WESTERN ENERGY SERVICES CORP. RELEASES THIRD QUARTER 2023 FINANCIAL AND OPERATING RESULTS AND ANNOUNCES FURTHER DEBT REPAYMENTS
CALGARY, AB, Oct. 24, 2023 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its third quarter 2023 financial and operating results. Additional information relating to the Company, including the Company's financial statements and management's discussion and analysis as at September 30, 2023 and for the three and nine months ended September 30, 2023 and 2022 ("MD&A") will be available on SEDAR+ at www.sedarplus.ca. Non-International Financial Reporting Standards ("Non-IFRS") measures and ratios, such as Adjusted EBITDA, Adjusted EBITDA as a percentage of revenue, revenue per Operating Day, revenue per Service Hour and Working Capital, as well as abbreviations and definitions for standard industry terms are defined later in this press release. All amounts are denominated in Canadian dollars (CDN$) unless otherwise identified.
Third Quarter 2023 Operating Results:
- On September 29, 2023, the Company made a lump sum repayment of $4.1 million related to its HSBC Bank Canada six-year committed term non-revolving facility with the participation of Business Development Canada (the "HSBC Facility"). The voluntary repayment included all committed monthly principal payments from September 30, 2023 up to December 31, 2026, resulting in no current obligation owing on the HSBC Facility as at September 30, 2023. The remaining balance under the HSBC Facility is due upon maturity of the HSBC Facility on December 31, 2026.
- Third quarter revenue decreased by $3.5 million or 6%, to $55.0 million in 2023, as compared to $58.5 million in the third quarter of 2022. Contract drilling revenue totalled $38.3 million in the third quarter of 2023, which was consistent with $38.1 million in the third quarter of 2022. Production services revenue was $16.8 million for the three months ended September 30, 2023, a decrease of $3.6 million or 18%, as compared to $20.4 million in the same period of the prior year. In the third quarter of 2023, revenue was negatively impacted by lower activity in production services and contract drilling in Canada and the US due to lower commodity prices, compared to the third quarter of 2022 as described below:
- In Canada, Operating Days of 883 days in the third quarter of 2023 were 26 days (or 3%) lower compared to 909 days in the third quarter of 2022. This compares to a 7% decrease in the Canadian Association of Energy Contractors ("CAOEC") industry Operating Days in the third quarter of 2023, compared to the third quarter of 2022. Drilling rig utilization in Canada was 28% in the third quarter of 2023, compared to 27% in the same period of the prior year, as lower Operating Days were offset by three rigs that were deregistered since September 30, 2022. The CAOEC industry average utilization of 38%1 for the third quarter of 2023 represented a decrease of 200 bps compared to the CAOEC industry average utilization of 40% in the third quarter of 2022. Revenue per Operating Day averaged $31,698 in the third quarter of 2023, an increase of 8% compared to the same period of the prior year, mainly due to rig upgrades, market driven increased pricing, and inflationary pressures on operating costs, including higher wages and fuel charges that are passed through to the customer;
- In the United States ("US"), drilling rig utilization averaged 34% in the third quarter of 2023, compared to 45% in the third quarter of 2022, with Operating Days decreasing from 333 days in the third quarter of 2022 to 249 days in the third quarter of 2023 due to lower industry activity. Average active industry rigs of 6492 in the third quarter of 2023 were 15% lower compared to the third quarter of 2022. Revenue per Operating Day for the third quarter of 2023 averaged US$30,898, a 17% increase compared to US$26,372 in the same period of the prior year, mainly due to improved spot market rates; and
- In Canada, service rig utilization of 33% in the third quarter of 2023 was lower than 45% in the same period of the prior year as industry activity decreased, mainly due to the completion of the Federal site rehabilitation program, several customers waiting on the restoration of power in areas impacted by wildfires and lower commodity prices experienced during the first eight months of 2023, compared to 2022. Revenue per Service Hour averaged $1,012 in the third quarter of 2023 and was 4% higher than the third quarter of 2022, due to improved pricing and inflationary pressures on operating costs, including higher wages and fuel charges that are passed through to the customer.
