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 hospitality services to the natural resources industry in Canada, Australia and the United States (U.S.) We provide a full suite of services for our guests, including lodging, catering and food service, housekeeping and maintenance at accommodation facilities that we or our customers own. In many cases, we also 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 offer 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, and 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 Company is built on the foundation of the following core values: Safety, 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. We provide hospitality services that 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: (1) our fleet of mobile assets, particularly for shorter term projects such as pipeline construction and seasonal drilling programs; (2) our scalable lodge or village model; or (3) our service of guests 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. Our scalable facilities provide workforce accommodations where, in many cases, traditional accommodations or housing are not accessible, sufficient or cost effective. 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 primary focus is on providing these hospitality services to leading natural resource companies at our major properties, which we refer to as lodges in Canada and the U.S. and villages in Australia, or at facilities owned by our customers. We own and operate 26 lodges and villages with approximately 28,000 rooms. We operate approximately 12,200 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 Demand for our hospitality services is influenced by five primary factors: (1) commodity prices, (2) customers' capital spending, (3) available infrastructure, (4) headcount requirements and (5) competition. Current commodity prices, and our customers’ expectations for future commodity prices, influence customers’ spending and maintenance on current productive assets, expansion of existing assets and greenfield development of new assets. In addition to commodity prices, different types of customer activity require varying workforce sizes, influencing the demand for our services. Competing locations, infrastructure and services will also influence demand for our rooms and services. In the Canadian oil sands region, demand for our hospitality services is primarily influenced by the longer-term outlook for oil prices. Spending on the construction and development of new projects has historically decreased 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. Depressed oil price levels of both West Texas Intermediate (WTI) and Western Canadian Select (WCS) resulting from the initial spread of COVID-19 materially impacted 2020 maintenance and production spending and activity by Canadian operators and, therefore, demand for our hospitality services. Customers began restoring production in the fourth quarter of 2020, reaching pre-pandemic levels in 2022. Although oil prices reached multi-year highs in the first half of 2022 and fluctuated in the second half of 2022, there is continued uncertainty around commodity price levels, including the ongoing impact of COVID-19, inflationary pressures, actions taken by OPEC+ to adjust production levels, geopolitical events such as the ongoing Russia/Ukraine conflict, and regulatory implications on such prices, which could cause our Canadian oil sands and pipeline customers to reduce production, delay expansionary and maintenance spending and defer additional investments in their oil sands assets. 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 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. 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. 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. We expect that LNG investment and activity in Western Canada will be 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. Currently, Western Canada does not have any operational LNG export facilities. 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). 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 several portions of the related pipeline construction activity. The actual timing of when revenue is realized from the Coastal GasLink (CGL) pipeline and Sitka Lodge contracts could be impacted by any delays in the construction of the Kitimat LNG Facility or the pipeline, such as protest blockades and COVID-19. Our current expectation is that our contracted commitments associated with the CGL pipeline project will be completed in 2023. Any new delays in facility or pipeline construction may result in extensions to these dates. See "Canada-Canadian British Columbia Lodge" for more information. 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. Similar to the Canadian market, 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. Our customer service requirements are primarily driven by production, maintenance and operational activities. Through 2022, we saw increased activity from both new and 4 existing customers. With sustained met coal pricing above $200 per tonne, customers have committed to new projects and expansion projects and recommenced operations which were previously put on-hold. Current met coal prices continue to support an optimistic outlook for the sector, though exploration and future investment in Australia could be impacted with the recent increases to the Queensland royalty scheme introduced in mid-2022. Met coal prices have faced downward pressure in early 2023 due to falling steel demand, global economic weakness, and expected improvement in Australian supply as weather patterns and mining conditions improve. Iron ore prices fluctuated in the second half of 2022, with prices recovering from a low of $78 per tonne to over $100 per tonne with renewed support in the Chinese property sector. With stronger supply and a slow recovery in Chinese construction, downside pressure on current prices remains. In the last half of 2022, we sold both our wellsite services and our offshore businesses in the U.S. Our remaining U.S. business supports completion activity in the Bakken and construction and turnaround work in the Louisiana industrial area. 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. 