Civeo Corp 10-K

ITEM 1. Business Available Information We maintain a website with the address of www.civeo.com. We are not including the information contained on our website as a part of, or incorporating it by reference into, this annual report. We file or furnish annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (the SEC). We make available free of charge through our website our Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the SEC. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us, and our filings are available on the Internet at www.sec.gov and free of charge upon written request to our corporate secretary at the address shown on the cover page of this annual report. Our Company We provide a suite of hospitality services for our guests in the natural resources industry, including lodging, catering and food service, housekeeping and maintenance at accommodation facilities that we or our customers own. In many cases, we provide services that support the day-to-day operations of these facilities, such as laundry, facility management and maintenance, water and wastewater treatment, power generation, communication systems, security and logistics. We also manage development activities for workforce accommodation facilities, including site selection, permitting, engineering and design, manufacturing management and site construction, along with providing hospitality services once the facility is constructed. We primarily operate in some of the world’s most active oil, metallurgical (met) coal, liquefied natural gas (LNG) and iron ore producing regions, where, in many cases, traditional accommodations and related infrastructure often are not accessible, sufficient or cost effective. Our customers include major and independent oil companies, mining companies, engineering companies and oilfield and mining service companies. Our extensive suite of services enables us to meet the unique needs of each of our customers, while providing comfortable accommodations for their employees. Our customers are able to outsource their accommodations needs to a single supplier, maintaining employee welfare and satisfaction while focusing their investment on their core resource production efforts. Our Company is built on the foundation of the following core values: Safety, Respect, Care, Excellence, Integrity and Collaboration. We put the safety of our employees and guests above all other concerns. We care about our people, guests, customers, communities and the environment, and we deliver excellent service with passion and pride. We act with integrity and collaborate with our people, communities, customers and partners. We take an active role working to minimize the environmental impact of our operations through a number of sustainable initiatives. We also have a focus on water conservation and utilize alternative water supply options such as recycling and rainwater collection and use. By building infrastructure such as wastewater treatment and water treatment facilities to recycle gray and black water on some of our sites, we are able to gain cost efficiencies as well as reduce the use of trucks related to water and wastewater hauling, which in turn, reduces our carbon footprint. In our Australian villages, we utilize passive-solar-design principles and smart-switching systems to reduce the need for electricity related to heating and cooling. Our hospitality services span the lifecycle of customer projects, from the initial exploration and resource delineation to long-term production. Initially, as customers assess the resource potential and determine how they will develop it, they typically need our hospitality services for a limited number of employees for an uncertain duration of time. Our fleet of mobile assets is well-suited to support this initial exploratory stage as customers evaluate their development and construction plans. As development of the resource begins, we are able to serve their needs through either: (i) our fleet of mobile assets, particularly for shorter term projects such as pipeline construction and seasonal drilling programs, (ii) our scalable lodge or village model, or (iii) our integrated services model in customer-owned facilities. As projects grow and headcount needs increase, we are able to meet our customers growing needs at our accommodation facilities or with our hospitality services. By providing infrastructure support and hospitality services early in the project lifecycle, we are well positioned to continue to service our customers throughout the production phase, which typically lasts decades. We own and operate 24 lodges and villages with approximately 26,000 rooms. We operate approximately 14,200 rooms owned by our customers. Additionally, in Canada, we also offer a fleet of mobile assets which serve shorter term projects, such as pipeline construction. We have long-standing relationships with many of our customers, many of whom are, or are affiliates of, large, investment-grade energy and mining companies. 3 For the years ended December 31, 2023, 2022 and 2021, we generated $700.8 million, $697.1 million and $594.5 million in revenues and $39.5 million, $17.0 million and $6.1 million in operating income, respectively. The majority of our operations, assets and income are derived from the hospitality services provided at lodges and villages we own that have historically been contracted by our customers under multi-year, take-or-pay or exclusivity contracts. The hospitality services we provide at these facilities generated 63% of our revenue for the year ended December 31, 2023. Important performance metrics include revenue related to our major properties, average daily rates and aggregate billed rooms. The table below summarizes these key statistics for the periods presented in this annual report. Year Ended December 31, 2023 2022 2021 (In thousands, except for room counts and average daily rate) Accommodation Revenue (1) Canada $ 266,926 $ 279,455 $ 239,526 Australia 177,834 152,714 145,335 Other 11,205 3,058 5,437 Total Accommodation Revenue $ 455,965 $ 435,227 $ 390,298 Mobile Facility Rental Revenue (2) Canada $ 61,899 $ 96,400 $ 62,856 Other — 18,367 14,486 Total Mobile Facility Rental Revenue $ 61,899 $ 114,767 $ 77,342 Food Service and Other Services Revenue (3) Canada $ 23,970 $ 20,142 $ 18,996 Australia 158,929 125,538 105,739 Other 42 90 50 Total Food Service and Other Services Revenue $ 182,941 $ 145,770 $ 124,785 Manufacturing Revenue (4) Other $ — $ 1,288 $ 2,038 Total Manufacturing Revenue $ — $ 1,288 $ 2,038 Total Revenue $ 700,805 $ 697,052 $ 594,463 Average Daily Rates for Lodges and Villages (5) Canada $ 97 $ 100 $ 99 Australia $ 75 $ 75 $ 79 Total Billed Rooms for Lodges and Villages (6) Canada 2,710,784 2,759,521 2,404,880 Australia 2,371,763 2,024,068 1,846,882 Average Exchange Rate Canadian dollar to U.S. dollar $ 0.74 $ 0.77 $ 0.80 Australian dollar to U.S. dollar $ 0.66 $ 0.69 $ 0.75 (1) Includes revenues related to lodge and village rooms and hospitality services for Civeo owned rooms for the periods presented. (2) Includes revenues related to mobile assets for the periods presented. (3) Includes revenues related to food service, laundry and water and wastewater treatment services, and facilities management for the periods presented. (4) Includes revenues related to modular construction and manufacturing services for the periods presented. Civeo's remaining manufacturing operations in Louisiana were sold in the fourth quarter of 2022. (5) Average daily rate is based on billed rooms and accommodation revenue for Civeo owned rooms during the periods presented. (6) Billed rooms represents total billed days for Civeo owned rooms for the periods presented. 4 Our History Our history is one of identifying customer and market needs and developing economic solutions. Our historical experience in Canada began in small, mobile camps and evolved into owning and managing large scale remote accommodations. In Australia, our operations originated with a similar build-own-operate model as we operate in our Canadian lodges, growing up to our current eight owned villages. Since then and with the addition of an acquisition, we have evolved our service delivery to include operating customer-owned locations with the same hospitality services that we provide at our owned villages. Our Canadian operations, founded in 1977, began by providing modular rental housing to energy customers, primarily supporting drilling rig crews in the Western Canadian Sedimentary Basin. Over the next decade, we acquired a food service operation, enabling us to provide a more comprehensive accommodation solution. Through our experience with Syncrude’s Mildred Lake Village, a 2,100 bed facility that we operated and managed for them for nearly 20 years, we recognized the need for a premium, and more permanent, solution for workforce accommodations and hospitality services in the Canadian oil sands region. Pursuing this strategy, we opened PTI Lodge in 1998, one of the first independent lodging facilities in the region. In 2018, we acquired Noralta Lodge Ltd. (Noralta), which provided remote hospitality services in Alberta, Canada (the Noralta Acquisition) through eleven lodges comprising over 5,700 owned rooms and 7,900 total rooms. Over time, we have developed into Canada’s largest third-party provider of accommodations and hospitality services in the Canadian oil sands region. During 2015, we entered the Canadian LNG market with the construction of our Sitka Lodge. LNG Canada (LNGC), a joint venture among Shell Canada Energy, an affiliate of Shell plc (40 percent), and affiliates of PETRONAS, through its wholly-owned entity, North Montney LNG Limited Partnership (25 percent), PetroChina (15 percent), Mitsubishi Corporation (15 percent) and Korea Gas Corporation (5 percent), is currently constructing a liquefaction and export facility in Kitimat, British Columbia (Kitimat LNG Facility). The Kitimat LNG Facility is nearing completion and expected to be operational in 2024. Our Sitka Lodge is well positioned to serve construction activity at the Kitimat LNG facility, as well as portions of the related pipeline construction activity. With the acquisition of our Australian business in December 2010, we began providing hospitality services to support the Australian natural resources industry through our villages located in Queensland, New South Wales and Western Australia. Like Canada, our Australian business has a long-history of taking care of customers in remote regions, beginning with our initial Moranbah Village in 1996, and has grown to become Australia’s largest independent provider of hospitality services for people working in remote locations. Our Australian business was the first to introduce resort-style accommodations to the mining sector, adding landscaping, outdoor kitchens, pools, fitness centers and, in some cases, taverns. In 2019, we acquired Action Industrial Catering (Action), a provider of catering and managed services (which we refer to as our integrated services business) to the mining industry in Western Australia. The Action acquisition enhanced our service offering, expanded our geographic footprint, added exposure to new commodities in Australia and underlines our focus on pursuing growth opportunities that fit within our core competencies and strategic direction. Our Customers We provide our hospitality services to customers in the natural resources industry. Our scalable facilities provide long-term and temporary workforce accommodations where, in many cases, traditional accommodations and related infrastructure often are not accessible, sufficient or cost effective. Through our wide range of hospitality services offerings, we are able to identify, solve