WESTERN ENERGY SERVICES CORP. RELEASES SECOND QUARTER 2024 FINANCIAL AND OPERATING RESULTS

CALGARY, AB, July 23, 2024 /CNW/ - Western Energy Services Corp. ("Western" or the "Company") (TSX: WRG) announces the release of its second quarter 2024 financial and operating results.  Additional information relating to the Company, including the Company's financial statements and management's discussion and analysis ("MD&A") as at June 30, 2024 and for the three and six months ended June 30, 2024 and 2023 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.

Second Quarter 2024 Operating Results:

• Second quarter revenue of $43.0 million was consistent with the second quarter of 2023.  Contract drilling revenue totalled $27.1 million in the second quarter of 2024, which was $3.5 million (or 11%), lower than $30.6 million in the second quarter of 2023.  Production services revenue was $16.0 million for the three months ended June 30, 2024, an increase of $3.6 million (or 28%) as compared to $12.4 million in the same period of the prior year.  In the second quarter of 2024, revenue in Canada was positively impacted by higher commodity prices, which was offset by lower contract drilling activity in the US, compared to the second quarter of 2023 as described below:
  • In Canada, Operating Days of 656 days in the second quarter of 2024 were 80 days (or 14%) higher compared to 576 days in the second quarter of 2023.  Drilling rig utilization in Canada was 21% in the second quarter of 2024, compared to 19% in the same period of the prior year mainly due to improved crude oil prices and some of the Company's drilling rigs working longer into spring break-up than in 2023.  The Canadian Association of Energy Contractors ("CAOEC") industry Operating Days increased by 8% in the second quarter of 2024, compared to the second quarter of 2023, while the CAOEC industry average utilization increased by five percentage points to 30%¹ for the second quarter of 2024, compared to the CAOEC industry average utilization of 25% in the second quarter of 2023.  The increase in the CAOEC industry average utilization is attributable to a 12% decrease in the average number of drilling rigs registered with the CAOEC in the second quarter of 2024 compared to the second quarter of 2023.  If the number of registered drilling rigs with the CAOEC had not decreased, the CAOEC industry average utilization in the second quarter of 2024 would have been approximately 27%, two percentage points higher than the second quarter of 2023.  Revenue per Operating Day averaged $31,765 in the second quarter of 2024, a decrease of 4% compared to the same period of the prior year, mainly due to lower third party revenue;
  • In the United States ("US"), drilling rig utilization averaged 24% in the second quarter of 2024, compared to 37% in the second quarter of 2023, with Operating Days decreasing from 267 days in the second quarter of 2023 to 153 days in the second quarter of 2024 due to lower industry activity.  Average active industry rigs of 603² in the second quarter of 2024 were 16% lower compared to the second quarter of 2023.  Revenue per Operating Day for the second quarter of 2024 averaged US$30,016, a 6% decrease compared to US$31,896 in the same period of the prior year, mainly due to higher standby revenue in 2023; and
  • In Canada, service rig utilization was 33% in the second quarter of 2024, compared to 23% in the same period of the prior year, as Service Hours increased by 37% to 13,444 hours from 9,844 hours in the same period of the prior year, due to favorable weather resulting in improved activity.  Revenue per Service Hour averaged $1,016 in the second quarter of 2024 and was 3% lower than the second quarter of 2023, due to area specific rig requirements.
• The Company incurred a net loss of $5.1 million in the second quarter of 2024 ($0.15 net loss per basic common share) as compared to a net loss of $7.8 million in the second quarter of 2023 ($0.23 net loss per basic common share).  The change can mainly be attributed to a $1.2 million increase in Adjusted EBITDA, a $0.9 million decrease in stock based compensation expense and a $0.4 million decrease in finance costs.  Administrative expenses in the second quarter of 2024 were $1.8 million higher than the second quarter of 2023, due to $1.8 million of one-time reorganization costs incurred in 2024.
• Adjusted EBITDA of $5.3 million in the second quarter of 2024 was $1.2 million (or 27%) higher compared to $4.1 million in the second quarter of 2023.  The increase in Adjusted EBITDA in the second quarter of 2024 was due to higher drilling and production services revenue in Canada, offset partially by $1.8 million of one-time reorganization costs incurred.  Normalizing for the $1.8 million of one-time reorganization costs, Adjusted EBITDA would have totalled $7.1 million for the second quarter of 2024, an increase of 73% from the second quarter of 2023. 
• Second quarter additions to property and equipment of $5.6 million in 2024 compared to $6.7 million in the second quarter of 2023, consisting of $4.2 million of expansion capital related to rig upgrades and $1.4 million of maintenance capital.

