CALGARY, ALBERTA–(Marketwired – Oct. 25, 2016) – Western Energy Services Corp. (“Western” or the “Company”) (TSX:WRG) announces the release of its third quarter 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 three and nine months ended September 30, 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.
Third Quarter 2016 Operating Results:
- Third quarter Operating Revenue decreased by $13.7 million (or 31%) to $30.7 million in 2016 as compared to $44.4 million in 2015. In the contract drilling segment, Operating Revenue totaled $20.2 million in the third quarter of 2016 as compared to $30.9 million in the third quarter of 2015; while in the production services segment, Operating Revenue totaled $10.5 million for the three months ended September 30, 2016 as compared to $13.4 million in the same period of the prior year. While West Texas Intermediate (“WTI”) prices recovered somewhat near the end of the third quarter of 2016, Operating Revenue continued to be impacted by low commodity prices, as both crude oil and natural gas prices were lower year over year. Operating Revenue in the contract drilling and production services segments were impacted by lower utilization and pricing as described below:
- Drilling rig utilization – Operating Days (or “Drilling Rig Utilization”) in Canada was 20% in the third quarter of 2016 compared to 26% in the third quarter of 2015, reflecting a 600 basis points (“bps”) decrease. Third quarter 2016 Drilling Rig Utilization represented a premium of 300 bps to the Canadian Association of Oilwell Drilling Contractors (“CAODC”) industry average of 17%, consistent with the 200 bps premium to the industry average realized in the third quarter of 2015. Despite the premium relative to the CAODC average in the third quarter of 2016, weather negatively impacted Drilling Rig Utilization. While 940 Operating Days were worked in the period, 227 Operating Days were lost relating to weather delays. Higher than average precipitation levels impact the Company’s ability to move drilling rigs and work in certain locations. Additionally, increased competition in the third quarter of 2016 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%, as compared to the third 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 32% in the third quarter of 2016, as compared to 19% in the same period of the prior year. Operating Revenue per Revenue Day in the United States decreased by 37% in the third quarter of 2016 due to downward pricing pressure, as well as the renegotiation of the day rate and extending the term on the long term contract; and
- Well servicing utilization of 24% in the third quarter of 2016 compared to 26% in the same period of the prior year. Reduced activity, due to the low commodity price environment and unseasonably wet weather in the quarter, coupled with a 15% decrease in well servicing hourly rates, due to pricing pressure in all areas, resulted in a $2.4 million (or 22%) decrease in well servicing Operating Revenue in the period.
- Third quarter Adjusted EBITDA decreased by $7.2 million to $0.9 million in 2016 as compared to $8.1 million in the third quarter of 2015. The year over year change in Adjusted EBITDA is due to lower utilization and 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 third quarter of 2016 decreased by $1.4 million (or 23%) to $4.8 million as compared to $6.2 million in the third 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 $17.0 million in the third quarter of 2016 (a loss of $0.23 per basic common share) as compared to a net loss of $76.8 million in the same period in 2015 (a loss of $1.04 per basic common share). The change in the third quarter net loss in 2016, relative to the third quarter of 2015, can be attributed to the following:
- A prior year goodwill impairment loss of $71.3 million recorded in the third quarter of 2015; and
- A $3.8 million decrease in income tax expense due to lower taxable income in the third quarter of 2016.
- Offsetting the above mentioned items are the following:
- An increase of $7.8 million in depreciation expense due to the Company changing from unit of production to straight line depreciation for drilling and well servicing rigs; and
- A $7.2 million decrease in Adjusted EBITDA due to lower utilization and pricing in both the contract drilling and production services segments.
- Third quarter 2016 capital expenditures of $0.7 million included $0.3 million of expansion capital and $0.4 million of maintenance capital. In total, capital spending in the third quarter of 2016 decreased by 86% from the $4.8 million incurred in the third quarter of 2015, as the Company is only incurring necessary maintenance capital to preserve cash during the current slowdown in oilfield service activity.