and implement solutions and services that enhance the guest experience and reduce the customer’s total cost of housing a workforce in a remote operating location. In addition to lodging, catering and food service, housekeeping and maintenance at accommodation facilities that we or our customers own, our hospitality services have evolved to include fitness centers, water and wastewater treatment, laundry service and many other enhancements. Our customers either own their accommodations assets or outsource them. Customers may choose to own their accommodations assets because (i) their natural resource project is the only source of demand for rooms in the region; (ii) they believe in the long-term nature of their resource project; and/or (iii) they desire to maintain control over the supply of rooms for their project. Where customers have chosen to own their accommodations assets, customers usually subcontract the 5 management of the facility and the provision of the hospitality services to a third-party provider, such as Civeo through our integrated services model in customer-owned facilities. Historically, Canadian oil sands developers and Australian mining companies built and owned the accommodations necessary to house their personnel in these remote regions because local labor and third-party owned rooms were not available. Over the past 20 years, and increasingly over the past 10 years, some customers have moved away from the insourcing business model for a portion of their accommodation needs as they recognize that owning accommodations and providing the related hospitality services are non-core investments for their business. The accommodations outsourcing model is effective in regions in which multiple customers have on-going or prospective projects where third-party owned and operated accommodations assets can service multiple customers. This allows those customers to share some of the costs associated with their peak accommodations needs, including infrastructure (power, water, sewer and information technology) and central dining and recreation facilities. The Canadian oil sands region and the Queensland Bowen Basin region are two geographic areas that fit this market dynamic. Initial demand for our hospitality services has historically been driven by our customers’ capital spending programs related to the construction and development of natural resource projects and associated infrastructure, as well as the exploration for oil and natural gas. Long-term demand for our services has been driven by natural resource production, maintenance and operation of those facilities as well as expansion of those sites. In general, industry capital spending programs are based on the outlook for commodity prices, production costs, economic growth, global commodity supply/demand, estimates of resource production and the expectations of our customers' shareholders. As a result, demand for our hospitality services is largely sensitive to expected commodity prices, principally related to oil, met coal, LNG and iron ore, and the resultant impact of these commodity price expectations on our customers’ spending. Other factors that can affect our business and financial results include the general global economic environment, including inflationary pressures, supply chain disruptions and labor shortages, volatility affecting the banking system and financial markets, availability of capital to the natural resource industry and regulatory changes in Canada, Australia and other markets, including governmental measures introduced to fight climate change. We believe that our existing industry divides accommodations into two primary types: (i) lodges and villages and (ii) mobile assets. Civeo is principally focused on hospitality services at lodges and villages. Lodges and villages typically contain a larger number of rooms and require more time and capital to develop. These facilities typically have dining areas, meeting rooms, recreational facilities, pubs and taverns and landscaped grounds where weather permits. Lodges and villages are generally supported by multi-year, take-or-pay or exclusivity contracts. These facilities are designed to serve the long-term needs of customers in developing and producing their natural resource developments. Mobile assets are designed to follow customers’ activities and can be deployed rapidly to scale. They are often used to support conventional and in-situ drilling crews, as well as pipeline and seismic crews, and are contracted on a project-by-project, well-by-well or short-term basis. Oftentimes, customers will initially require mobile assets as they evaluate or initially develop a field or mine. Mobile asset projects can be dedicated and committed to a single customer or project or can serve multiple customers. Our Competitors The accommodation facilities market supporting the natural resource industry is segmented into competitors that serve components of the overall value chain, but very few offer the entire suite of hospitality services to customers. We estimate that customer-owned rooms represent over 50% of the market. Engineering firms such as Bechtel and Fluor often design accommodations facilities. Many public and private firms, such as ATCO Structures & Logistics Ltd. (ATCO), Dexterra Group Inc. (Dexterra), Alta-Fab Structures Ltd. (Alta-Fab) and Northgate Industries Ltd. (Northgate), build modular accommodations for sale. Dexterra, Black Diamond Group Limited (Black Diamond), ATCO, Royal Camp Services Ltd. and Target Hospitality primarily own and lease units to customers and, in some cases, provide facility management services, usually on a shorter-term basis with a more limited number of rooms, similar to our mobile assets business. Facility service companies, such as Aramark Corporation (Aramark), Sodexo Inc. (Sodexo), Compass Group PLC (Compass Group) and Cater Care, typically do not invest in and own the accommodations assets, but will provide hospitality services at third-party or customer-owned facilities. Canada Overview During the year ended December 31, 2023, we generated approximately 50% of our revenue from our Canadian operations. We are western Canada’s largest provider of hospitality services for people working in remote locations. We provide our services through our lodges and mobile assets and at customer-owned locations. Our hospitality services support 6 workforces in the Canadian LNG and oil sands markets and in a variety of oil and natural gas drilling, mining, pipeline and related natural resource applications. Canadian Market Demand for our hospitality services in the Canadian market is largely driven by customer capital spending, which is greatly influenced by current and future commodity prices. In the Canadian oil sands region, demand is primarily influenced by the longer-term outlook for oil prices rather than current energy prices, given the multi-year production life of oil sands projects and the capital investment associated with development of such large-scale projects. Demand for our Canadian lodges is secondarily impacted by oil takeaway capacity which influences the net price our customers receive for their oil production. Spending on the construction and development of new projects generally decreases as the outlook for oil prices decreases. However, spending on current operations and maintenance has historically reacted less quickly and less severely to changes in oil prices, as customers consider their cash operating costs, rather than overall full-cycle returns. Likewise, construction and expansion projects already underway have also been less sensitive to commodity price decreases, as customers generally focus on completion and incremental costs. Natural gas prices also influence oil sands activity as an input cost: as natural gas prices fluctuate, a significant component of our customers’ operating costs fluctuate as well. Another factor that influences demand for our hospitality services in the Canadian oil sands region is the type of customer project we are supporting. Generally, Canadian customers require larger workforces during construction and expansionary periods, and therefore have higher demand for our rooms and services. Operational and maintenance headcounts are typically a fraction, 20% to 25%, of the headcounts experienced during construction. In addition, proximity to customer activity and availability of customer-owned and competitor-owned rooms influences the rental demand of our rooms in the Canadian oil sands region. Typically, customers prefer to first utilize their own rooms on location, and if such customer-owned rooms are insufficient, customers prefer to avoid busing their workforces to housing more than 45 kilometers away. The Athabasca oil sands are located in northern Alberta, an area that is very remote, with a limited local labor supply. Of Canada’s approximately 40 million residents, approximately half of the population lives in ten cities, while approximately 12% of the population lives in Alberta and less than 1% of the population lives within 100 kilometers of the oil sands activity. The local municipalities, of which Fort McMurray is the largest, have limited infrastructure to respond to workforce accommodation demands and are a significant driving distance from many of the oil sands projects. As such, the workforce accommodations market provides a cost-effective solution to the challenge of staffing large oil sands projects by sourcing labor largely throughout Canada to work on a rotational basis. With respect to LNG and related pipeline activity in Canada, a number of multinational energy companies believe there is a potential to export LNG from Canada to meet the increasing global LNG demand, particularly in Asia. Currently, Western Canada does not have any operational LNG export facilities. The Kitimat LNG Facility is nearing completion and expected to be operational in 2024. The population of Kitimat and the surrounding area is approximately 9,000 people, whereas the LNGC project had almost 7,500 workers at its peak to construct the Kitimat LNG Facility. Accordingly, British Columbia LNG activity and related pipeline projects are a material driver of activity for our Sitka Lodge, as well as for our mobile assets, which are contracted to serve designated portions of the related pipeline construction activity. The majority of our contracted commitments associated with the Coastal GasLink Pipeline (CGL), the pipeline constructed to transport natural gas feedstock to LNGC, were completed in the fourth quarter of 2023. See "Canada-Canadian British Columbia Lodge" for more information. LNG investment and activity in Western Canada, and related demand for hospitality services, is influenced by the global prices for LNG, which are largely tied to global oil prices, global supply/demand dynamics for LNG and Western Canadian wellhead prices for natural gas. Utilization of our existing Canadian capacity and any future expansions will largely depend on continued LNG and oil sands spending related to existing production, maintenance activities and potential future expansion of existing projects. 