricing in all divisions improved which impacted Operating Revenue as described below:
    • Drilling Rig Utilization in Canada for the six month period ended June 30, 2018 averaged 34%, compared to an average of 36% for the six month period ended June 30, 2017, reflecting a 200 bps decrease. The decrease in activity in the first half of 2018 is due to some of Western's customers ending their winter drilling programs early and deferring their drilling plans to later in 2018. Drilling Rig Utilization of 34% in 2018 represented a premium of 500 bps to the CAODC industry average of 29%, whereas in the first six months of 2017, Drilling Rig Utilization of 36% represented a 700 bps premium to the industry average. The decrease in the Company's utilization premium to the industry average in 2018 is a function of a smaller industry rig fleet, as rigs continue to be decommissioned or moved out of the WCSB. Western's market share, represented by the Company's Operating Days as a percentage of the CAODC's total Operating Days in the WCSB, remained relatively consistent at 9.6% in the first half of 2018, as compared to 10.0% in the first half of 2017. While utilization decreased during the six months ended June 30, 2018, pricing continued to increase and resulted in an 11% improvement in Operating Revenue per Billable Day in 2018, as compared to the same period in the prior year. The increase in pricing is due to changes in the average rig mix and the Company steadily raising rates over the last twelve months, as the energy industry continues to recover from a multi-year downturn;
    • In the United States, four of the Company's six drilling rigs operated during the period, two of which were working throughout the period on long term contracts, resulting in Operating Days increasing by 15% for the six months ended June 30, 2018, as compared to the same period in the prior year. While activity increased, Drilling Rig Utilization decreased to 40% for the six months ended June 30, 2018, as compared to 42% in the same period of the prior year, due to an increased rig fleet as a Cardium class drilling rig from the Canadian fleet was transferred to the United States fleet in late 2017. Operating Revenue per Billable Day in the United States improved by 7% in the first six months of 2018, as compared to the same period of the prior year, as the Company has been able to raise day rates as commodity prices improve in the United States. Additionally, day rates were aided by standby revenue earned in the second quarter of 2018 on a third drilling rig that began operating on a long term contract near the end of the second quarter; and
    • Well servicing utilization of 23% for the six months ended June 30, 2018 compared to 26% in the same period of the prior year, due to customers deferring work amid widening crude oil differentials in the first quarter of 2018, as activity in the second quarter improved year over year. Hourly rates improved for the six months ended June 30, 2018, increasing by 5% as compared to the same period in the prior year, due to changes in the average rig mix and the Company working to increase rates across all areas. Lower utilization, partially offset by improved pricing, led to a $1.1 million (or 5%) decrease in well servicing Operating Revenue in 2018.
  • Adjusted EBITDA for the six months ended June 30, 2018 decreased by $2.7 million (or 15%) to $16.0 million as compared to $18.7 million for the six months ended June 30, 2017. However, after normalizing for the $6.4 million in shortfall commitment revenue recognized in the first quarter of 2017, Adjusted EBITDA improved by $3.7 million (or 30%), as compared to the same period in the prior year. The year over year change in Adjusted EBITDA is due to improved pricing in all divisions and increased activity in the United States, offset by decreased activity in Canada and lower shortfall commitment revenue.
  • Administrative expenses, excluding depreciation and stock based compensation, for the six month period ended June 30, 2018 decreased by $1.6 million (or 14%) to $9.8 million, as compared to $11.4 million in the same period of the prior year, mainly due to lower employee related costs.
  • The Company incurred a net loss of $21.4 million for the six months ended June 30, 2018 ($0.23 per basic common share) as compared to a net loss of $21.0 million in the same period in 2017 ($0.28 per basic common share). The change can be attributed to the following:
    • A $2.7 million decrease in Adjusted EBITDA, mainly due to lower shortfall commitment revenue and decreased activity in Canada, partially offset by improved pricing in all divisions and increased activity in the United States; and
    • A $1.2 million decrease in income tax recovery due to improved earnings before taxes.