- Administrative expenses increased by $0.7 million or 21%, to $4.0 million in the third quarter of 2023, as compared to $3.3 million in the third quarter of 2022, due to inflationary pressures on all employee related costs.
- The Company incurred a net loss of $1.3 million in the third quarter of 2023 ($0.04 net loss per basic common share) as compared to a net income of $0.8 million in the same period in 2022 ($0.02 net income per basic common share). The change can mainly be attributed to a $3.8 million decrease in Adjusted EBITDA and a $0.5 million increase in depreciation expense due to property and equipment additions, which were partially offset by a $1.3 million decrease in income tax expense, a $0.6 million increase in other items, a $0.2 million decrease in stock based compensation expense and a $0.1 million decrease in finance costs due to a lower total debt balance.
- Adjusted EBITDA of $11.0 million in the third quarter of 2023 was $3.8 million, or 25%, lower compared to $14.8 million in the third quarter of 2022. Adjusted EBITDA in 2023 was lower due to lower production services activity in Canada and lower contract drilling activity in the US and Canada, as well as inflationary cost increases, offset partially by higher pricing across all divisions.
- Third quarter additions to property and equipment of $7.3 million in 2023 compared to $8.5 million in the third quarter of 2022, consisting of $1.7 million of expansion capital related to the substantial completion of the Company's rig upgrade program and $5.6 million of maintenance capital.
1 Source: CAOEC, monthly Contractor Summary. |
Year to Date 2023 Operating Results:
- During the nine months ended September 30, 2023, the Company reduced its total debt by $13.6 million (or 10%), primarily through repayments of its Credit Facilities (as defined in this press release) as well as a $4.1 million voluntary repayment of all committed monthly principal amounts owing on its HSBC Facility to its maturity on December 31, 2026 as described previously.
- Western's drilling rig upgrade program, which was initiated in 2022, has been a success and has generated a substantial portion of revenue in the nine months ended September 30, 2023. Since the upgrades have been performed and the rigs recommissioned into service, all upgraded drilling rigs have worked for customers. Additionally, the upgraded rigs have generated higher day rates which contributed to increased revenue for the nine months ended September 30, 2023.
- Revenue for the nine months ended September 30, 2023, increased by $37.6 million or 27%, to $177.2 million as compared to $139.6 million for the nine months ended September 30, 2022. Contract drilling revenue totalled $126.9 million for the nine months ended September 30, 2023, an increase of $40.6 million or 47%, compared to $86.3 million in the same period of the prior year. Production services revenue was $50.6 million for the nine months ended September 30, 2023, a decrease of $2.9 million or 6%, as compared to $53.5 million in the same period of the prior year. In the nine months ended September 30, 2023, revenue was positively impacted by improved pricing in all divisions, rig upgrades, as well as higher activity in contract drilling, partially offset by lower activity in production services, compared to the same period of 2022 as described below:
- In Canada, Operating Days of 2,742 days for the nine months ended September 30, 2023, were 430 days (or 19%) higher, compared to 2,312 days for the nine months ended September 30, 2022, resulting in drilling rig utilization of 30% for the nine months ended September 30, 2023, compared to 23% in the same period of the prior year. This compares to a 1% increase in CAOEC Operating Days for the nine months ended September 30, 2023, compared to the same period in the prior year. The CAOEC industry average utilization of 36%3 for the nine months ended September 30, 2023, represented an increase of 200 bps compared to the CAOEC industry average utilization of 34% for the nine months ended September 30, 2022. Revenue per Operating Day averaged $32,755 for the nine months ended September 30, 2023, an increase of 17% compared to the same period of the prior year, mainly due to rig upgrades, market driven increased pricing, and inflationary pressures on operating costs, including higher wages and fuel charges that are passed through to the customer;
- In the US, drilling rig utilization averaged 39% for the nine months ended September 30, 2023, compared to 31% in the same period of 2022, with Operating Days improving by 160 days from 683 days in 2022 to 843 days in 2023. Average active industry rigs of 7094 in the nine months ended September 30, 2023 were 1% higher than the average for the nine months ended September 30, 2022. Revenue per Operating Day for the nine months ended September 30, 2023 averaged US$32,038, a 31% increase compared to US$24,421 in the same period of the prior year, mainly due to improved spot market pricing in the Williston Basin; and
- In Canada, service rig utilization of 33% for the nine months ended September 30, 2023 was lower than 42% in the same period of the prior year as industry activity decreased, mainly due to the completion of the Federal site rehabilitation program, several customers waiting on the restoration of power in areas impacted by wildfires and lower commodity prices. Revenue per Service Hour averaged $1,030 for the nine months ended September 30, 2023 and was 11% higher than the same period of the prior year, due to improved pricing and inflationary pressures on operating costs, including higher wages and fuel charges that are passed through to the customer.