7 Canadian Oil Sands Lodges During the year ended December 31, 2023, activity in the Athabasca oil sands region generated approximately 67% of our Canadian revenue, or 34% of our consolidated revenue. The oil sands region continues to represent one of the world’s largest reserves for heavy oil. Our Wapasu Creek, Athabasca, Beaver River, Fort McMurray Village, Grey Wolf, Hudson, and Borealis lodges are focused on the northern region of the Athabasca oil sands, where customers primarily utilize surface mining to extract bitumen. Oil sands mining operations are characterized by large capital requirements, large reserves, larger personnel requirements, long-term reserve lives, very low exploration or reserve risk and relatively lower cash operating costs per barrel of bitumen produced. Our Conklin, Anzac, Red Earth and Wabasca lodges are focused in the southern portion of the region where we primarily serve in-situ operations and pipeline expansion and maintenance activity. In-situ methods are used on reserves that are too deep for traditional mining methods. In-situ technology typically injects steam or solvents into the deep oil sands in place to separate the bitumen from the sand and pumps it to the surface where it undergoes the same upgrading treatment as the mined bitumen. Reserves requiring in-situ techniques of extraction represent 80% of the established recoverable reserves in Alberta. In comparison to surface mining operations, in-situ operations generally require lower initial capital investment, fewer personnel but produce lower volumes of bitumen per development, with higher ongoing operating expense per barrel of bitumen produced. Our oil sands lodges primarily support personnel for ongoing operations associated with surface mining and in-situ oil sands projects, as well as maintenance, turnaround and expansionary personnel, generally under short- and medium-term contracts. Most of our oil sands lodges are located on land with leases obtained from the province of Alberta, with initial terms of ten years, or subleased from the resource developer. Our leases have expiration dates that range from 2024 to 2030. In recent years, we have successfully renewed or extended all expiring land leases which we have requested to renew or extend. We did not renew an expiring land lease associated with our McClelland Lake Lodge in Alberta, Canada, which expired in June 2023, in order to support our customer’s intent to mine the land where the lodge was located. Two of our oil sands properties are located on land which we own. In order to operate a lodge in Canada, we are required to obtain a development permit from the regional municipality in which the lodge is located. The development permits are granted for a term of five years. Our development permits have expiration dates that range from 2024 to 2028. In recent years, we have successfully renewed or extended all expiring development permits. See “Item 1A. Risk Factors - Risks Related to Our Operations - The majority of our major Canadian lodges are located on land subject to leases. If we are unable to renew a lease or obtain permits necessary to operate on such leased land, we could be materially and adversely affected.” of this annual report for further information. We provide a range of hospitality services at our lodges, including reservation management, check in and check out, food service, housekeeping and facilities management. Our lodge guests receive amenities similar to a full-service, urban hotel with our service offering a room and three meals a day. Our Wapasu Creek Lodge, with more than 5,000 rooms, is equivalent in size to the largest hotels in North America. We provide our hospitality services at the lodges we own on a day rate or monthly rental basis, and our customers typically commit for short to long-term contracts (from several months up to several years). Most customers make a minimum nightly or monthly room commitment or an aggregate total room night commitment for the term of the contract, and the multi-year contracts typically provide for inflationary escalations in rates for increased food, labor and utilities costs. Canadian British Columbia Lodge As previously discussed, LNGC is currently constructing the Kitimat LNG Facility. British Columbia LNG activity and related pipeline projects are a material driver of activity for our Sitka Lodge, as well as for our mobile assets, which are contracted to serve designated portions of the related CGL pipeline construction activity. The majority of our contracted commitments associated with the CGL pipeline project were completed in the fourth quarter of 2023. 8 Canadian Lodge Locations Rooms in our Canadian Lodges As of December 31, Lodges Region Extraction Technique 2023 2022 2021 Wapasu Creek N. Athabasca mining/in-situ 5,174 5,174 5,174 Athabasca N. Athabasca mining 2,005 2,005 2,005 McClelland Lake (2) N. Athabasca mining — 1,997 1,997 Beaver River N. Athabasca mining 1,094 1,094 1,094 Fort McMurray Village: Black Bear N. Athabasca mining 531 531 531 Bighorn N. Athabasca mining 763 763 763 Lynx N. Athabasca mining 855 855 855 Wolverine N. Athabasca mining 855 855 855 Borealis (1) N. Athabasca mining 1,504 1,504 1,504 Grey Wolf N. Athabasca mining 946 946 946 Hudson (1) N. Athabasca mining 624 624 624 Wabasca (1) S. Athabasca mining 288 288 288 Red Earth (1) S. Athabasca mining 216 216 216 Conklin (1) S. Athabasca mining/in-situ 610 610 610 Anzac (1) S. Athabasca in-situ 526 526 526 Subtotal – Oil Sands 15,991 17,988 17,988 Sitka Lodge Kitimat, BC LNG 961 961 959 Total Rooms 16,952 18,949 18,947 (1) Currently closed as of December 31, 2023, due to lodge loading strategy, seasonal activity fluctuations or low activity level in the region. All closed lodges are periodically assessed for impairment at an asset group level, in accordance with United States (U.S.) generally accepted accounting principles. See Note 4 - Impairment Charges to the notes to the consolidated financial statements in Item 8 of this annual report for further discussion. (2) The land lease associated with the asset expired in June 2023 and was not renewed. See "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview and Macroeconomic Environment -McClelland Lake Lodge” of this annual report for additional information. 9 Hospitality Services at Third-Party Owned Facilities We also provide hospitality services at customer-owned facilities. Historically, this has been focused around natural resource production-related housing facilities that are owned by oil production companies. The facilities we manage typically range anywhere from 500 to 1,500 rooms. We customize our service offerings depending on our customer’s needs. Hospitality services can be performed on an end-to-end basis with food service, housekeeping, maintenance and utility services included or in segments such as food service only. Our focus on hospitality service contracts has allowed us to successfully pursue food service only opportunities. Due to our experience servicing customer-owned facilities, this business easily fits into our overall strategy. Canadian Mobile Assets Our mobile assets consist of modular, skid-mounted accommodations and central facilities that can be configured to serve a multitude of short- to medium-term accommodation needs. Dormitory, kitchen and ancillary assets can be rapidly mobilized and demobilized and are scalable to support 200 to 800 people in a single location. In addition to asset rental, we provide hospitality services such as food service and housekeeping, as well as other camp management services. Our mobile assets service the traditional oil and gas sector in Alberta and British Columbia and in-situ oil sands drilling and development operations in Alberta, as well as pipeline construction crews throughout Western Canada. These assets have also been used in the past in disaster relief efforts, the 2010 Vancouver Winter Olympic Games and a variety of other non-energy related projects. Our mobile assets are rented on a per unit basis based on the number of days that a customer utilizes the asset, and, in some cases, involve standby rental arrangements. In cases where we provide food service or ancillary services, the contract can provide for per unit pricing or cost-plus pricing. Customers are also typically responsible for mobilization and demobilization costs. Our focus on hospitality service contracts has allowed us to successfully pursue food service only opportunities. Due to our experience servicing customer-owned facilities, this business easily fits into our overall strategy. Australia Overview During the year ended December 31, 2023, we generated 48% of our revenue from our Australian operations. As of December 31, 2023, we owned 8,910 rooms across eight villages, of which 7,488 rooms service the Bowen Basin of central Queensland, one of the premier met coal basins in the world. We provide hospitality services on a day rate basis to mining and related service companies (including construction contractors), typically under short- and medium-term contracts (one to five years) with minimum nightly room commitments. In addition, we provide integrated services to the mining industry in Western Australia and South Australia. Australian Market As the largest contributor to exports and a major contributor to the country’s gross domestic product and government revenue, the Australian natural resources industry plays a vital role in the Australian economy. Australia has broad natural resources, including met and thermal coal, conventional and coal seam gas, base metals, iron ore, copper, lithium and precious metals such as gold. Australia is the largest exporter of met coal and iron ore in the world, in addition to being in close proximity to the largest steel producing countries in the world, primarily in Southeast Asia. The growth of Australian natural resource commodity exports over the last decade has been largely driven by strong Asian demand for met coal, iron ore and LNG. Australia’s resources are primarily located in remote regions of the country that lack infrastructure and resident labor forces to produce these resources, as the majority of Australia’s population is located on the east coast of the country. As a result, much of the natural resources labor force works on a rotational basis, which often requires a commute from a major city or the coast to a living arrangement near the resource projects. Consequently, there is substantial need for workforce accommodations and hospitality services to support resource production in the country. Workforce accommodations have historically been built and owned by the resource developer/owner, with third parties providing the hospitality and facility management services, typical of an insourcing business model. Since 1996, our Australian business has sought to change the insourcing business model through its hospitality services offering, allowing customers to outsource their accommodations needs and focus their investments on resource production operations. Our Australian villages are strategically located in proximity to long-lived, low-cost mines operated by multiple investment-grade, international mining companies. 