Year to Date 2024 Operating Results:

• Revenue for the six months ended June 30, 2024 decreased by $17.2 million (or 14%), to $105.0 million compared to $122.2 million in the same period of 2023.  Contract drilling revenue totalled $66.8 million for the six months ended June 30, 2024, which was $21.9 million (or 25%), lower than $88.7 million in the same period of the prior year.  Production services revenue totalled $38.4 million for the six months ended June 30, 2024, an increase of $4.6 million (or 14%) as compared to $33.8 million in the same period of the prior year.  In the first half of 2024, revenue was negatively impacted by lower activity in contract drilling in Canada and the US due to lower commodity prices in the first part of 2024, specifically natural gas prices, but positively impacted by higher production services activity in 2024, compared to the first half of 2023 as described below:
  • In Canada, Operating Days of 1,609 days for the six months ended June 30, 2024 were 250 days (or 13%) lower compared to 1,859 days for the six months ended June 30, 2023.  Drilling rig utilization in Canada was 26% for the six months ended June 30, 2024, compared to 30% in the same period of the prior year mainly due to customers cancelling or deferring their programs into the second half of 2024, as a result of lower natural gas prices in 2023 that continued into 2024.  The CAOEC industry Operating Days increased by 2% in the first half of 2024, compared to the first half of 2023, while the CAOEC industry average utilization increased five percentage points to 40%³ for the six months ended June 30, 2024, compared to the CAOEC industry average utilization of 35% in the same period of the prior year.  The increase in the CAOEC industry average utilization is attributable to a 12% decrease in the average number of drilling rigs registered with the CAOEC in the first half of 2024 compared to the first half of 2023.  If the number of registered drilling rigs with the CAOEC had not decreased, the CAOEC industry average utilization for the six months ended June 30, 2024 would have been approximately 36%, one percentage point higher than the six months ended June 30, 2023.  Revenue per Operating Day for the six months ended June 30, 2024 averaged $33,226, which was consistent with the same period of the prior year;
  • In the US, drilling rig utilization averaged 25% for the six months ended June 30, 2024, compared to 41% in the same period of the prior year, with Operating Days decreasing from 594 days in the six months ended June 30, 2023 to 317 days in the same period of 2024 due to lower industry activity.  Average active industry rigs of 613⁴ for the six months ended June 30, 2024 were 17% lower compared to the six months ended June 30, 2023.  Revenue per Operating Day for the six months ended June 30, 2024 averaged US$30,967, a 5% decrease compared to US$32,515 in the same period of the prior year, mainly due to higher standby revenue in 2023; and
  • In Canada, service rig utilization of 38% for the six months ended June 30, 2024 was higher than 33% in the same period of the prior year with Service Hours increasing by 13% from 28,097 hours in 2023 to 31,843 hours in 2024.  Revenue per Service Hour averaged $1,040 for the six months ended June 30, 2024 and was consistent with the six months ended June 30, 2023.
• The Company incurred a net loss of $3.7 million for the six months ended June 30, 2024 ($0.11 net loss per basic common share) as compared to a net loss of $3.4 million in the same period in 2023 ($0.10 net loss per basic common share).  The change can mainly be attributed to a $1.3 million decrease in stock based compensation expense, a $0.7 million decrease in finance costs, and a $0.4 million increase in income tax recovery, which were partially offset by a $2.8 million decrease in Adjusted EBITDA.  Administrative expenses for the six months ended June 30, 2024 were $2.4 million higher than the same period of 2023, due to higher employee related costs including one-time reorganization costs of $1.8 million incurred in 2024.
• Adjusted EBITDA of $20.5 million for the six months ended June 30, 2024 was $2.8 million (or 12%) lower compared to $23.3 million in the same period of 2023 and included one-time reorganization costs of $1.8 million.  After normalizing for the one-time reorganization costs, Adjusted EBITDA for the six months ended June 30, 2024 would have totalled $22.3 million, a decrease of $1.0 million (or 4%) from the same period in the prior year.  Adjusted EBITDA in 2024 was lower due to lower drilling activity in Canada and the US, as well as lower pricing in the US.
• Year to date 2024 additions to property and equipment of $7.5 million compared to $11.9 million in the same period of 2023, consisting of $4.8 million of expansion capital related to rig upgrades and $2.7 million of maintenance capital.
• On March 22, 2024, the Company extended the maturity of its $35.0 million syndicated revolving credit facility (the "Revolving Facility") and its $10.0 million committed operating facility (the "Operating Facility" and together the "Credit Facilities") from May 18, 2025 to the earlier of (i) six months prior to the maturity date of the Second Lien Facility (as defined in this press release) which is currently November 18, 2025, or (ii) March 21, 2027 if the Second Lien Facility is extended.  The total commitments under the Credit Facilities are unchanged and there were no changes to the Company's financial covenants, which are described on page 9 of the Company's second quarter 2024 MD&A under "Liquidity and Capital Resources".