- Administrative expenses increased by $2.3 million or 23%, to $12.4 million for the nine months ended September 30, 2023, as compared to $10.1 million in the same period of 2022, due to higher employee related costs along with inflationary costs and higher professional fees.
- The Company generated a net loss of $4.7 million for the nine months ended September 30, 2023 ($0.14 net loss per basic common share) as compared to net income of $32.4 million in the same period in 2022 ($1.89 net income per basic common share). The change can mainly be attributed to the $49.4 million gain on debt forgiveness in 2022 in connection with the Company's restructuring transaction completed in May 2022, a $6.7 million increase in Adjusted EBITDA, a $4.0 million decrease in income tax expense and a $2.7 million decrease in finance costs due to the lower total debt balance, offset partially by a $1.1 million increase in stock based compensation expense and a $1.1 million increase in depreciation expense due to property and equipment additions.
- Adjusted EBITDA of $34.4 million for the nine months ended September 30, 2023 was $6.7 million, or 24%, higher compared to $27.7 million in the same period of 2022. Adjusted EBITDA was higher due to improved contract drilling activity in Canada and the US in the first half of 2023, higher pricing across all divisions, and US$0.6 million of shortfall commitment revenue, which was offset partially by lower activity in the third quarter of 2023, one-time costs of $0.6 million related to reactivating certain drilling rigs and inflationary cost increases and $0.8 million lower government subsidies received in 2023 compared to 2022.
- Year to date 2023 additions to property and equipment of $19.2 million compared to $26.5 million in the same period of 2022, consisting of $6.8 million of expansion capital related to the substantial completion of the Company's rig upgrade program and $12.4 million of maintenance capital.
3 Source: CAOEC, monthly Contractor Summary. |
Selected Financial Information |
|||||||||||||||||
(stated in thousands, except share and per share amounts) |
|||||||||||||||||
Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||||
Financial Highlights |
2023 |
2022 |
Change |
2023 |
2022 |
Change |
|||||||||||
Revenue |
55,003 |
58,483 |
(6 %) |
177,196 |
139,552 |
27 % |
|||||||||||
Adjusted EBITDA(1) |
11,033 |
14,799 |
(25 %) |
34,369 |
27,688 |
24 % |
|||||||||||
Adjusted EBITDA as a percentage of revenue(1) |
20 % |
25 % |
(20 %) |
19 % |
20 % |
(5 %) |
|||||||||||
Cash flow from operating activities |
13,267 |
6,854 |
94 % |
45,085 |
22,039 |
105 % |
|||||||||||
Additions to property and equipment |
7,348 |
8,470 |
(13 %) |
19,218 |
26,520 |
(28 %) |
|||||||||||
Net income (loss) |
(1,267) |
818 |
(255 %) |
(4,691) |
32,415 |
(114 %) |
|||||||||||
– basic and diluted net income (loss) per share |
(0.04) |
0.02 |
(300 %) |
(0.14) |
1.89 |
(107 %) |
|||||||||||
Weighted average number of shares |
|||||||||||||||||
– basic |
33,841,781 |
33,839,658 |
- |
33,841,478 |
17,120,283 |
98 % |
|||||||||||
– diluted |
33,841,781 |
33,839,658 |
- |
33,841,478 |
17,120,936 |
98 % |
|||||||||||
Outstanding common shares as at period end |