Offsetting the above mentioned items was:

    • A $1.9 million positive change in other items, of which $1.6 million related to transaction costs incurred in the prior period, coupled with gains and losses on foreign exchange and asset sales;
    • A $0.9 decrease in finance costs, due to lower total debt levels; and
    • A $0.5 million decrease in stock based compensation expense as fewer unvested stock options and equity settled restricted share units were outstanding in the quarter.
  • Year to date capital expenditures of $10.1 million included $5.6 million of expansion capital and $4.5 million of maintenance capital. In total, capital spending for the six months ended June 30, 2018 increased by $4.2 million from the $5.9 million incurred in the same period of the prior year. The Company incurred expansion capital mainly related to drilling rig upgrades, as well as required maintenance capital, in 2018.
  • On January 31, 2018, the Company completed the one time draw of $215.0 million on its 7.25% second lien secured term loan facility (the "Second Lien Facility"). The proceeds from the Second Lien Facility draw, along with cash on hand and funds available under the $70.0 million syndicated revolving credit facility (the "Revolving Facility") and the $10.0 million committed operating facility (the "Operating Facility" and together the "Credit Facilities") were used to redeem the $265.0 million 7⅞% senior unsecured notes (the "Senior Notes") at their par value of $265.0 million on February 1, 2018.

 

Selected Financial Information








(stated in thousands, except share and per share amounts)








Three months ended June 30


Six months ended June 30

Financial Highlights

2018

2017

   Change


2018

2017

Change

Revenue

33,141

33,307

-


114,398

117,529

(3%)

Operating Revenue(1)

30,976

30,469

2%


103,941

108,622

(4%)

Gross Margin(1)

5,562

5,667

(2%)


25,833

30,125

(14%)

Gross Margin as a percentage of Operating Revenue

18%

19%

(5%)


25%

28%

(11%)

Adjusted EBITDA(1)

897

121

641%


16,009

18,746

(15%)

Adjusted EBITDA as a percentage of Operating Revenue

3%

-

100%


15%

17%

(12%)

Cash flow from operating activities

26,313

20,659

27%


30,177

23,832

27%

Capital expenditures

5,426

3,435

58%


10,082

5,871

72%

Net loss

(15,475)

(16,628)

(7%)


(21,422)

(20,993)

2%


-basic net loss per share                 

(0.17)

(0.23)

(26%)


(0.23)

(0.28)

(18%)


-diluted net loss per share

(0.17)

(0.23)

(26%)


(0.23)

(0.28)

(18%)

Weighted average number of shares









-basic

92,178,383

73,797,866

25%


92,177,719

73,796,911

25%


-diluted

92,178,383

73,797,866

25%


92,177,719

73,796,911

25%

Outstanding common shares as at period end

92,179,281

73,798,126

25%


92,179,281

73,798,126

25%

(1)

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












Three months ended June 30


Six months ended June 30

Operating Highlights(1)

2018

2017

Change


2018

2017

Change

Contract Drilling








Canadian Operations:








Contract drilling rig fleet:









-Average active rig count                                 

9.2

10.3

(11%)


19.1

20.3

(6%)


-End of period

50

51

(2%)


50

51

(2%)

Operating Revenue per Billable Day

19,453

17,411

12%


19,113

17,252(3)

11%

Operating Revenue per Operating Day

21,363

19,009

12%


21,218

18,992(3)

12%

Operating Days

761

859

(11%)


3,112

3,345

(7%)

Drilling rig utilization - Billable Days

18%

20%

(10%)


38%

40%

(5%)

Drilling rig utilization - Operating Days

17%

19%

(11%)


34%

36%

(6%)

CAODC industry average utilization – Operating Days(2)

17%

18%

(6%)


29%

29%

-









United States Operations:








Contract drilling rig fleet:









-Average active rig count

2.1

2.7

(22%)


2.7

2.5

8%


-End of period

6

5

20%


6

5

20%

Operating Revenue per Billable Day (US$)

22,815

19,545

17%


21,040

19,738

7%

Operating Revenue per Operating Day (US$)

25,865

23,235

11%


23,356

23,573

(1%)

Operating Days

166

208

(20%)


440

384

15%

Drilling rig utilization - Billable Days

34%

54%

(37%)


45%

51%

(12%)

Drilling rig utilization - Operating Days

30%

46%

(35%)


40%

42%

(5%)









Production Services








Well servicing rig fleet:









-Average active rig count

10.5

9.4

12%


15.5

17.1

(9%)


-End of period

66

66

-


66

66

-

Service rig Operating Revenue per Service Hour

723

652

11%


710

678

5%

Service Hours

9,588

8,511

13%


28,064

30,968

(9%)

Service rig utilization

16%

14%

14%


23%

26%

(12%)

(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 six months ended June 30, 2017.