10 Our Australian villages support similar activities as our Canadian lodges for the natural resources industry in Australia. Our customers are typically developing and producing met coal, iron ore and other minerals which have resource lives that are measured in decades. As such, their spending levels tend to react similarly to commodity prices as the spending levels of our Canadian customers. Spending on producing assets is less sensitive to commodity price decreases in the short and medium term, assuming the projects remain cash flow positive. However, new construction projects and expansionary projects are typically canceled or deferred during periods of lower met coal and iron ore prices. New project construction activity typically requires larger workforces than day-to-day operations, where proximity and availability of customer-owned rooms influences the demand for our rooms and services. Demand for rooms at our Australian villages is primarily driven by production, maintenance and operational activities. Our Australian operations primarily serve the Bowen Basin of Queensland and the Pilbara region in Western Australia. During the year ended December 31, 2023, our five villages in the Bowen Basin generated 47% of our Australian revenue, or 23% of our consolidated revenue. The Bowen Basin contains one of the largest coal deposits in Australia and is renowned for its premium met coal. In addition, we provide village operation and mine site cleaning services at eight customer locations in the Pilbara region, which is renowned for high grade iron ore production. Our villages and customer-owned locations are focused on the mines in the central portion of the Pilbara and Bowen Basins and are well positioned for the active mines in the region. Beyond met coal and iron ore markets served in the Pilbara and Bowen Basins, we serve several other markets with three additional villages and ten customer-owned villages. At the end of 2023, we had two villages with over 1,000 combined rooms in the Gunnedah Basin, a thermal and met coal region in New South Wales. In Western Australia, we serve workforces related to LNG facilities operations on the Northwest Shelf through our Karratha village. In addition, we provide hospitality services in Western Australia and South Australia at ten customer-owned villages which support workforces related to nickel, copper, zinc, silver and gold production in the Goldfields-Esperance region, lithium production in the Pilbara region and copper, silver and gold in Western Australia and South Australia. Australian Village Locations 11 Owned Rooms in our Australian Villages As of December 31, Villages Resource Basin Commodity 2023 2022 2021 Coppabella Bowen met coal 3,144 3,048 3,048 Dysart Bowen met coal 1,798 1,798 1,798 Moranbah Bowen met coal 1,240 1,240 1,240 Middlemount Bowen met coal 816 816 816 Boggabri Gunnedah met/thermal coal 622 622 622 Narrabri Gunnedah met/thermal coal 502 502 502 Nebo Bowen met coal 490 490 490 Karratha Pilbara LNG, iron ore 298 298 298 Kambalda (1) - gold, lithium — — 232 Total Rooms 8,910 8,814 9,046 (1) Sold in the third quarter of 2022. Our Australian segment includes eight company-owned villages with 8,910 rooms as of December 31, 2023, which are strategically located near long-lived, low-cost mines operated by large mining companies. Our Australian business provides hospitality services to mining and related service companies under short- and medium-term contracts. Our growth plan for this part of our business continues to include enhanced occupancy and expansion of these properties where we believe there is durable long-term demand, as well as to provide hospitality services at customer-owned assets. Our Coppabella, Dysart, Moranbah, Middlemount and Nebo villages are located in the Bowen Basin. Coppabella, at over 3,100 rooms, is our largest village and provides rooms and related hospitality services to a variety of customers. Each of these villages supports both operational workforce needs and contractor needs with resort style amenities, including swimming pools, gyms, a walking track and a tavern. Our Narrabri and Boggabri villages in New South Wales provide rooms and related hospitality services to met and thermal coal mines and coal seam gas in the Gunnedah Basin. Our Karratha village, in Western Australia, services workforces related to LNG facilities operations on the Northwest Shelf. Hospitality Services at Third-Party Owned Facilities We also provide hospitality services at customer-owned villages to the mining industry in Western Australia. Historically, this has been focused around natural resource production-related village facilities that are primarily owned by iron ore production companies. We provide village hospitality services at 18 customer-owned locations, which represent over 12,600 rooms, primarily in the Pilbara region of Western Australia, one of the premier iron ore bodies in the world, and in the Goldfields-Esperance region of Western Australia. The facilities we manage range anywhere from 200 to over 1,900 rooms. We work together with our customers to customize our service offerings depending on our customer’s needs. Hospitality services can be performed on an end-to-end basis with catering and food service, housekeeping and site maintenance included or in segments such as food service only. Mine site cleaning services are also provided at some of our customer-owned locations. Other In the first quarter of 2023, we sold our accommodation assets in Louisiana. In addition, in the second half of 2022, we sold both our U.S. wellsite services and offshore businesses. Our remaining U.S. business consists of 235 rooms at our Killdeer Lodge, which supports completion activity in the Bakken. U.S. oil completion activity will continue to be impacted by oil prices, pipeline capacity, federal energy policies and availability of capital to support exploration and production completion plans. Community Engagement With a focus on long-term Indigenous community participation, our Canadian operations continue to work closely with a number of First Nations to develop mutually beneficial partnerships focused on revenue sharing, capacity building, employment and community investment and support. For over a decade, our Canadian operations supported Buffalo Metis Catering, a partnership with three Metis communities in the Regional Municipality of Wood Buffalo. Through this partnership, food and housekeeping services were delivered to three of our lodges. Beyond these services, this partnership provided a business incubator environment for a number of Metis business ventures. Our Canadian operations also procure services from a number 12 of other First Nations-owned, Metis-owned and member-owned businesses including water hauling, snow removal and security services. In 2023, we purchased more than C$64.0 million in goods and services from the Indigenous business community, representing 27% of our total Canadian local spending, compared to C$66.2 million in goods and services from the Indigenous business community, representing 30% of our total Canadian local spending in 2022. In 2021, the Fort McKay Metis community awarded Civeo with the inaugural 2020 Fort McKay Metis National President's Award. This award recognizes people or organizations who make a positive contribution to the well-being of the Metis community. In 2023 and in 2019, our Indigenous partnership initiatives earned Civeo a Gold level Progressive Aboriginal Relations (PAR) certification, by a jury comprised of Indigenous business people, which was supported by an unbiased, independent, third-party verification of our performance. In 2016, Civeo was awarded a Silver level PAR certification by the Canadian Council for Aboriginal Business (CCAB), demonstrating our commitment to the principles and practices established by the CCAB. In addition, in 2011 and 2012, we were recognized with awards from the Alberta Chamber of Commerce. In 2018, Civeo entered into three new Indigenous partnerships in the oil sands region and two new partnerships in British Columbia and, in 2021, Civeo entered into a new partnership in British Columbia. Our partnerships in British Columbia are tied to accommodations contracts secured by Civeo for the Kitimat LNG Facility, the CGL pipeline project that originates in the North Montney region of north-east British Columbia and the Trans Mountain expansion project that twins an existing pipeline between Edmonton, Alberta and Burnaby, British Columbia. Beyond revenue sharing, these arrangements provide procurement, employment, training, and ancillary business opportunities for Indigenous owned businesses. In Australia, our community relations program also aims to build and maintain a positive social license to operate by consulting and engaging with local regional communities from project inception, through development, construction and operations. This is a major advantage for our business model, as it facilitates consistent communication, engenders trust and builds relationships to last throughout the resource lifecycle. There is an emphasis on developing partnerships that create a long-term sustainable outcome to address specific community needs. To that end, we partner with local municipalities to improve and expand municipal infrastructure. These improvements provide necessary infrastructure, allowing the local communities an opportunity to expand and improve. We also provide support to local community groups through sponsorship and in-kind contributions to local events and initiatives. In addition, all of our food suppliers are Australian companies and, where possible, are based locally. Through our membership with Supply Nation, a non-profit organization committed to supplier diversity and Indigenous business development, we directed approximately A$12.3 million in 2023, compared to A$9.5 million in 2022, into Indigenous-owned and operated companies, and we are always looking for more opportunities to partner with these businesses. In addition, we have four unincorporated joint venture partnerships with Indigenous landowners in Western Australia. Under these agreements, we strive to develop the business capacity, project management skills and expertise of the Indigenous joint venture members and also provide local employment opportunities and training. One of the four unincorporated joint venture partnerships entitles Indigenous landowners to a profit distribution calculated in accordance with the unincorporated joint venture deeds. Additionally, three of the four remaining agreements incentivize the joint venture members via milestone payments for business objectives achieved. Customers and Competitors Our customers primarily operate in oil sands mining and development, drilling, exploration and extraction of oil and natural gas and coal and other extractive industries. To a lesser extent, we also support other activities, including pipeline construction, forestry and humanitarian aid. Our largest customers in 2023 were Suncor Energy and Fortescue Metals Group Ltd., who each accounted for more than 10% of our 2023 revenues. Our primary competitors in Canada in lodge and mobile asset hospitality services include ATCO, Black Diamond, Dexterra and Clean Harbors, Inc. Some of these competitors have one or two locations similar to our oil sands lodges; however, based on our estimates, these competitors do not have the breadth or scale of our lodge operations. In Canada, we also compete against Aramark, Sodexo, Compass Group and Royal Camp Services for third-party facility management and hospitality services. Our primary competitors in Australia for our village hospitality services are customer-owned and operated villages as well as Ausco Modular (a subsidiary of Modulaire Group), Fleetwood Corporation and smaller independent village operators. We compete against ISS, Sodexo, Compass Group, Northern Rise (as a division of Sirrom Corporation) and Cater Care for third-party facility management services. 