33,843,009 |
33,841,318 |
- |
33,843,009 |
33,841,318 |
- |
|||||||||||
(1) See "Non-IFRS Measures and Ratios" included in this press release. |
Three months ended September 30 |
Nine months ended September 30 |
|||||||||||||||
Operating Highlights(2) |
2023 |
2022 |
Change |
2023 |
2022 |
Change |
||||||||||
Contract Drilling |
||||||||||||||||
Canadian Operations: |
||||||||||||||||
Contract drilling rig fleet: |
||||||||||||||||
– Average active rig count |
9.6 |
9.9 |
(3 %) |
10.0 |
8.5 |
18 % |
||||||||||
Operating Days |
883 |
909 |
(3 %) |
2,742 |
2,312 |
19 % |
||||||||||
Revenue per Operating Day(3) |
31,698 |
29,283 |
8 % |
32,755 |
28,002 |
17 % |
||||||||||
Drilling rig utilization |
28 % |
27 % |
4 % |
30 % |
23 % |
30 % |
||||||||||
CAOEC industry average utilization – Operating Days(4) |
38 % |
40 % |
(5 %) |
36 % |
34 % |
6 % |
||||||||||
Average meters drilled per well |
7,035 |
5,929 |
19 % |
6,908 |
6,077 |
14 % |
||||||||||
Average Operating Days per well |
10.6 |
11.4 |
(7 %) |
12.7 |
12.1 |
5 % |
||||||||||
United States Operations: |
||||||||||||||||
Contract drilling rig fleet: |
||||||||||||||||
– Average active rig count |
2.7 |
3.6 |
(25 %) |
3.1 |
2.5 |
24 % |
||||||||||
Operating Days |
249 |
333 |
(25 %) |
843 |
683 |
23 % |
||||||||||
Revenue per Operating Day (US$)(3) |
30,898 |
26,372 |
17 % |
32,038 |
24,421 |
31 % |
||||||||||
Drilling rig utilization |
34 % |
45 % |
(24 %) |
39 % |
31 % |
26 % |
||||||||||
Average meters drilled per well |
3,609 |
3,727 |
(3 %) |
3,459 |
3,604 |
(4 %) |
||||||||||
Average Operating Days per well |
12.8 |
9.8 |
31 % |
13.0 |
10.9 |
19 % |
||||||||||
Production Services |
||||||||||||||||
Well servicing rig fleet: |
||||||||||||||||
– Average active rig count |
21.5 |
28.4 |
(24 %) |
21.5 |
26.4 |
(19 %) |
||||||||||
Service Hours |
13,984 |
18,492 |
(24 %) |
42,081 |
51,635 |
(19 %) |
||||||||||
Revenue per Service Hour(3) |
1,012 |
975 |
4 % |
1,030 |
928 |
11 % |
||||||||||
Service rig utilization |
33 % |
45 % |
(27 %) |
33 % |
42 % |
(21 %) |
||||||||||
(2) See "Defined Terms" included in this press release. |
(3) See "Non-IFRS Measures and Ratios" included in this press release. |
(4) Source: The CAOEC monthly Contractor Summary. The CAOEC industry average is based on Operating Days divided by total available drilling days. |
Financial Position at (stated in thousands) |
September 30, 2023 |
December 31, 2022 |
September 30, 2022 |
|
Working capital(1) |
16,473 |
21,923 |
21,439 |
|
Total assets |
453,980 |
475,708 |
475,651 |
|
Long term debt – non current portion |
114,107 |
126,527 |
127,639 |
(1) See "Non-IFRS Measures and Ratios" included in this press release. |
Business Overview
Western is an energy services company that provides contract drilling services in Canada and in the US and production services in Canada through its various divisions, its subsidiary, and its first nations relationships.
Contract Drilling
Western markets a fleet of 42 drilling rigs specifically suited for drilling complex horizontal wells across Canada and the US. Western is currently the fourth largest drilling contractor in Canada, based on the CAOEC registered drilling rigs5.