 








Financial Position at (stated in thousands)




June 30, 2018

December 31, 2017

June 30, 2017

Working capital




7,717

62,866

51,730

Property and equipment




634,812

652,828

677,465

Total assets




670,584

760,504

758,278

Long term debt




210,944

265,219

264,702

 

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 complex horizontal wells.  Western is currently the fifth largest drilling contractor in Canada, based on the CAODC registered rigs, with a fleet of 50 rigs operating through Horizon.  Of the Canadian fleet, 23 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 six drilling rigs operating through Stoneham, including five Duvernay class triple drilling rigs.  Western is also the fifth largest well servicing company in Canada with a fleet of 66 rigs operating through Eagle.  Western's oilfield rental equipment division, which operates through Aero, provides oilfield rental equipment for hydraulic fracturing services, well completions and production work, coil tubing and drilling services.

Crude oil and natural gas prices impact the cash flow of Western's customers, which in turn impacts the demand for Western's services.  The following table summarizes average crude oil and natural gas prices, as well as average foreign exchange rates for the three and six months ended June 30, 2018 and 2017.








Three months ended June 30

Six months ended June 30


2018

2017

Change


2018

2017

Change

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
















Crude Oil








West Texas Intermediate (US$/bbl)

67.97

48.11

41%


65.63

49.87

32%

Western Canadian Select (CDN$/bbl)

64.44

51.35

25%


55.99

50.85

10%









Natural Gas








30 day Spot AECO (CDN$/mcf)

1.22

2.78

(56%)


1.63

2.74

(41%)









Average foreign exchange rates(2)








US dollar to Canadian dollar

1.29

1.34

(4%)


1.28

1.33

(4%)

(1)

See "Abbreviations" included in this press release.

(2)

Source: Bloomberg

 

West Texas Intermediate ("WTI") on average improved in the second quarter of 2018 as compared to the first quarter of 2018, increasing by 8%, and was 41% higher compared to the same period in the prior year.  For Western's Canadian customers, the impact of the weaker US dollar when translating WTI into the Canadian dollar equivalent, resulted in a 36% increase for the three months ended June 30, 2018, as compared to the same period in the prior year.  Canadian heavy crude pricing improved in the second quarter of 2018, as Western Canadian Select ("WCS") on average increased by 37% as compared to the first quarter of 2018, and increased by 25% as compared to the same period of the prior year.  Natural gas prices declined in the second quarter of 2018, as the 30 day spot AECO price decreased by 56% over the same period of the prior year and decreased by 37% as compared to the first quarter of 2018.  However, the prices for condensate and natural gas liquids ("NGL") in Canada improved in the second quarter of 2018, as compared to the same period in the prior year.

Improved market conditions in 2018 has led to a corresponding increase in the demand for oilfield services in the United States.  As reported by Baker Hughes, a GE Company, the average number of active drilling rigs in the United States increased approximately 16% and 23% respectively, for the three and six months ended June 30, 2018 as compared to the same periods in the prior year.  However in Canada, higher crude oil prices have been largely offset by lower natural gas prices, combined with continued industry concerns over market access, increased regulation, and the prevailing customer preference to return cash to shareholders, or pay down debt, rather than grow production.  These factors have resulted in a decrease in industry activity levels.  The CAODC reported that for drilling in Canada, the total number of Operating Days in the WCSB decreased by approximately 7.0% and 3.6% respectively, for the three and six months ended June 30, 2018, as compared to the same periods in the prior year.

Outlook

Currently, 20 of Western's drilling rigs are operating.  Six of Western's 56 drilling rigs (or 11%) are under long term take or pay contracts, with one expected to expire in 2018, two expected to expire in 2019, two expected to expire in 2020 and one expected to expire in 2021.  These contracts each typically generate between 250 and 350 Billable Days per year.