13 Historically, many customers have invested in their own accommodations. We estimate that our existing and potential customers own approximately 50% of the rooms available in both the Canadian oil sands and the Australian coal mining regions. Our Lodge and Village Contracts During the year ended December 31, 2023, revenues from our lodges and villages represented over 63% of our consolidated revenues. Our contract terms generally provide for a daily rate for a reserved room and an occupied room rate that compensates us for hospitality services, including food service, housekeeping, utilities and maintenance for workers staying in the lodges and villages. In most multi-year contracts, our rates typically have annual escalation provisions to cover increases in labor and consumables costs over the contract term. In some contracts, customers have a contractual right to terminate, for reasons other than a breach, in exchange for a termination fee. Our customers typically contract for hospitality services under contracts with terms that most often range from several months to twelve years. The contracts expire throughout the year, and for many of the near-term expirations, we are in the process of negotiating extensions or new commitments. We cannot assure that we can renew existing contracts or obtain new business on the same or better terms, if at all. Long-Term Take-or-Pay Contracts . Over the term of a take-or-pay contract, the customer commits to either a minimum number of rooms over a specified period or an aggregate number of room nights over the period, generally for terms greater than 12 months. During the year ended December 31, 2023, we billed approximately 2.6 million room nights under our long-term take-or-pay contracts, which included 0.6 million room nights in excess of the take-or-pay minimums. For the year ended December 31, 2024, we have commitments for 1.7 million room nights under our long-term take-or-pay contracts. Short-Term Take-or-Pay Contracts. Customers may contract with us on a take-or-pay basis for less than 12 months, particularly for turnaround projects. Similar to long-term take-or-pay contracts, the customer commits to either a minimum number of rooms over a specified period or an aggregate number of room nights over the period. During the year ended December 31, 2023, we billed approximately 0.7 million room nights under our short-term take-or-pay contracts. For the year ended December 31, 2024, we have commitments for 0.1 million room nights under our short-term take-or-pay contracts. Exclusivity Contracts. Over the term of an exclusivity contract, rather than receiving a minimum room commitment, we are the exclusive hospitality service provider for the customer's employees working on a specific project or projects. During the year ended December 31, 2023, we billed approximately 1.7 million room nights under our exclusivity contracts. Casual / Walk-ins. Customers without long-term committed contracts may utilize lodge/village rooms via short-term bookings at lodge/village casual or agreed rates. During the year ended December 31, 2023, we billed approximately 0.1 million room nights to casual or walk-in customers. Our Integrated Services Contracts During the year ended December 31, 2023, revenues from our customer-owned locations represented 26% of our consolidated revenues. Our contract terms generally provide for a per guest per day rate for hospitality services, including food service and housekeeping. Similar to our owned lodge and villages contracts, in most multi-year contracts, our rates typically have annual escalation provisions to cover increases in labor and consumables costs over the contract term. Our customers typically contract for hospitality services under exclusivity contracts with terms that most often range from several months to five years. During the year ended December 31, 2023, we billed approximately 2.6 million room nights under our integrated services exclusivity contracts. Seasonality of Operations Our operations are directly affected by seasonal weather. A portion of our Canadian operations is conducted during the winter months when the winter freeze in remote regions is required for customers’ activity to occur. The spring thaw in these frontier regions restricts operations in the second quarter and adversely affects our customers' operations and our ability to provide services. Customers’ maintenance activities in the oil sands region, such as shutdown and turnaround activity, are typically performed in the second and third quarters annually. Our Canadian operations have also been impacted by forest fires and flooding in the past five years. During the Australian rainy season between November and April, our operations in Queensland and the northern parts of Western Australia can be affected by cyclones, monsoons and resultant flooding. Human Capital Resources We believe that our employees are one of our greatest resources. As of December 31, 2023, we had approximately 1,600 full-time employees and approximately 1,000 hourly employees on a consolidated basis, 47% of whom are located in Canada, 14 52% of whom are located in Australia and 1% of whom are located in the U.S. We were party to collective bargaining agreements covering 798 employees located in Canada and 1,020 employees located in Australia as of December 31, 2023. As a company, we acknowledge the significance of a diverse workforce composed of individuals from various backgrounds, experiences, and perspectives. As many of our projects in Canada and Australia operate in traditional territories, we work closely with Indigenous communities to actively explore mutually beneficial investment, employment, and business opportunities. Our ability to cultivate and strengthen relationships with Indigenous communities is vital to the success of our business. In Canada, we are committed to expanding our Indigenous workforce to 10%. In 2023, we reached 7% Indigenous employment in Canada, excluding corporate staff. Approximately 6% of our total new hires in Canada were of Indigenous background during 2023. We strive to offer competitive compensation, benefits and services that meet the needs of our employees, including short- and long-term incentive packages, various defined contribution plans, healthcare benefits, and wellness and employee assistance programs. Management monitors market compensation and benefits in order to attract, retain, and promote employees and reduce turnover and its associated costs. Safety is a foundational pillar of Civeo’s corporate culture. We are committed to operating in a safe, secure and responsible manner for the benefit of our employees, customers and the communities we serve. Our commitment to safeguarding employees, contractors, and guests is demonstrated through our employee-named Making Zero Count initiative, which emphasizes the importance of eliminating harm and focuses on the processes required to achieve exceptional performance. At Civeo, we believe that investing in our employees is fundamental to our success. Our commitment to training and career development enables employees to grow and advance in their careers while supporting our industry-leadership position. Committed to the continuous improvement of our team, we prioritize the development of our workforce’s technical and managerial competencies, with an emphasis on safety, customer service, and leadership development. Our learning and development program encompasses a range of learning modalities, including e-learning modules, in-person training sessions, nationally certified programs and licensed training provided by external partners. Government Regulation Our business is significantly affected by Canadian, Australian and U.S. laws and regulations at the federal, provincial, state and local levels relating to the oil, natural gas and mining industries, worker safety and environmental protection. Changes in these laws, including more stringent regulations and increased levels of enforcement of these laws and regulations, and the development of new laws and regulations could significantly affect our business and result in: • increased difficulty securing required permits, approvals, licenses or other authorizations issued by federal, provincial and local authorities needed to carry out our operations or our customers' operations; • increased compliance costs or additional operating restrictions associated with our operations or our customers’ operations; • other increased costs to our business or our customers’ business; • reduced demand for oil, natural gas, and other natural resources that our customers produce; and • reduced demand for our services. To the extent that these laws and regulations impose more stringent requirements or increased costs or delays upon our customers in the performance of their operations, the resulting demand for our services by those customers may be adversely affected, which impact could be significant and long-lasting. Moreover, climate change laws or regulations could increase the cost of consuming, and thereby reduce demand for, oil and natural gas, which could reduce our customers’ demand for our services. We cannot predict changes in the level of enforcement of existing laws and regulations, how these laws and regulations may be interpreted or the effect changes in these laws and regulations may have on us or our customers or on our future operations or earnings. We also are not able to predict the extent to which new laws and regulations will be adopted or whether such new laws and regulations may impose more stringent or costly restrictions on our customers or our operations. Our operations and the operations of our customers are subject to numerous stringent and comprehensive foreign, federal, provincial, state and local environmental laws and regulations governing the release or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly yet critical. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, modification or cessation of operations, 15 assessment of administrative and civil penalties, and even criminal prosecution. Although we do not anticipate that future compliance with existing environmental laws and regulations will have a material effect on our financial condition, results of operations or cash flows over the short term, there can be no assurance that substantial costs for compliance or penalties for non-compliance with these existing requirements will not be incurred in the future by us or our customers. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations and enforcement policies or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities upon us or our customers that we cannot currently quantify. Canadian Environmental Regulations In Canada, the federal and provincial governments both have jurisdiction to regulate environmental matters. The provincial governments may also devolve jurisdiction over environmental matters to local governments. Our activities, or those of our customers, may be subject to environmental regulations imposed by these three levels of government. The following addresses updates to Canadian federal and provincial environmental regulations in 2023 that may affect us or our customers. Air Quality Management The Government of Canada (Canada), the Government of Alberta (Alberta), and the Government of British Columbia (British Columbia) each have frameworks for air quality management that may affect us and our customers. At the federal level, the Reduction in the Release of Volatile Organic Compounds Regulations (Petroleum Sector) were published in 2020. Certain leak detection and repair provisions of the regulations took effect beginning in 2021 and the regulations set additional monitoring and requirements for operators in 2022 and 2023. These regulations require the implementation of comprehensive leak detection and repair (LDAR) programs as well as design and operating standards that prevent leaks at Canadian petroleum refineries, upgraders and certain petrochemical facilities and may affect our customers’ operations. In addition to federal requirements, emissions from facilities in Alberta are subject to provincial regulation. The Alberta Energy Regulator (AER), which is responsible for regulating upstream oil and gas activity in Alberta, oversees compliance with Directive 60: Upstream Petroleum Industry Flaring, Incinerating, and Venting (Directive 60). This Directive applies to all upstream petroleum industry wells, facilities and pipelines as well as all oil sands schemes and operations with the exception of oil sands mining. Directive 60 requires operators to eliminate or reduce