Year to Date Operating Results
- Operating Revenue for the nine month period ended September 30, 2016 decreased by $100.7 million (or 57%) to $75.3 million in 2016, as compared to $176.0 million in the same period of the prior year. In the contract drilling segment, Operating Revenue totaled $49.9 million for the nine month period ended September 30, 2016 compared to $123.3 million in the same period of the prior year; while in the production services segment, year to date Operating Revenue totaled $25.4 million compared to $53.0 million in the same period of the prior year. Operating Revenue continued to be impacted by low commodity prices, as both crude oil and natural gas prices were lower year over year. Operating Revenue in the contract drilling and production services segments for the nine month period ended September 30, 2016 were impacted by lower utilization and pricing as described below:
- Drilling Rig Utilization in Canada of 14% for the nine month period ended September 30, 2016, compared to 28% for the nine month period ended September 30, 2015, reflects a 50% decrease. Drilling Rig Utilization on a year to date basis in 2016 represented a discount of 100 bps to the CAODC industry average of 15%, as compared to the 400 bps premium to the CAODC industry average realized in the nine month period ended September 30, 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 in 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 in the nine month period ended September 30, 2016 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%, as compared to the same period of 2015;
- In the United States, Drilling Rig Utilization of 22% for the nine months ended September 30, 2016, compared to 32% in the same period of the prior year. Operating Revenue per Revenue Day in the United States decreased by 23% in the nine months ended September 30, 2016 due to renegotiating the day rate and extending the term on a long term contract, coupled with pricing pressure on spot market rates; and
- Well servicing utilization of 17% for the nine months ended September 30, 2016 compared to 31% in the same period of the prior year. Reduced activity as well as a 19% reduction in well servicing hourly rates, due to pricing pressure in all areas, resulted in a $24.6 million (or 55%) decrease in well servicing Operating Revenue in the period.
- Adjusted EBITDA for the nine months ended September 30, 2016 decreased by $50.7 million to $2.3 million, as compared to $53.0 million for the nine months ended September 30, 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.
- Year to date administrative expenses, excluding depreciation and stock based compensation, for the nine month period ended September 30, 2016 decreased by $4.6 million (or 24%) to $15.0 million as compared to $19.6 million in the same period of the prior year. 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 $8.6 million and $22.1 million respectively, of additional depreciation expense for the three and nine months ended September 30, 2016 over what would have been expensed had the previous assumptions using the unit of production methodology continued to be used in the periods. The estimated additional depreciation expense for the year ending December 31, 2016 from this change is expected to be approximately $29.1 million.
- 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 September 30, 2016 Horizon had a fleet of 51 drilling rigs.
- The Company incurred a net loss of $47.5 million for the nine months ended September 30, 2016 (a loss of $0.64 per basic common share) as compared to a net loss of $74.1 million for the same period in 2015 (a loss of $1.00 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; and
- A $25.5 million decrease in income tax expense due to lower taxable income for the nine months ended September 30, 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 $50.7 million decrease in Adjusted EBITDA due to lower utilization and pricing in both the contract drilling and production services segments;
- An increase of $12.2 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;
- Losses on asset decommissioning of $5.2 million in the contract drilling segment recorded in the second quarter of 2016; and
- A $2.0 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 period.
- Year to date capital expenditures of $2.0 million included $0.9 million of expansion capital and $1.1 million of maintenance capital. In total, capital spending for the nine months ended September 30, 2016 decreased by 93% from the $30.3 million incurred in the same period of 2015, as the Company is only incurring 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”) totaling $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 Sept 30 | Nine months ended Sept 30 | ||||||||||||
| Financial Highlights | 2016 | 2015 | Change | 2016 | 2015 | Change | |||||||
| Revenue | 32,485 | 46,959 | (31%) | 79,312 | 184,846 | (57%) | |||||||
| Operating Revenue(1) | 30,665 | 44,350 | (31%) | 75,258 | 176,027 | (57%) | |||||||
| Gross Margin(1) | 5,685 | 14,285 | (60%) | 17,255 | 72,579 | (76%) | |||||||