Western's capital budget for 2018 remains unchanged and is expected to total $20 million with $8 million allocated for expansion capital and $12 million for maintenance capital.  Western believes the 2018 capital budget provides a prudent use of cash resources and will allow it to maintain its premier drilling and well servicing rig fleets, while remaining responsive to customer requirements.  Western will continue to manage its operations in a disciplined manner and make required adjustments to its capital program as customer demand changes.  

Weak natural gas prices in Canada are expected to persist in 2018.  While Canadian crude oil prices are much improved, capital budgets for Western's Canadian customers have not increased materially.  As such, year over year activity levels for the remainder of 2018 are expected to remain relatively consistent with 2017, with the potential to modestly improve if recent gains in crude oil pricing are maintained.  Improving gross margin continues to be a priority for the Company and, as has been demonstrated over the last five quarters, Western is working to implement higher rates with each rig that is awarded work.  Prices for Western's services remain below historical levels and 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.  As at June 30, 2018, Western had nothing drawn on its $80.0 million Credit Facilities, which mature on December 17, 2020 and $215.0 million outstanding on its Second Lien Facility, which matures on January 31, 2023.   

Oilfield service activity in Canada will be affected by the development of resource plays in Alberta and northeast British Columbia which will be impacted by pipeline construction, environmental regulations including the implementation of a price on carbon emissions in Alberta, and the level of investment in Canada.  Currently, the largest challenges facing the oilfield service industry are limited take away capacity, continued customer spending constraints relative to historical levels, as a result of low natural gas prices and differentials on Canadian crude oil, and the increasing challenge of staffing field crews, particularly in the well servicing division.  Western's rig fleet is well positioned to benefit from potential liquefied natural gas expansion in British Columbia.  It is also Western's view that its modern drilling and well servicing rig fleets, reputation, and disciplined cash management provide a competitive advantage which will enable the Company to manage through the current oilfield service environment.

2018 Second 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. MT (11:00 a.m. ET) on Thursday, July 26, 2018.

The conference call dial-in number is 1-888-390-0546.

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 9, 2018 by dialing 1-888-390-0541, passcode 164464.

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)

2018

2017


2018

2017

Operating Revenue







Drilling

21,791

22,807


79,141

82,043


Production services

9,227

7,670


24,962

26,683


Less: inter-company eliminations

(42)

(8)


(162)

(104)


30,976

30,469


103,941

108,622

Third party charges

2,165

2,838


10,457

8,907

Revenue

33,141

33,307


114,398

117,529

Less: operating expenses

(44,081)

(44,128)


(121,566)

(120,370)

Add:







Depreciation – operating

16,313

16,412


32,704

32,793


Stock based compensation – operating

189

76


297

173

Gross Margin

5,562

5,667


25,833

30,125

 

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

The 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)

2018

2017


2018

2017

Net loss

(15,475)

(16,628)


(21,422)

(20,993)

Add:







Finance costs

4,493

5,419


9,873

10,831


Income tax recovery

(5,153)

(6,154)


(6,395)

(7,642)


Depreciation – operating

16,313

16,412


32,704

32,793


Depreciation – administrative

286

307


545

629

EBITDA

464

(644)


15,305

15,618

Add:







Stock based compensation – operating

189

76


297

173


Stock based compensation – administrative

254

565


504

1,134


Other items

(10)

124


(97)

1,821

Adjusted EBITDA

897

121


16,009

18,746

Subtract:







Depreciation – operating

(16,313)

(16,412)


(32,704)

(32,793)


Depreciation – administrative

(286)

(307)


(545)

(629)

Operating Loss

(15,702)

(16,598)


(17,240)

(14,676)

 

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, 2018

December 31, 2017

Long term debt




210,944

265,219

Current portion of long term debt




1,789

475

Less: cash and cash equivalents




(6,036)

(48,825)

Net Debt




206,697

216,869

 

Defined Terms:

Average active rig count (contract drilling): Calculated as drilling rig utilization – Billable Days multiplied by the average number of drilling rigs in the Company's fleet for the period.
Average active rig count (production services): Calculated as service rig utilization multiplied by the average number of service rigs in the Company's fleet for the period.
Billable Days:  Defined as Operating Days plus rig mobilization days.
Drilling rig utilization Operating Days (or "Drilling Rig Utilization"):  Calculated based on Operating Days divided by total available days.
Drilling rig utilization Billable Days:  Calculated based on Billable Days divided by total available days.
Operating Days:  Defined as contract drilling days, calculated on a spud to rig release basis.
Service Hours:  Defined as well servicing hours completed.
Service rig utilization:  Calculated based on Service Hours divided by available hours, being 10 hours per day, per well servicing rig, 365 days per year.