Selected Financial Information
(stated in thousands, except share and per share amounts)
	Three months ended June 30									Six months ended June 30
Financial Highlights	2024		2023		Change					2024			2023		Change
Revenue	43,033		42,954			-				105,015			122,193			(14 %)
Adjusted EBITDA^(1)	5,259		4,140			27 %				20,478			23,336			(12 %)
Adjusted EBITDA as a percentage of revenue^(1)	12 %		10 %			20 %				20 %			19 %			5 %
Cash flow from operating activities	19,260		25,373			(24 %)				27,062			31,818			(15 %)
Additions to property and equipment	5,635		6,705			(16 %)				7,537			11,870			(37 %)
Net loss	(5,136)		(7,845)			35 %				(3,681)			(3,424)			(8 %)
– basic and diluted net loss per share	(0.15)		(0.23)			35 %				(0.11)			(0.10)			(10 %)
Weighted average number of shares
– basic and diluted	33,843,015		33,841,324			-				33,843,015			33,841,324			-
Outstanding common shares as at period end	33,843,015		33,841,324			-				33,843,015			33,841,324			-

(1)      See "Non-IFRS Measures and Ratios" included in this press release.

				Three months ended June 30															Six months ended June 30
Operating Highlights^(2)					2024		2023                      Change														2024			2023			Change
Contract Drilling
Canadian Operations:
Contract drilling rig fleet:
– Average active rig count					7.2			6.3							14 %					8.8			10.3						(15 %)
Operating Days					656			576							14 %					1,609			1,859						(13 %)
Revenue per Operating Day^(3)					31,765			33,218							(4 %)					33,226			33,258						-
Drilling rig utilization					21 %			19 %							11 %					26 %			30 %						(13 %)
CAOEC industry average utilization – Operating Days^(4)					30 %			25 %							20 %					40 %			35 %						14 %
Average meters drilled per well					7,104			8,367							(15 %)					7,550			6,828						11 %
Average Operating Days per well					12.0			16.1							(25 %)					12.9			14.0						(8 %)
United States Operations:
Contract drilling rig fleet:
– Average active rig count					1.7			2.9							(41 %)					1.7			3.3						(48 %)
Operating Days					153			267							(43 %)					317			594						(47 %)
Revenue per Operating Day (US$)^(3)					30,016			31,896							(6 %)					30,967			32,515						(5 %)
Drilling rig utilization					24 %			37 %							(35 %)					25 %			41 %						(39 %)
Average meters drilled per well					4,818			3,272							47 %					5,368			3,395						58 %
Average Operating Days per well					12.3			11.9							3 %					14.0			13.1						7 %
Production Services
Well servicing rig fleet:
– Average active rig count					20.7			15.1							37 %					24.5			21.6						13 %
Service Hours					13,444			9,844							37 %					31,843			28,097						13 %
Revenue per Service Hour^(3)					1,016			1,052							(3 %)					1,040			1,039						-
Service rig utilization					33 %			23 %							43 %					38 %			33 %						15 %

(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 days. From June 30, 2023 to June 30, 2024, there were 54 drilling rigs deregistered with the CAOEC, which resulted in higher industry average utilization in the second quarter of 2024 and for the six months ended June 30, 2024.

Financial Position at (stated in thousands)	June 30, 2024		December 31, 2023	June 30, 2023
Working capital^(1)	22,203		20,125	19,576
Total assets	433,354		442,933	456,746
Long term debt – non current portion	106,912		111,174	118,109

(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 41 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 June 30
	2024				2023
Rig class^(1)	Canada	US	Total		Canada	US	Total
Cardium	11	-	11		11	1	12
Montney	18	1	19		18	1	19
Duvernay	5	6	11		5	6	11
Total marketed drilling rigs^(2)	34	7	41		34	8	42
Total owned drilling rigs	48	7	55		48	8	56

(1)      See "Contract Drilling Rig Classifications" included in this press release.