Western's marketed and owned contract drilling rig fleets are comprised of the following:
As at September 30 |
|||||||
2023 |
2022 |
||||||
Rig class(1) |
Canada |
US |
Total |
Canada |
US |
Total |
|
Cardium |
11 |
1 |
12 |
11 |
2 |
13 |
|
Montney |
18 |
1 |
19 |
19 |
- |
19 |
|
Duvernay |
5 |
6 |
11 |
7 |
6 |
13 |
|
Total marketed drilling rigs(2) |
34 |
8 |
42 |
37 |
8 |
45 |
|
Total owned drilling rigs |
48 |
8 |
56 |
49 |
8 |
57 |
|
(1) See "Contract Drilling Rig Classifications" included in this press release. |
(2) Source: CAOEC Contractor Summary as at October 24, 2023. |
Production Services
Production services provides well servicing and oilfield equipment rentals in Canada. Western operates 65 well servicing rigs and is the second largest well servicing company in Canada based on CAOEC registered well servicing rigs6.
Western's well servicing rig fleet is comprised of the following:
Owned well servicing rigs |
As at September 30 |
|
Mast type |
2023 |
2022 |
Single |
30 |
30 |
Double |
27 |
25 |
Slant |
8 |
8 |
Total owned well servicing rigs |
65 |
63 |
Business Environment
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 nine months ended September 30, 2023 and 2022.
Three months ended September 30 |
Nine months ended September 30 |
||||||||||||||
2023 |
2022 |
Change |
2023 |
2022 |
Change |
||||||||||
Average crude oil and natural gas prices(1)(2) |
|||||||||||||||
Crude Oil |
|||||||||||||||
West Texas Intermediate (US$/bbl) |
82.26 |
91.56 |
(10 %) |
77.40 |
98.09 |
(21 %) |
|||||||||
Western Canadian Select (CDN$/bbl) |
93.19 |
93.53 |
- |
80.42 |
105.55 |
(24 %) |
|||||||||
Natural Gas |
|||||||||||||||
30 day Spot AECO (CDN$/mcf) |
2.70 |
4.62 |
(42 %) |
2.86 |
5.70 |
(50 %) |
|||||||||
Average foreign exchange rates(2) |
|||||||||||||||
US dollar to Canadian dollar |
1.34 |
1.31 |
2 % |
1.34 |
1.28 |
5 % |
|||||||||
(1) See "Abbreviations" included in this press release. (2) Source: Sproule September 30, 2023, Price Forecast, Historical Prices. |
|||||||||||||||
5 Source: CAOEC Drilling Contractor Summary as at October 24, 2023. |
West Texas Intermediate ("WTI") on average decreased by 10% and 21% respectively, for the three and nine months ended September 30, 2023, compared to the same periods in the prior year. Pricing on Western Canadian Select ("WCS") crude oil for the three months ended September 30, 2023, was consistent with the same period of the prior year, whereas for the nine months ended September 30, 2023, WCS decreased by 24%, compared to the same period in the prior year. In the first eight months of 2023, both WTI and WCS were lower than the same period of 2022, however pricing for both WTI and WCS improved at the end of the third quarter of 2023, compared to the third quarter of 2022. In 2023, crude oil prices decreased due to global economic concerns including weakening demand for crude oil, the fear of a North American recession and continued high interest rates implemented to manage inflationary factors. Natural gas prices in Canada also declined in 2023 due to lower demand, as well as weather related factors including warmer winter seasons in both North America and Europe, as the 30-day spot AECO price decreased by 42% and 50% respectively, for the three and nine months ended September 30, 2023, compared to the same periods of the prior year. Additionally, the US dollar to the Canadian dollar foreign exchange rate for the three and nine months ended September 30, 2023, strengthened by 2% and 5% respectively, compared to the same periods of the prior year.
In both the US and Canada, lower commodity prices in the first eight months of the year reduced industry activity in the third quarter of 2023. As reported by Baker Hughes Company7, the number of active drilling rigs in the US decreased by approximately 19% to 623 rigs as at September 30, 2023, as compared to 765 rigs at September 30, 2022 due to lower commodity prices. In Canada, there were 190 active rigs in the Western Canadian Sedimentary Basin ("WCSB") at September 30, 2023, compared to 215 active rigs as at September 30, 2022, representing a decrease of approximately 12%. The CAOEC8 reported that for drilling in Canada, the total number of Operating Days in the WCSB for the three months ended September 30, 2023, were 7% lower than the same period in the prior year. For the nine months ended September 30, 2023, the total number of Operating Days in the WCSB in Canada were 1% higher than the same period of the prior year. In addition to lower commodity prices, there remains continued service industry concerns over the prevailing customer preference to return cash to shareholders through share buyback programs and dividends, or pay down debt, rather than grow production through the drill bit thereby limiting industry drilling activity.