flaring associated with a wide variety of energy development activities and operations. In December 2018, the AER finalized amendments to its Directive 60 and Directive 017: Measurement Requirements for Oil and Gas Operations (Directive 17) as part of its role in implementing commitments from the Alberta government to reduce methane emissions from upstream oil and gas operations by 45% by 2025. These requirements, among other things, set limits on methane emissions from various facilities and require annual reporting of such emissions to the AER. The methane reduction requirements in Directive 60 took effect in 2020, additional vent gas limits took effect on January 1, 2022 and additional vent gas limits took effect on January 1, 2023. Meeting these regulatory requirements may result in additional costs or liabilities for our customers’ operations. Similarly, emissions from facilities in British Columbia are also subject to provincial regulation. The British Columbia Energy Regulator (BCER) is responsible for regulating oil and gas activity in British Columbia. BCER oversees compliance with the Drilling and Production Regulation, which is one of British Columbia's primary regulatory instruments governing all aspects of oil and natural gas drilling and production. Effective January 1, 2020, that regulation was amended to require operators to eliminate or reduce natural gas leaking or venting associated with a wide variety of equipment and activities in energy development. Under this regulation, requirements are imposed for facilities detecting leaks and inspecting seals as well as restrictions or prohibitions on the types of equipment used for energy development. Some of these requirements took effect in 2022 and further requirements took effect on January 1, 2023. In addition, the BCER completed consultation in 2023 on proposed amendments to the Drilling and Production Regulation to maintain equivalency with federal requirements. Regulations designed to achieve a 45% reduction in methane emissions relative to 2014 levels are now in place. The BCER is currently conducting a regulatory review and engagement on the development of new regulations designed to achieve a 75% reduction in methane emissions from the oil and gas sector by 2030. Meeting these regulatory requirements may result in additional costs or liabilities for our customers’ operations. 16 Environmental Assessment of Major Projects In August 2019, the Canadian Environmental Impact Assessment Act, 2012 (CEAA 2012) was repealed and replaced with the federal Impact Assessment Act. The Impact Assessment Act and regulations made under that Act provide that certain new projects and expansions to existing projects – including oil sands mining and in situ projects, metallurgical mining projects, pipelines and other developments – will likely require a federal planning and assessment process to understand the environmental and social impacts of the project, as well as decision on whether those impacts are in the public interest. One of the stated objectives of the Impact Assessment Act was to shorten review times for projects that are subject to review under that Act. However, concerns about lengthy reviews that require substantial information from project proponents remain even after the implementation of the Impact Assessment Act. Our customers operate in the aforementioned industries and could be considering future projects that would be subject to the Impact Assessment Act. To the extent our customers are required to comply with this legislation, it is possible that the uncertainty regarding cost and timelines for navigating the planning, assessment, and decision-making processes may negatively impact our customers' decisions on whether to proceed with those projects. The Government of Alberta, supported by the governments of Ontario and Saskatchewan, has challenged the constitutionality of the Impact Assessment Act. In October of 2023, a majority of the Supreme Court of Canada (Court) concluded that a large portion of the regime created by the Impact Assessment Act was unconstitutional. The federal government subsequently issued interim guidance on the administration of the Impact Assessment Act and advised that it intended to amend the Impact Assessment Act to align with the Court's ruling. The federal government is expected to introduce legislation amending the Impact Assessment Act in 2024. As a result, there is significant uncertainty about the future application of Canada's federal environmental assessment legislation to our customers. Climate Change Regulation Scientific studies have suggested that emissions of greenhouse gases (GHG), including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In December 2015, 195 nations, including Canada, Australia, and the U.S., adopted the Paris Agreement at the 21st “Conference of the Parties” to the United Nations Convention on Climate Change (COP 21). The Paris Agreement does not set legally binding emission reduction targets but does set a goal of limiting global temperature increases to less than 2° Celsius. Canada announced that it is in favor of the decision of the COP 21 to endeavor to take action to further limit global temperature increases to less than 1.5° Celsius. The Paris Agreement also requires parties to submit Intended Nationally Determined Contributions (INDCs) which set out their emission reduction targets and to renew these INDCs, with the goal of increasing the reductions, every five years. The Paris Agreement does not legally bind the parties to reach their INDCs, nor does it prescribe the measures that must take to achieve them. These measures are left to each participating nation. In September 2016, Canada's new federal government confirmed that it would not commit to a more ambitious INDC than the preceding Conservative federal government. The government maintained this approach in 2017 revisions to Canada’s INDC submission taking into account the federal Pan-Canadian Framework on Clean Growth and Climate Change (PCF) adopted in 2016. In March 2016, Canada and the Government of the U.S. jointly announced their intention to take action to reduce methane emissions from the oil and gas sector in an effort to meet their respective INDCs pursuant to the Paris Agreement. For its part, Canada announced its intention to reduce methane emissions from the oil and gas sector by 40-45 percent below 2012 levels by 2025. In 2018, the government introduced the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (Federal Methane Regulations) to implement its methane commitment. The Federal Methane Regulations impose various quantity-based limits on the venting of natural gas (or in the case of well completions involving hydraulic fracturing, a ban on such venting) and include associated conservation, measurement, inspection and corrective action requirements. Certain requirements of the Federal Methane Regulations came into effect January 1, 2020, and other emissions limits are now in place for certain equipment installed on or after January 1, 2023. In March 2022, the federal government began consultation on a proposed strategy to expand coverage and increase stringency of methane reduction obligations in the oil and gas sector specifically, and is expected to issue draft regulations in 2023. In December 2023, the federal government published proposed amendments to the Federal Methane Regulations for public comment. The proposed amendments are intended to reduce methane emissions in Canada's upstream oil and gas sector by at least 75% below 2012 levels by 2030. To achieve that objective, the proposed amendments would prohibit venting natural gas to the environment, subject to limited exceptions. They would also impose requirements on hydrocarbon combustion systems and measures to reduce fugitive methane emissions. Draft regulations are expected to be published in 2024. These requirements may result in additional costs or liabilities for our customers’ operations. 17 In 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act (GGPPA), which came into force on January 1, 2019. This regime has two parts: an output-based pricing system for large industry and a regulatory fuel charge. This system serves as a "backstop" and applies in provinces and territories that request it and in those that do not have their own emissions pricing systems in place that meet the federal standards. This ensures that there is a uniform price on emissions across the country. The backstop price under the GGPPA increased to $50 per tonne of CO2e in 2022. As of January 1, 2024, the backstop price is $65 per tonne of CO2e. That price will increase to $80 in April 2024 and the current government plan is to continue increasing that price by $15 each year until it reaches $170/tonne of CO2e in 2030. On November 19, 2020, the federal government introduced the Canadian Net-Zero Emissions Accountability Act in Parliament. That Act was passed by Parliament and received Royal Assent on June 29, 2021 and binds the Government of Canada to a process intended to help Canada achieve net-zero emissions by 2050. It also establishes rolling five-year emissions-reduction targets and requires the government to develop plans to reach each target. The federal government is required to support those efforts by creating a Net-Zero Advisory Body and by publishing annual reports that describe how departments and Crown corporations are considering the financial risks and opportunities of climate change in their decision-making. At the 26th Conference of the Parties to the UNFCCC (COP 26), held in Glasgow between October 31 and November 13, 2021, Canada presented a strengthened climate plan and committed to an enhanced emissions reduction target of between 40 and 45 percent below 2005 levels by 2030. Following a 2021 federal election, the Government of Canada delivered a new Throne Speech in November 2021 which reiterated its intent to take action that would "go further, faster" to fight climate change. Among other things, the federal government pledged to cap and cut oil and gas sector emissions while accelerating on the path to 100 percent net zero electricity. In December 2023, the federal government announced that it intended to implement a national cap-and-trade system for oil and gas emissions in Canada and published a draft regulatory framework for public comment. Draft regulations are expected to be published in 2024. As currently proposed, the cap-and-trade system would apply to liquified natural gas producers as well as producers in the conventional oil, offshore, oil sands and natural gas production and processing subsectors. The proposed cap-and-trade system would set oil and gas sector emissions limits, to be phased in between 2026 and 2030. Producers would be required to reduce their emissions or purchase "allowances" from other facilities that have reduced their emissions. These requirements, if implemented, may result in additional costs or liabilities for our customers’ operations. In addition, the federal government amended the Canadian Environmental Protection Act, 1999 (“CEPA”) in 2023. In particular, the preamble to CEPA now recognizes that every individual in Canada has a right to a healthy environment. The Government of Canada must now take into consideration this right, including the principles of environmental justice, when making decisions under CEPA, including its regulation of greenhouse gas emissions in Canada. Within two years, the Government of Canada must develop an implementation framework on how this right will be upheld while administering CEPA. Until that framework is developed, there is significant uncertainty regarding how these changes to CEPA will be implemented, and their potential to affect