| Gross Margin as a percentage of Operating Revenue | 19% | 32% | (41%) | 23% | 41% | (44%) | |||||||
| Adjusted EBITDA(1) | 896 | 8,080 | (89%) | 2,269 | 52,972 | (96%) | |||||||
| Adjusted EBITDA as a percentage of Operating Revenue | 3% | 18% | (83%) | 3% | 30% | (90%) | |||||||
| Cash flow from operating activities | 909 | (530) | (272%) | 17,958 | 79,816 | (78%) | |||||||
| Capital expenditures | 651 | 4,752 | (86%) | 1,995 | 30,303 | (93%) | |||||||
| Net loss | (16,973) | (76,816) | (78%) | (47,464) | (74,129) | (36%) | |||||||
| -basic net loss per share | (0.23) | (1.04) | (78%) | (0.64) | (1.00) | (36%) | |||||||
| -diluted net loss per share | (0.23) | (1.04) | (78%) | (0.64) | (1.00) | (36%) | |||||||
| Weighted average number of shares | |||||||||||||
| -basic | 73,722,144 | 74,044,832 | – | 73,672,389 | 74,434,833 | (1%) | |||||||
| -diluted | 73,722,144 | 74,044,832 | – | 73,672,389 | 74,434,833 | (1%) | |||||||
| Outstanding common shares as at period end | 73,795,266 | 73,684,965 | – | 73,795,266 | 73,684,965 | – | |||||||
| Dividends declared | – | 5,526 | (100%) | – | 16,710 | (100%) | |||||||
| (1) See “Non-IFRS measures” included in this press release. | |||||||||||||
| Three months ended Sept 30 | Nine months ended Sept 30 | ||||||||||||
| Operating Highlights | 2016 | 2015 | Change | 2016 | 2015 | Change | |||||||
| Contract Drilling | |||||||||||||
| Canadian Operations: | |||||||||||||
| Contract drilling rig fleet: | |||||||||||||
| -Average | 51 | 50 | 2% | 52 | 49 | 6% | |||||||
| -End of period | 51 | 52 | (2%) | 51 | 52 | (2%) | |||||||
| Operating Revenue per Revenue Day(1) | 15,256 | 21,135 | (28%) | 17,206(3) | 23,815 | (28%) | |||||||
| Operating Revenue per Operating Day(1) | 17,017 | 23,220 | (27%) | 19,224(3) | 26,221 | (27%) | |||||||
| Operating Days(1) | 940 | 1,176 | (20%) | 1,959 | 3,793 | (48%) | |||||||
| Drilling rig utilization – Revenue Days(1) | 22% | 28% | (21%) | 15% | 31% | (52%) | |||||||
| Drilling rig utilization – Operating Days(1) | 20% | 26% | (23%) | 14% | 28% | (50%) | |||||||
| CAODC industry average utilization(1)(2) | 17% | 24% | (29%) | 15% | 24% | (38%) | |||||||
| United States Operations: | |||||||||||||
| Contract drilling rig fleet: | |||||||||||||
| -Average | 5 | 5 | – | 5 | 5 | – | |||||||
| -End of period | 5 | 5 | – | 5 | 5 | – | |||||||
| Operating Revenue per Revenue Day (US$)(1) | 18,967 | 30,260 | (37%) | 22,515 | 29,140(4) | (23%) | |||||||
| Operating Revenue per Operating Day (US$)(1) | 22,246 | 32,341 | (31%) | 25,923 | 32,967(4) | (21%) | |||||||
| Operating Days(1) | 145 | 86 | 69% | 306 | 442 | (31%) | |||||||
| Drilling rig utilization – Revenue Days(1) | 37% | 20% | 85% | 26% | 37% | (30%) | |||||||
| Drilling rig utilization – Operating Days(1) | 32% | 19% | 68% | 22% | 32% | (31%) | |||||||
| Production Services | |||||||||||||
| Well servicing rig fleet: | |||||||||||||
| -Average | 66 | 66 | – | 66 | 66 | – | |||||||
| -End of period | 66 | 66 | – | 66 | 66 | – | |||||||
| Service Rig Operating Revenue per Service Hour(1) | 603 | 712 | (15%) | 646 | 799 | (19%) | |||||||
| Service Hours(1) | 14,335 | 15,565 | (8%) | 31,123 | 55,873 | (44%) | |||||||
| Service rig utilization(1) | 24% | 26% | (8%) | 17% | 31% | (45%) | |||||||
| (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 nine months ended September 30, 2016. | |||||||||||||
| (4) Excludes shortfall commitment and standby revenue from take or pay contracts of US$4.5 million for the nine months ended September 30, 2015. | |||||||||||||
| Financial Position at (stated in thousands) | Sept 30, 2016 | Sept 30, 2015 | Dec 31, 2015 | |||
| Working capital | 55,259 | 71,735 | 70,679 | |||
| Property and equipment | 720,554 | 843,670 | 773,647 | |||
| Total assets | 794,170 | 947,137 | 876,608 | |||
| Long term debt | 264,118 | 264,219 | 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 currently has a drilling rig fleet of 56 rigs specifically suited for drilling horizontal wells of increased complexity. Western is the sixth largest drilling contractor in Canada 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 fourth 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. Overall performance of the Company for the three and nine months ended September 30, 2016 continued to be impacted by the low crude oil and natural gas price environment. WTI on average remained relatively constant in the third quarter of 2016 as compared to the second quarter of 2016, decreasing by 1%, and was 3% and 19% lower for the three and nine months ending September 30, 2016 respectively, as compared to the same periods in the prior year. Canadian natural gas prices, such as AECO, increased significantly quarter over quarter, increasing on average by 70% from the second quarter of 2016 to the third quarter of 2016. However AECO remained 18% and 33% lower for the three and nine months ended September 30, 2016 respectively, as compared to the same periods of the prior year. The following table summarizes average crude oil and natural gas prices, as well as average foreign exchange rates for the three and nine months ended September 30, 2016 and 2015.