Outlook
In 2023, crude oil prices have been impacted in the short term by the fear of a North American recession, concerns surrounding demand from a weak global economy, continued uncertainty concerning the ongoing war in Ukraine and most recently, by the Israel-Palestine conflict in the Middle East. Events such as these contribute to the volatility of commodity prices and the precise duration and extent of the adverse impacts of the current macroeconomic environment on Western's customers, operations, business and global economic activity, remains uncertain at this time. Additionally, the threatened shutdown and relocation of a portion of the Enbridge Line 5 pipeline has contributed to continued uncertainty regarding takeaway capacity. However, recent positive events such as the Trans Mountain pipeline expansion, now expected to be mechanically complete in 2023 and start operating in early 2024, the Coastal Gaslink pipeline project which is 98% complete, and the LNG Canada liquefied natural gas project in British Columbia expected to be online in 2025, may contribute to increased industry activity. Controlling fixed costs, maintaining balance sheet strength and flexibility, repaying debt and managing through a volatile market are priorities for the Company, as prices and demand for Western's services continue to improve.
As a result of the reduced industry activity in the third quarter of 2023 caused by lower commodity prices in the first eight months of the year, Western has reduced its capital budget for 2023 to $25 million, which represents a decrease of $5 million from Western's previous capital budget of $30 million. The revised budget is comprised of $8 million of expansion capital and $17 million of maintenance capital. Western will continue to manage its costs in a disciplined manner and make required adjustments to its capital program as customer demand changes. Currently, 15 of Western's drilling rigs and 19 of Western's well servicing rigs are operating.
As at September 30, 2023, Western had no amounts drawn on its $45.0 million senior secured credit facilities (the "Credit Facilities") and $6.3 million outstanding on its HSBC Facility, which matures on December 31, 2026. As at September 30, 2023, Western had $106.6 million outstanding on its second lien term loan facility with Alberta Investment Management Corporation (the "Second Lien Facility").
Energy service activity in Canada will be affected by the continued development of resource plays in Alberta and northeast British Columbia which will be impacted by continued pipeline construction, environmental regulations, and the level of investment in Canada. The January 2023 announcement that the government of British Columbia and the Blueberry River First Nations reached an agreement which provides a framework for how resource development may continue within the Blueberry River First Nations claim area, including the restoration and future development of land, water and natural resources, has facilitated an increase in 2023 drilling license approvals, which should lead to higher demand for Montney and Duvernay class rigs. With Western's recent drilling rig upgrade program substantially complete, the Company is well positioned to be the contractor of choice to supply drilling rigs in a tightening market. Western's upgraded drilling rigs have all worked for customers since the upgrades were completed. Western is also active with three fit for purpose drilling rigs in the Clearwater formation in northern Alberta. In the short term, the largest challenges facing the energy service industry are a lack of qualified field personnel and the restrained growth in customer drilling activity due to their continuing preference to return cash to shareholders through share buybacks, increased dividends and repayment of debt, rather than grow production. If commodity prices stabilize for an extended period and as customers strengthen their balance sheets by reducing debt levels, we expect that drilling activity will increase. In the medium term, Western's rig fleet is well positioned to benefit from the LNG Canada liquefied natural gas project and the Trans Mountain pipeline expansion. Western is an experienced deep horizontal driller in Canada, with an average well length of 6,908 meters drilled per well and an average of 12.7 operating days to drill per well for the nine months ended September 30, 2023. It remains Western's view that its upgraded drilling rigs and modern well servicing rigs, reputation for quality and capacity of the Company's rig fleet, and disciplined cash management provides Western with a competitive advantage.