Contract Drilling Rig Classifications:

Cardium class rig: Defined as any contract drilling rig which has a total hookload less than or equal to 399,999 lbs (or 177,999 daN). 
Montney class rig: Defined as any contract drilling rig which has a total hookload between 400,000 lbs (or 178,000 daN) and 499,999 lbs (or 221,999 daN).
Duvernay class rig: Defined as any contract drilling rig which has a total hookload equal to or greater than 500,000 lbs (or 222,000 daN).

Abbreviations:

  • Barrel ("bbl");
  • Basis point ("bps"):  A 1% change equals 100 basis points and a 0.01% change is equal to one basis point;
  • Canadian Association of Oilwell Drilling Contractors ("CAODC");
  • DecaNewton ("daN");
  • International Financial Reporting Standards ("IFRS");
  • Natural Gas Liquids ("NGL");
  • Pounds ("lbs");
  • Thousand cubic feet ("mcf");
  • Western Canadian Sedimentary Basin ("WCSB");
  • Western Canadian Select ("WCS"); and
  • West Texas Intermediate ("WTI").

Forward-Looking Statements and Information
This press release contains certain statements or disclosures relating to Western that are based on the expectations of Western as well as assumptions made by and information currently available to Western which may constitute forward-looking information under applicable securities laws.  All information and statements contained herein that are not clearly historical in nature constitute forward-looking information, and the words "may", "will", "should", "could", "expect", "intend", "anticipate", "believe", "estimate", "plan", "predict", "potential", "continue", or the negative of these terms or other comparable terminology are generally intended to identify forward-looking information.  Such information represents the Company's internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital expenditures, anticipated future debt levels and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance.  This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information.

In particular, forward-looking information in this press release includes, but is not limited to, statements relating to commodity pricing; the future demand for and utilization of the Company's services and equipment; the pricing for the Company's services and equipment; the terms of existing and future drilling contracts in Canada and the US and the revenue resulting therefrom (including the number of Operating Days typically generated from the Company's contracts); the Company's expansion and maintenance capital plans for 2018; the Company's liquidity needs including the ability of current capital resources to cover Western's financial obligations and the 2018 capital budget; the use and availability of the Company's Credit Facilities; pricing for Western's services and impact on Adjusted EBITDA; the Company's ability to maintain certain covenants under its Credit Facilities; expectations as to the increase in crude oil transportation capacity through pipeline development; the potential impact of changes to environmental laws and regulations and the implementation of a price on carbon emissions in Alberta; the expectation of continued investment in the Canadian crude oil and natural gas industry; expectations relating to producer spending and activity levels for oilfield services, and the Company's ability to find and maintain enough field crew members.

The material assumptions in making the forward-looking statements in this press release include, but are not limited to, assumptions relating to: demand levels and pricing for oilfield services; demand for crude oil and natural gas and the price and volatility of crude oil and natural gas; pressures on commodity pricing; the continued business relationships between the Company and its significant customers; 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; the ability to maintain a satisfactory safety record; and general business, economic and market conditions.

Although Western believes that the expectations and assumptions on which such forward-looking statements and information are based on are reasonable, undue reliance should not be placed on the forward-looking statements and information as Western cannot give any assurance that they will prove to be correct.  Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties.  Actual results could differ materially from those currently anticipated due to a number of factors and risks.  These include, but are not limited to, the risk that recent improvements in commodity pricing may not continue, and other general industry, economic, market and business conditions.  Readers are cautioned that the foregoing list of risks, uncertainties and assumptions are not exhaustive.  Additional information on these and other risk factors that could affect Western's operations and financial results are 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.

View original content: http://www.newswire.ca/en/releases/archive/July2018/25/c8504.html

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