(2)      Source: CAOEC Contractor Summary as at July 23, 2024.

Production Services

Production services provides well servicing and oilfield equipment rentals in Canada. Western operates 63 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 June 30
Mast type	2024	2023
Single	28	30
Double	27	27
Slant	8	8
Total owned well servicing rigs	63	65

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 six months ended June 30, 2024 and 2023.

			Three months ended June 30									Six months ended June 30
			2024		2023			Change				2024			2023				Change
Average crude oil and natural gas prices^(1)(2)
Crude Oil
West Texas Intermediate (US$/bbl)			80.57		73.80			9 %				78.76			74.97				5 %
Western Canadian Select (CDN$/bbl)			91.54		78.95			16 %				84.68			74.04				14 %
Natural Gas
30 day Spot AECO (CDN$/mcf)			1.22		2.52			(52 %)				1.74			2.94				(41 %)
Average foreign exchange rates^(2)
US dollar to Canadian dollar			1.37		1.34			2 %				1.36			1.35				1 %

(1)	See "Abbreviations" included in this press release.
(2)	Source: Sproule June 30, 2024, Price Forecast, Historical Prices.

West Texas Intermediate on average increased by 9% and 5% respectively, for the three and six months ended June 30, 2024, compared to the same periods in the prior year.  Pricing on Western Canadian Select crude oil increased by 16% and 14% respectively, for the three and six months ended June 30, 2024, compared to the same periods in the prior year.  In 2024, crude oil prices improved due to tighter crude oil supplies resulting from OPEC production cuts and ongoing geopolitical conflicts in Ukraine and the Middle East.  However, natural gas prices in Canada declined in 2024 due to lower demand, as the 30-day spot AECO price decreased by 52% and 41% respectively, for the three and six months ended June 30, 2024, compared to the same periods of the prior year.  Additionally, the US dollar to the Canadian dollar foreign exchange rate for the three and six months ended June 30, 2024 strengthened by 2% and 1% respectively, with the same periods in the prior year.

Despite improved crude oil prices in the first half of 2024 in both the US and Canada, industry drilling activity weakened in the US.  As reported by Baker Hughes Company⁷, the number of active drilling rigs in the US decreased by approximately 14% to 581 rigs as at June 30, 2024, as compared to 674 rigs at June 30, 2023 and averaged 603 rigs during the second quarter of 2024, compared to 719 rigs in the second quarter of 2023.  Similarly, the average number of active drilling rigs in the US decreased by approximately 17% in the first half of 2024 to average 613 rigs compared to 740 rigs in the first half of 2023.  In Canada there were 182 active rigs in the Western Canadian Sedimentary Basin ("WCSB") at June 30, 2024, compared to 179 active rigs as at June 30, 2023, representing an increase of approximately 2%, however the CAOEC⁸ reported that for drilling in Canada, the total number of Operating Days in the WCSB for the three months ended June 30, 2024, were 8% higher than the same period in the prior year.  Similarly, for the six months ended June 30, 2024, the total number of Operating Days in the WCSB were 2% higher than the same period of the prior year.

Outlook

In 2024, commodity prices are being impacted in the short term by concerns surrounding demand from continued uncertainty concerning the ongoing conflicts in Ukraine and in the Middle East.  In addition, OPEC announced a gradual unwinding of production cuts.  Events such as these contribute to the volatility of commodity prices.  The precise duration and extent of the adverse impacts of the current macroeconomic environment and global economic activity on Western's customers and operations remains uncertain at this time.  Additionally, the threatened shutdown and relocation of a portion of the Enbridge Line 5 pipeline and the recent challenge and notice of civil claim related to the Blueberry River First Nations agreement in British Columbia by the Treaty 8 nations, have contributed to continued uncertainty regarding takeaway capacity and resource development.  However, the Trans Mountain pipeline expansion commenced operations as of May 1, 2024 bringing much needed takeaway capacity to the market.  The Trans Mountain pipeline project, the Coastal GasLink pipeline project, which is mechanically complete and expected to be online in 2025, and the LNG Canada liquefied natural gas project in British Columbia, now more than 85% complete and 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 are expected to continue to improve.

As previously announced, Western's board of directors has approved a capital budget for 2024 of $23 million, comprised of $8 million of expansion capital and $15 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, 16 of Western's drilling rigs and 19 of Western's well servicing rigs are operating.