7 Source: Baker Hughes Company, 2023 Rig Count monthly press releases. |
Non-IFRS Measures and Ratios
Western uses certain financial measures in this press release which do not have any standardized meaning as prescribed by International Financial Reporting Standards ("IFRS"). These measures and ratios, 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 and ratios have been described and presented in this press release to provide shareholders and potential investors with additional information regarding the Company. The non-IFRS measures and ratios used in this press release are identified and defined as follows:
Adjusted EBITDA and Adjusted EBITDA as a Percentage of Revenue
Adjusted 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 non-GAAP financial measure as it is used by management and other stakeholders, including current and potential investors, to analyze the Company's principal business activities prior to consideration of how Western's activities are financed and the impact of foreign exchange, income taxes and depreciation. Adjusted EBITDA provides an indication of the results generated by the Company's principal operating segments, which assists management in monitoring current and forecasting future operations, as certain non-core items such as interest and finance costs, taxes, depreciation and amortization, and other non-cash items and one-time gains and losses are removed. The closest IFRS measure would be net income (loss) for consolidated results.
Adjusted EBITDA as a percentage of revenue is a non-IFRS financial ratio which is calculated by dividing Adjusted EBITDA by revenue for the relevant period. Adjusted EBITDA as a percentage of revenue is a useful financial measure as it is used by management and other stakeholders, including current and potential investors, to analyze the profitability of the Company's principal operating segments.
The following table provides a reconciliation of net income (loss), as disclosed in the condensed consolidated statements of operations and comprehensive income, to Adjusted EBITDA:
Three months ended September 30 |
Nine months ended September 30 |
|||||||
(stated in thousands) |
2023 |
2022 |
2023 |
2022 |
||||
Net income (loss) |
(1,267) |
818 |
(4,691) |
32,415 |
||||
Income tax expense (recovery) |
(268) |
1,013 |
(931) |
3,035 |
||||
Income (loss) before income taxes |
(1,535) |
1,831 |
(5,622) |
35,450 |
||||
Add (deduct): |
||||||||
Gain on debt forgiveness |
- |
- |
- |
(49,357) |
||||
Depreciation |
10,283 |
9,744 |
30,831 |
29,652 |
||||
Stock based compensation |
574 |
795 |
2,212 |
1,135 |
||||
Finance costs |
2,789 |
2,946 |
8,710 |
11,428 |
||||
Other items |
(1,078) |
(517) |
(1,762) |
(620) |
||||
Adjusted EBITDA |
11,033 |
14,799 |
34,369 |
27,688 |
||||
Revenue per Operating Day
This non-IFRS measure is calculated as total drilling revenue for both Canada and the US respectively, divided by Operating Days in Canada and the US respectively. This calculation represents the average day rate by country charged to Western's customers.
Revenue per Service Hour
This non-IFRS measure is calculated as total well servicing revenue divided by total Service Hours. This calculation represents the average hourly rate charged to Western's customers.
Working Capital
This non-IFRS measure is calculated as current assets less current liabilities as disclosed in the Company's condensed consolidated financial statements.
Defined Terms
Average active rig count (contract drilling): Calculated as drilling rig utilization 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.
Average meters drilled per well: Defined as total meters drilled divided by the number of wells completed in the period.
Average Operating Days per well: Defined as total Operating Days divided by the number of wells completed in the period.
Drilling rig utilization: Calculated based on Operating 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 as total Service Hours divided by 217 hours per month per rig multiplied by the average rig count for the period as defined by the CAOEC industry standard.