our customers' operations. In Alberta, GHGs are regulated pursuant to the Emissions Management and Climate Resilience Act and the Technology Innovation and Emissions Reduction Regulation (TIER Regulation). In December 2019, the TIER Regulation was deemed equivalent to the backstop prescribed by the federal GGPPA, meaning that facilities within Alberta subject to the TIER Regulation are not subject to the full costs of complying with the GGPPA. The TIER Regulation generally applies to Alberta-based facilities that emit over 100,000 tonnes of CO2e per year. Under the TIER Regulation, emissions from each facility are compared to either an industry-wide benchmark or a facility-specific benchmark which effectively permits facilities to emit GHGs up to a certain amount without being subject to the provincial carbon price. Those benchmarks “tighten” resulting in more onerous compliance costs, every year. Facilities with emissions that exceed the industry-wide benchmark or facility-specific benchmark, as applicable, must rely on one or more of the compliance options established by the TIER Regulation, such as purchase credits or offsets for each tonne of CO2e in excess of their limits. The Alberta government issues an order every year setting the price to acquire credits, which effectively dictates compliance costs. In January 2023, the Alberta government published amendments to the TIER Regulation, including increases to the carbon price and increases to annual benchmark tightening rates. These changes were implemented in order to ensure that the TIER Regulation maintains equivalency with the framework established by GGPPA. Increases to the cost of TIER Regulation credits and annual benchmark tightening rates may result in additional costs or liabilities for our customers’ operations. In addition, similar increases in stringency of provincial GHG regulatory frameworks within British Columbia and Saskatchewan may result in additional costs or liabilities for our customers’ operations. The Canadian Species at Risk Act is intended to prevent wildlife species in Canada from disappearing and to provide for the recovery of wildlife species that no longer exist in the wild in Canada, or that are endangered or threatened as a result of human activity, and to manage species of special concern to prevent them from becoming endangered or threatened. The designation of previously unprotected species as threatened or endangered in areas of Canada where our customers’ oil and natural gas exploration and production operations are conducted could cause them to incur increased costs arising from species 18 protection measures or could result in limitations on their exploration and production activities, which could have an adverse impact on demand for our services. Woodland caribou habitat covers large portions of several Canadian provinces including British Columbia, Alberta, and Saskatchewan. Many of our customers have existing or proposed developments in or near woodland caribou habitat. Conservation measures imposed by the federal or provincial governments could affect the business of our customers with operations near caribou habitat. Abandonment and Remediation of Oil and Gas Infrastructure As the lifecycle regulator for energy resource activities, the AER oversees closure requirements, including the abandonment and reclamation of wells, well sites, facilities, facility sites, and pipelines. Historically, the AER discharged this role through its Liability Management Rating Program (AB LMR Program). The AB LMR Program relied on the ratio of a company's assets and liabilities (Liability Management Ratio or LMR) to assess whether the company would be able to address closure obligations. Where a company's liabilities exceeded their assets (resulting in a LMR of less than 1.0), the AER could require the company to post security to bring the ratio to 1.0. The AB LMR Program was developed during a period of rapid growth in the province when companies were focused on well and infrastructure expansion. In recent years, it became clear that the LMR Program needed to be updated to reflect declining production and aging infrastructure. As a result of the Supreme Court of Canada's decision in Orphan Well Association v Grant Thornton (also known as the Redwater decision), receivers and trustees can no longer avoid the AER's legislated authority to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a license transfer when any such licensee is subject to formal insolvency proceedings. This means that insolvent estates can no longer disclaim assets that have reached the end of their productive lives (and therefore represent a net liability) in order to deal primarily with the remaining productive and valuable assets without first satisfying any abandonment and reclamation obligations associated with the insolvent estate's assets. In April 2020, the Government of Alberta passed the Liabilities Management Statutes Amendment Act, which places the burden of a defunct licensee's abandonment and reclamation obligations first on the defunct licensee's working interest partners, and second, the AER may order the orphan fund (Orphan Fund) established under the Oil and Gas Conservation Act (OGCA) to assume care and custody and accelerate the clean-up of wells or sites which do not have a responsible owner. These changes will come into force on proclamation. As a result of the changing landscape and new direction from the Redwater decision, in July 2020, the Government of Alberta began implementing changes to its liability management policy. In particular, in July 2020, the Province released a new Liability Management Framework (AB LMF) which includes a series of mechanisms and requirements to improve and expedite reclamation efforts and to require industry to better manage clean-up of oil and gas wells, pipelines and facilities. Notably, the AB LMF provided policy direction allowing the AER to take "Licensee Special Action" to assist operators in managing their assets and maintaining operations under certain circumstances. The Government of Alberta followed the announcement of the AB LMF with amendments to the Oil and Gas Conservation Rules and the Pipeline Rules in late 2020. The changes to these rules fall into three broad categories: (i) they introduce "closure" as a defined term, which captures both abandonment and reclamation; (ii) they expand the AER's authority to initiate and supervise closure; and (iii) they permit qualifying third parties on whose property wells or facilities are located to request that licensees prepare a closure plan. The AB LMF provided Government of Alberta policy direction on managing energy sector closure requirements. The AER implements and administers that policy through directives. In April 2021, the AER made changes to Directive 67: Eligibility Requirements for Acquiring and Holding Energy Licenses and Approvals (Directive 67) in order to increase scrutiny the AER applies to ensure that authorization for oil and gas development is only granted to responsible parties. Those changes include additional requirements for industry to provide updated financial information when making certain applications to the AER and throughout the energy development lifecycle. As a result of the changes to Directive 67, the AER may revoke or restrict a company's eligibility to hold AER licenses if the AER determines that the licensee poses an "unreasonable risk", taking into account a broad range of financial and operational considerations. In December 2021, the AER published a new Directive 88: Licensee Life-Cycle Management (Directive 88) and supporting guidance information to further support implementing the AB LMF. Among other things, Directive 88 establishes the AER's authority to conduct a holistic licensee assessment to inform regulatory decisions about a given licensee, including by conducting a "Licensee Capability Assessment." Directive 88 also establishes the Licensee Management Program contemplated in the AB LMF which enables the AER to proactively monitor licensees to identify those at risk of not meeting 19 their regulatory obligations and to use appropriate regulatory tools to address that risk. Finally, Directive 88 establishes the Inventory Reduction Program and allows the AER to set licensee-specific and industry-wide closure targets. Complementing the AB LMF Program and associated directives, Alberta's OGCA establishes an orphan fund (Orphan Fund) to help pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LMR Program if a licensee or working interest participant becomes insolvent or is unable to meet its obligations. The Orphan Fund was originally conceived to be bankrolled by licensees in the AB LMR Program who contribute to a levy administered by the AER. However, given the increase in orphaned oil and natural gas assets, the Government of Alberta has loaned the Orphan Fund approximately $335 million to carry out abandonment and reclamation work, of which, $121 million had been paid as of May 2023. In response to the COVID-19 pandemic, the Government of Alberta also covered $113 million in levy payments that licensees would otherwise have owed to the Orphan Fund, corresponding to the levy payments due for the first six months of the AER's fiscal year. A separate orphan levy applies to persons holding licenses for large facilities. Collectively, these programs, the AB LMF, and associated directives are designed to minimize the risk to the Orphan Fund posed by the unfunded liabilities of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines. These and any other changes to the AER's approach to manages closure requirements for energy resource activities may result in additional costs or liabilities for our customers’ operations. In British Columbia the BCER’s Comprehensive Liability Management Plan addresses liability management, improving the rate of inactive site restoration, and addressing orphan sites. The BCER uses a Liability Management Rating (LMR) program to evaluate each company’s ability to pay for site restoration. The BCER addresses dormant sites through the Dormancy and Shutdown Regulation, which ensures oil and natural gas producers responsibly bring their energy resource activities to regulatory closure within a reasonable time frame. The Dormant Sites Program is used to identify permit holders that are subject to the dormant site provisions of the Energy Resource Activities Act and the Dormancy and Shutdown Regulation. The regulation sets timelines for restoration and imposes requirements for decommissioning, site assessment, remediation and restoration. Like in Alberta, British Columbia’s Orphan Site Reclamation Fund is a levy on oil and natural gas producers that is used to pay the cost of restoring orphan sites in BC. If or when applicable to operations, any changes to the BCER’s approach to managing dormancy and closure requirements for energy resource activities may result in additional costs or liabilities for our customers’ operations. Australian Environmental Regulations Our Australian segment is regulated by statutory environmental and land use controls at the federal, state and territory and local government levels which may result in land use approval, regulation of operations and compliance risk. These controls include: land use and urban design controls; controls to protect Australia’s natural environment, iconic places and Aboriginal and Torres Strait islander native title and heritage; the regulation of hard and liquid waste, including the requirement for trade waste and/or wastewater permits or licenses; the regulation of water, noise, heat, and atmospheric gases emissions; the regulation of the production, transport and storage of dangerous and hazardous materials (including asbestos); the regulation of pollution and site contamination and requirements to notify of and clean-up environmental contamination. Federal Controls At a federal level, the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) is Australia’s key piece of environmental legislation. The EPBC Act protects of matters of national environmental significance, for example, threatened species and communities (e.g. Koalas), migratory species, Ramsar wetlands and world heritage properties. Activities that have the potential to impact matters protected by the EPBC Act trigger referral to the federal government for assessment and approval. In October 2020, the findings of an independent review of the EPBC Act (Independent Review) recommended significant reforms including (but not limited to) introduction of legally binding ‘National Environmental Standards’, a ‘climate change’ referral trigger, measures to harness and recognize the importance of indigenous knowledge, stronger compliance and enforcement powers, proposals for revised bilateral agreements with the States and Territories to streamline the assessment and approval process of some activities regulated by the EPBC Act and criminal penalties for offenses relating to emissions-intensive actions. In December 2022 the federal government announced its response to the Independent Review. This response proposes various changes to the EPBC Act in line with the Independent Review, for example, the introduction of ‘National Environmental Standards’, creation of a federal Environmental Protection Agency and the introduction of a requirement to 20 achieve ‘net positive’ outcomes. Several bills to effect some of the recommended reforms are currently before Parliament and a comprehensive draft bill is expected to be introduced in 2024 together with a draft of the proposed National Environmental Standards. Notably, the federal government is not presently proposing to introduce the climate change referral trigger recommended by the Independent Review. If any of the recommended reforms take effect, our obligations under, and compliance with, the EPBC Act ought to be reviewed. However, its implications for our Australian operations are not anticipated to be significant. Ongoing awareness of these reforms is important as the legislative and policy changes may affect our customers’ operations and have impacts on the non-renewable resources sector generally. There is an increasing emphasis from regulators on sustainability and energy efficiency in business operations. Federal requirements are now in place for the mandatory disclosure of energy performance under building rating schemes. These schemes require the tracking of specific environmental performance factors. Carbon reporting requirements currently exist for corporations which meet a reporting threshold for greenhouse gases or energy use or production for a reporting (financial) year under federal legislation. From July 1, 2023, new obligations and reporting requirements took effect with respect to the ‘Safeguard Mechanism’ – Australia’s policy for reducing emissions from facilities that emit more than 100,000t CO2-e per financial year that has been in place since 2016. These reforms are intended to assist Australia meet its emissions reduction targets of 43% below 2005 levels by 2030 and may affect large scale industry customers. The federal government has also proposed further climate-related disclosure requirements that are anticipated to take effect (for some companies) from mid-2024. These proposed disclosure requirements will oblige companies to disclose various climate-related information, including information about their greenhouse gas emissions, climate-related targets, offset contributions, transition plans, and information about strategies, plans and governance procedures/controls in place to monitor and manage climate-related risks and opportunities. If these reforms become law, we will have corporate reporting requirements in relation to these climate related matters, likely to commence in 2026. State and Territory Controls At a State and Territory level, our operations are authorized and regulated by layers of planning and environmental approvals. Queensland, New South Wales and Western Australia all have multiple acts regulating matters of the environment, conservation, vegetation management and protection of aboriginal and Torres Strait Islander use rights which are administered by each States’ independent environment protection regulator (e.g. Queensland’s Department of Environment, Science and Innovation). If amendments are made to the EPBC Act to effect new bilateral agreements, the States and Territories will likely be given further power to assess and approve certain actions regulated the EPBC Act. Under state law, some specified activities, for example, sewage treatment works at our sites, may require regulation by way of environmental approvals. Such approvals may also impose monitoring and reporting obligations on the holder as well as obligations to rehabilitate the subject site once the regulated activity has ceased. We must ensure that all necessary approvals, permits and licenses are in place to authorize our operations and that the conditions of those approvals, permits and licenses are complied with until the relevant operations cease (and are cleaned-up if necessary). Where approvals are not held and/or complied with, the operation may be unlawful and subject to penalties, including stop-work orders, remediation orders and financial penalties. Our Australian operations continue to comply with our existing approvals, permits and licenses. We have a positive obligation under state legislation to notify of an incident causing (or threatening) serious or material environmental harm. Examples of notifiable environment harm include effluent overflow, chemical leaks and chemical fires. Failure to discharge this obligation can attract significant sanctions and financial penalties. Local Government At a local government level, our operations are subject to, and regulated by, local laws administered by local government authorities. Local laws may cover matters such as operation of certain activities, management of vegetation and natural and anthropogenic hazards, actionable nuisance and fencing. Local laws differ between each local government area and we must understand and operate within these laws as they apply to our operations Australia wide. 21 U.S. Environmental Regulations The Clean Water Act, as amended, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the U.S. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the U.S. Environmental Protection Agency (EPA) or authorized state agencies. In addition, the Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act of 1999, as amended, require the development and implementation of spill prevention and response plans and impose liability for the remedial costs and associated damages arising out of any unauthorized discharges. GHG Emissions The EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified large GHG emission sources in the U.S., including, offshore and onshore oil and natural gas production facilities, on an annual basis. In December 2023, the EPA issued a final rule updating New Source Performance Standards (NSPS) and providing emission guidelines to reduce methane and other pollutants from the oil and gas industry. While the U.S. Congress has, from time to time, considered legislation to reduce emissions of GHGs, in recent years, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions, including cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. The U.S. participated in the creation of the Paris Agreement at COP 21 in December 2015. Although the U.S. had withdrawn from the Paris Agreement, in November 2020, the Biden administration officially reentered the U.S. into the agreement in February 2021. Under the Paris Agreement, the Biden Administration has committed the U.S. to reducing its greenhouse gas emissions by 50% to 52% from 2005 levels by 2030. In November 2021, the U.S. and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us or our customers to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and natural gas, which could reduce our customers’ demand for our services. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. Other Environmental Regulations Our operations, as well as the operations of our customers, are also subject to various laws and regulations addressing the management, disposal and releases of regulated substances, including the federal Resource Conservation and Recovery Act, as amended (RCRA), the federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (CERCLA), also known as the Superfund law, and comparable state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial operations to prevent future contamination. The federal Endangered Species Act, as amended (ESA), restricts activities in the U.S. that may affect endangered or threatened species or their habitats. If endangered species are located in areas of the U.S. where our oil and natural gas exploration and production customers operate, such operations could be prohibited or delayed or expensive mitigation may be required. The designation of previously unprotected species as threatened or endangered or designation of previously unprotected habitat as critical habitat in areas of the U.S. where our customers’ oil and natural gas exploration and production operations are conducted could cause them to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities, which could have an adverse impact on demand for our services. Hydraulic fracturing is an important and common practice in the oil and gas industry. The process involves the injection of water, sand and chemicals under pressure into a formation to fracture the surrounding rock and stimulate production of hydrocarbons. Certain environmental advocacy groups and regulatory agencies have suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process, and have made claims that 22 hydraulic fracturing techniques are harmful to surface water and drinking water resources and may cause earthquakes. Various governmental entities (within and outside the U.S.) are in the process of studying, restricting, regulating or preparing to regulate hydraulic fracturing, directly or indirectly. In the U.S., the EPA already regulates certain hydraulic fracturing operations involving diesel under the Underground Injection Control program of the federal Safe Drinking Water Act. In January 2021, President Biden announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. In August 2022, a federal district judge in Louisiana permanently enjoined the moratorium in the 13 states that filed a lawsuit against the action. States and local governments may also seek to limit hydraulic fracturing activities through time, place, and manner restrictions on operations or ban the process altogether. The adoption of legislation or regulatory programs that restrict hydraulic fracturing could adversely affect, reduce or delay well drilling and completion activities, increase the cost of drilling and production, and thereby reduce demand for our services. There also exists the potential for the Biden Administration to pursue new or amended laws, regulations, executive actions and other regulatory initiatives that could impose more stringent restrictions on hydraulic fracturing, including potential restrictions on hydraulic fracturing by banning new oil and gas permitting on federal lands. While our operations are not directly affected by these actions, their impact on our oil and natural gas exploration and production customers could result in a decreased demand for the services that we provide. 23