As at June 30, 2024, Western had no amounts drawn on its Credit Facilities and $5.3 million outstanding on its committed term non revolving facility (the "HSBC Facility"), which matures on December 31, 2026.  As at June 30, 2024, Western had $98.8 million outstanding on its second lien secured term loan with Alberta Investment Management Corporation (the "Second Lien Facility"), which matures on May 18, 2026.  Western will continue to focus its efforts on debt reduction in 2024.

Energy service activity in Canada will be affected by volatile commodity prices, the continued development of resource plays in Alberta and northeast British Columbia, ongoing pipeline completions that will increase takeaway capacity, environmental regulations, and the level of investment in Canada.  With Western's upgraded drilling rigs, the Company is well positioned to be the contractor of choice to supply drilling rigs in a tightening market.  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 volatile commodity prices 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, then 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 increased drilling and production services activity expected to be generated by the LNG Canada liquefied natural gas project and the Trans Mountain pipeline expansion.  The total rig fleet in the WCSB has decreased from 439 drilling rigs at June 30, 2023 to 385 drilling rigs as of July 23, 2024, representing a decrease of 54 drilling rigs, or 12%, which reduces the supply of drilling rigs for such projects.  Western is an experienced deep horizontal driller in Canada, with an average well length of 7,550 meters drilled per well and an average of 12.9 Operating Days to drill per well for the six months ended June 30, 2024.  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.

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 loss, as disclosed in the condensed consolidated statements of operations and comprehensive loss, to Adjusted EBITDA:

	Three months ended June 30			Six months ended June 30
(stated in thousands)		2024	2023		2024	2023
Net loss		(5,136)	(7,845)		(3,681)	(3,424)
Income tax recovery		(1,621)	(1,830)		(1,093)	(663)
Loss before income taxes		(6,757)	(9,675)		(4,774)	(4,087)
Add (deduct):
Depreciation		10,075	10,252		20,598	20,548
Stock based compensation		(161)	762		276	1,638
Finance costs		2,494	2,879		5,150	5,921
Other items		(392)	(78)		(772)	(684)
Adjusted EBITDA		5,259	4,140		20,478	23,336

Revenue per Operating Day

This non-IFRS measure is calculated as 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 well servicing revenue divided by 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 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");
• Canadian Association of Energy Contractors ("CAOEC");
• DecaNewton ("daN");
• International Financial Reporting Standards ("IFRS");
• Pounds ("lbs");
• Thousand cubic feet ("mcf"); and
• Western Canadian Sedimentary Basin ("WCSB").

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 and its customers; commodity pricing; the future demand for the Company's services and equipment; the effect of inflation and commodity prices on energy service activity; expectations with respect to customer spending; the expected impact of Western's recently upgraded drilling rigs; the potential continued impact of the current conflicts in Ukraine and the Middle East on crude oil prices; the Company's capital budget for 2024, including the allocation of such budget; Western's plans for managing its capital program; the energy service industry and global economic activity; expectations of increased takeaway capacity with respect to the completion of 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 recent challenge and notice of civil claim related to the Blueberry River First Nations decision by the Treaty 8 nations; the development of Alberta and British Columbia resource plays; expectations relating to the increase in takeaway capacity resulting from ongoing pipeline completions; challenges facing the energy service industry; the Company's focus on debt reduction; expectations with respect to increased drilling activity; 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 2024 and in the future; the impact, direct and indirect, of epidemics, pandemics, other public health crisis and geopolitical events, including the conflicts in Ukraine and the Middle East 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 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 Middle East 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, 2023, which is available under the Company's SEDAR+ profile at www.sedarplus.ca. 

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.  Any forward-looking statements contained herein are expressly qualified by this cautionary statement.

¹ Source: CAOEC, monthly Contractor Summary.

² Source: Baker Hughes Company, North America Quarterly Rig Count.

³ Source: CAOEC, monthly Contractor Summary.

⁴ Source: Baker Hughes Company, North America Quarterly Rig Count.

⁵ Source: CAOEC Drilling Contractor Summary as at July 23, 2024.

⁶ Source: CAOEC Well Servicing Fleet List as at July 23, 2024.

⁷ Source: Baker Hughes Company, 2024 Rig Count monthly press releases.

⁸ Source: CAOEC, monthly Contractor Summary.

SOURCE Western Energy Services Corp.

For more information, please contact: Alex R.N. MacAusland, President & CEO, or Gavin Lane, CFO at 403.984.5916