| Three months ended Sept 30 | Nine months ended Sept 30 | |||||||||||
| 2016 | 2015 | Change | 2016 | 2015 | Change | |||||||
| Average crude oil and natural gas prices(1)(2) | ||||||||||||
| Crude Oil | ||||||||||||
| West Texas Intermediate (US$/bbl) | 44.88 | 46.43 | (3%) | 41.44 | 50.96 | (19%) | ||||||
| Western Canadian Select (CDN$/bbl) | 40.00 | 43.26 | (8%) | 37.09 | 47.72 | (22%) | ||||||
| Natural Gas | ||||||||||||
| 30 day Spot AECO (CDN$/mcf) | 2.38 | 2.91 | (18%) | 1.86 | 2.78 | (33%) | ||||||
| Average foreign exchange rates(2) | ||||||||||||
| US dollar to Canadian dollar | 1.30 | 1.31 | (1%) | 1.32 | 1.26 | 5% | ||||||
| (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 38% and 43% respectively, for the three and nine months ended September 30, 2016, as compared to the three and nine months ended September 30, 2015. Similarly, as reported by Baker Hughes Incorporated, the number of active drilling rigs in the United States decreased approximately 45% and 54% for the three and nine months ended September 30, 2016 respectively, as compared to the same periods in the prior year.
Outlook
Currently, 15 of Western’s drilling rigs are operating and three of Western’s 56 drilling rigs (or 5%) are under long term take or pay contracts, with two of these contracts expected to expire in 2017, and one expected to expire in 2018. These contracts each typically generate between 250 and 350 Revenue Days per year.
Western’s capital budget for 2016 of $7 million remains unchanged, with $3 million allocated for expansion capital and $4 million for maintenance capital. Western believes the 2016 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 significantly, particularly since August 2016. As such, North American drilling rig counts appear to have bottomed out and the Company is expecting improved year over year activity levels in the fourth quarter of 2016. However, the Company expects pricing pressure will continue to be challenging as activity levels begin to recover. As at September 30, 2016, the Company had 16 drilling rigs operating in Canada and the United States, representing combined utilization of 29%; since that time, activity has remained steady and at October 25, 2016, the Company has 15 drilling rigs operating in Canada and the United States, with a full complement of experienced crews. Lower than normal activity levels and pricing pressure will continue to impact Western’s Adjusted EBITDA and cash flow from operating activities if low commodity prices persist. As discussed, the Company has taken a proactive approach to reducing administrative and fixed overhead costs including reducing fixed headcount since the beginning of 2015 by a third and implementing a 10% companywide wage rollback to salaried employees and directors’ fees in the first quarter of 2016, as well as reducing various other office related costs. In addition, Western’s variable cost structure, the previously announced suspension of the Company’s quarterly dividend and a prudent capital budget will aid in preserving balance sheet strength. In addition to $47.0 million in cash and cash equivalents at September 30, 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 $265.0 million 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 liquefied natural gas projects, increased crude oil transportation capacity through rail and pipeline development 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.
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, how those activities are financed, the impact of foreign exchange, how the results are taxed, how funds are invested, and how non-cash items and one-time gains and losses affect results.