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 Energy Contractors ("CAOEC");
- DecaNewton ("daN");
- International Financial Reporting Standards ("IFRS");
- 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 forward-looking statements and forward-looking information (collectively, "forward-looking information") within the meaning of applicable Canadian securities laws, as well as other information based on Western's current expectations, estimates, projections and assumptions based on information available as of the date hereof. All information and statements contained herein that are not clearly historical in nature constitute forward-looking information, and words and phrases such as "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 additions to property and equipment, anticipated future debt levels and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. This forward-looking 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: the business of Western; industry, market and economic conditions and any anticipated effects on Western; commodity pricing; the future demand for the Company's services and equipment, in particular, the Company's expectations regarding improved activity in 2023; Western's expectations regarding prevailing customer preferences; the effect of inflation and commodity prices on customer spending; the success of Western's drilling rig upgrade program; the potential impact of the current conflict in Ukraine on crude oil prices; the potential impact of a North American recession; the potential impact of a weak economy on demand for crude oil; the potential impact of the conflict in Israel on crude oil prices; revisions to the Company's capital budget for 2023, including the allocation of such budget; Western's plans for managing its capital program; the energy service industry and global economic activity; expectations with respect to the Trans Mountain pipeline expansion; the potential shutdown and relocation of the Enbridge Line 5 pipeline; expectations with respect to the Coastal GasLink pipeline project and LNG Canada facility; the impact of the Blueberry River First Nations decision; the development of Alberta and British Columbia resource plays; challenges facing the energy service industry; expectations as to the benefits of the LNG Canada natural gas project in British Columbia on the Company and its rig fleet; expectations relating to producer spending and activity levels for oilfield services; and the Company's ability to maintain a competitive advantage, including the factors and practices anticipated to produce and sustain such advantage.
The material assumptions that could cause results or events to differ from current expectations reflected in the forward-looking information in this press release include, but are not limited 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 impact of inflation; the continued business relationships between the Company and its significant customers; crude oil transport, pipeline and LNG export facility approval and development; that all required regulatory and environmental approvals can be obtained on the necessary terms and in a timely manner, as required by the Company; liquidity and the Company's ability to finance its operations; the effectiveness of the Company's cost structure and capital budget; 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 and the Company's competitive position therein; the ability of the Company's various business segments to access equipment (including spare parts and new technologies); global economic conditions and the accuracy of the Company's market outlook expectations for 2023 and in the future; the impact, direct and indirect, of the COVID-19 pandemic and geopolitical events, including the war in Ukraine and the conflict in Israel on Western's business, customers, business partners, employees, supply chain, other stakeholders and the overall economy; 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; that any required commercial agreements can be reached; that there are no unforeseen events preventing the performance of contracts and general business, economic and market conditions.
Although Western believes that the expectations and assumptions on which such forward-looking information is based on are reasonable, undue reliance should not be placed on the forward-looking information as Western cannot give any assurance that such will prove to be correct. By its nature, forward-looking information is subject to 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, volatility in market prices for crude oil and natural gas and the effect of this volatility on the demand for oilfield services generally; reduced exploration and development activities by customers and the effect of such reduced activities on Western's services and products; political, industry, market, economic, and environmental conditions in Canada, the US, Ukraine and globally; supply and demand for oilfield services relating to contract drilling, well servicing and oilfield rental equipment services; the proximity, capacity and accessibility of crude oil and natural gas pipelines and processing facilities; liabilities and risks inherent in oil and natural gas operations, including environmental liabilities and risks; changes to laws, regulations and policies; the ongoing geopolitical events in Eastern Europe and the duration and impact thereof; fluctuations in foreign exchange or interest rates; failure of counterparties to perform or comply with their obligations under contracts; regional competition and the increase in new or upgraded rigs; the Company's ability to attract and retain skilled labour; Western's ability to obtain debt or equity financing and to fund capital operating and other expenditures and obligations; the potential need to issue additional debt or equity and the potential resulting dilution of shareholders; uncertainties in weather and temperature affecting the duration of the service periods and the activities that can be completed; the Company's ability to comply with the covenants under the Credit Facilities, HSBC Facility and the Second Lien Facility and the restrictions on its operations and activities if it is not compliant with such covenants; Western's ability to protect itself from "cyber-attacks" which could compromise its information systems and critical infrastructure; disruptions to global supply chains; 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 discussed under the headings "Risk Factors" in Western's annual information form for the year ended December 31, 2022, which may be accessed through the SEDAR+ website at www.sedarplus.ca.
The forward-looking statements and information contained in this news 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. Any forward-looking statements contained herein are expressly qualified by this cautionary statement.
SOURCE Western Energy Services Corp.
Alex R.N. MacAusland, President and CEO, or Jeffrey K. Bowers, Senior VP Finance and CFO at 403.984.5916
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