The following table provides a reconciliation of revenue under IFRS, as disclosed in the condensed consolidated statements of operations and comprehensive income, to Operating Revenue and Gross Margin:
| Three months ended Sept 30 | Nine months ended Sept 30 | ||||||||
| (stated in thousands) | 2016 | 2015 | 2016 | 2015 | |||||
| Operating Revenue | |||||||||
| Drilling | 20,210 | 30,921 | 49,922 | 123,274 | |||||
| Production Services | 10,460 | 13,448 | 25,354 | 53,025 | |||||
| Less: inter-company eliminations | (5) | (19) | (18) | (272) | |||||
| 30,665 | 44,350 | 75,258 | 176,027 | ||||||
| Third party charges | 1,820 | 2,609 | 4,054 | 8,819 | |||||
| Revenue | 32,485 | 46,959 | 79,312 | 184,846 | |||||
| Less: operating expenses | (43,601) | (41,684) | (103,904) | (141,869) | |||||
| Add: | |||||||||
| Depreciation – operating | 16,712 | 8,791 | 41,352 | 29,040 | |||||
| Stock based compensation – operating | 89 | 219 | 495 | 562 | |||||
| Gross Margin | 5,685 | 14,285 | 17,255 | 72,579 | |||||
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 condensed 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 Sept 30 | Nine months ended Sept 30 | ||||||||
| (stated in thousands) | 2016 | 2015 | 2016 | 2015 | |||||
| Net loss | (16,973) | (76,816) | (47,464) | (74,129) | |||||
| Add: | |||||||||
| Finance costs | 5,708 | 5,508 | 17,044 | 15,029 | |||||
| Income tax expense (recovery) | (6,043) | (2,247) | (16,772) | 8,725 | |||||
| Depreciation – operating | 16,712 | 8,791 | 41,352 | 29,040 | |||||
| Depreciation – administrative | 378 | 464 | 1,204 | 1,378 | |||||
| EBITDA | (218) | (64,300) | (4,636) | (19,957) | |||||
| Add: | |||||||||
| Stock based compensation – operating | 89 | 219 | 495 | 562 | |||||
| Stock based compensation – administrative | 759 | 980 | 2,651 | 2,599 | |||||
| Impairment loss on goodwill | – | 71,256 | – | 71,256 | |||||
| Loss on asset decommissioning | – | – | 5,225 | – | |||||
| Other items | 266 | (75) | (1,466) | (1,488) | |||||
| Adjusted EBITDA | 896 | 8,080 | 2,269 | 52,972 | |||||
| Subtract: | |||||||||
| Depreciation – operating | (16,712) | (8,791) | (41,352) | (29,040) | |||||
| Depreciation – administrative | (378) | (464) | (1,204) | (1,378) | |||||
| Operating Earnings (Loss) | (16,194) | (1,175) | (40,287) | 22,554 | |||||
Net Debt
The following table provides a reconciliation of long term debt under IFRS, as disclosed in the condensed consolidated balance sheets to Net Debt:
| (stated in thousands) | September 30, 2016 | December 31, 2015 | ||
| Long term debt | 264,118 | 264,155 | ||
| Current portion of long term debt | 634 | 761 | ||
| Less: cash and cash equivalents | (47,016) | (58,445) | ||
| Net Debt | 217,736 | 206,471 |
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”);
- Western Canadian Sedimentary Basin (“WCSB”); and
- Western Canadian Select (“WCS”).
2016 Third Quarter Results Conference Call and Webcast
Western has scheduled a conference call and webcast to begin at 10:00 a.m. MDT (12:00 p.m. EDT) on Wednesday, October 26, 2016.
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 November 9, 2016 by dialing 1-800-408-3053 or 905-694-9451, passcode 7725844.
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 future declaration of dividends; commodity pricing; the future demand for and utilization of 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 2016; the Company’s liquidity needs including the ability of current capital resources to cover Western’s financial obligations and the 2016 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 2016 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; expectations as to the increase in crude oil transportation capacity through rail and pipeline development; expectations as to the necessary approvals for liquefied natural gas projects being obtained; the expectation of continued foreign investment into the Canadian crude oil and natural gas industry; the expectation that producer spending constraints will continue to be a large challenge facing the Company in 2016; 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; the development of liquefied natural gas projects, crude oil transport and pipeline approval and development; the Company’s ability to finance its operations; the effects of seasonal and weather conditions on operations and facilities; the competitive environment to which the various business segments are, or may be, exposed in all aspects of their business; the ability of the Company’s various business segments to access equipment (including spare parts and new technologies); changes in laws or regulations; currency exchange fluctuations; the ability of the Company to attract and retain skilled labour and qualified management; the ability to retain and attract significant customers; and other unforeseen conditions which could impact the use of services supplied by Western including Western’s ability to respond to such conditions.
Although Western believes that the expectations and assumptions on which such forward-looking statements and information are based on are reasonable, undue reliance should not be placed on the forward-looking statements and information as Western cannot give any assurance that they will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risk that the demand for oilfield services will not improve for the remainder of 2016 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.
Alex R.N. MacAusland
President and CEO
403.984.5916
403.984.5917 (FAX)
Western Energy Services Corp.
Jeffrey K. Bowers
Senior VP Finance and CFO
403.984.5916
403.984.5917 (FAX)
www.wesc.ca