5 For the years ended December 31, 2022, 2021 and 2020, we generated $697.1 million, $594.5 million and $529.7 million in revenues and $17.0 million, $6.1 million and $(147.2) million in operating income (loss), 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 62% of our revenue for the year ended December 31, 2022. Important performance metrics include revenue related to our major properties, average daily rate and aggregate billed rooms. The table below summarizes these key statistics for the periods presented in this annual report. Year Ended December 31, 2022 2021 2020 (In thousands, except for room counts and average daily rate) Accommodation Revenue (1) Canada $ 279,455 $ 239,526 $ 202,534 Australia 152,714 145,335 144,070 U.S. 3,058 5,437 2,451 Total Accommodation Revenue $ 435,227 $ 390,298 $ 349,055 Mobile Facility Rental Revenue (2) Canada $ 96,400 $ 62,856 $ 33,192 U.S. 18,367 14,486 16,837 Total Mobile Facility Rental Revenue $ 114,767 $ 77,342 $ 50,029 Food Service and Other Services Revenue (3) Canada $ 20,142 $ 18,996 $ 33,923 Australia 125,538 105,739 90,472 U.S. 90 50 50 Total Food Service and Other Services Revenue $ 145,770 $ 124,785 $ 124,445 Manufacturing Revenue (4) U.S. $ 1,288 $ 2,038 $ 6,200 Total Manufacturing Revenue $ 1,288 $ 2,038 $ 6,200 Total Revenue $ 697,052 $ 594,463 $ 529,729 Average Daily Rates for Lodges and Villages (5) Canada $ 100 $ 99 $ 95 Australia $ 75 $ 79 $ 73 Total Billed Rooms for Lodges and Villages (6) Canada 2,759,521 2,404,880 2,095,784 Australia 2,024,068 1,846,882 1,968,284 Average Exchange Rate Canadian dollar to U.S. dollar $ 0.77 $ 0.80 $ 0.75 Australian dollar to U.S. dollar 0.69 0.75 0.69 (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. 6 Our History 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. Through our wide range of hospitality services, 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. Using our experiences and service delivery model, our hospitality services have evolved to include fitness centers, water and wastewater treatment, laundry service and many other enhancements. 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. In 2018, LNGC's partners announced that a positive FID had been reached on 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 several 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, geographic footprint and exposure to new commodities in Australia and underlines our focus on pursuing growth opportunities that fit within our core competencies and strategic direction. In all our operating regions, our business is built on a culture of continuous service improvement to enhance the guest experience and reduce customers' workforce housing costs. Our Industry We provide hospitality services to the natural resource industry. Our scalable facilities provide long-term and temporary workforce accommodations where traditional accommodations and related infrastructure often are not accessible, sufficient or cost effective. Once facilities are deployed in the field, we also provide services such as lodging, catering and food service, housekeeping and maintenance, as well as operations of these facilities, including laundry, water and wastewater treatment, power generation, communication systems, security and logistics. Our hospitality services can be provided at accommodation facilities we own or at facilities owned by our customers. Demand for our services is cyclical and substantially dependent upon activity levels, particularly our customers’ willingness to spend capital on the exploration for, development and production of oil, met coal, LNG, iron ore and other natural resources. Our customers’ spending plans generally are based on their view of commodity supply and demand dynamics, as well as the outlook for near-term and long-term commodity prices. As a result, the demand for our services is sensitive to current and expected commodity prices. We serve multiple projects and multiple customers at most of our sites, which 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. Our business is significantly influenced by: (1) the level of production of oil sands deposits and associated maintenance and turnaround activities in Alberta, Canada; met coal production in Australia's Bowen Basin and iron ore production in Western Australia; (2) activity levels in support of extractive industries in Australia; (3) LNG and related pipeline activity in Canada; and (4) oil production in the U.S. 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. 7 Over the past 20 years, and increasingly over the past 10 years, some customers have moved away from the in sourcing business model for some of their accommodation needs as they recognize that owning accommodations and providing the hospitality services are non-core investments for their business. We believe that our existing industry divides accommodations into two primary types: (1) lodges and villages and (2) 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. 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), or 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, 2022, we generated approximately 57% 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 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 commodity price driven. In the Canadian oil sands region, demand is primarily influenced by the longer-term outlook for crude 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. Demand for hospitality services related to LNG is influenced by the global prices for LNG. 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. 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 39 million residents, nearly 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. Similarly, the LNGC project located in Kitimat, British Columbia, is expected to need as many as 7,500 workers to construct the liquefaction facilities. The population of Kitimat and the surrounding area is approximately 9,000. 8 Canadian Oil Sands Lodges During the year ended December 31, 2022, activity in the Athabasca oil sands region generated approximately 62% of our Canadian revenue. The oil sands region continues to represent one of the world’s largest reserves for heavy oil. Our McClelland Lake, 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, large 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, as well as a portion of our mobile assets, 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-situ operations generally require less capital and personnel and 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 2023 to 2030. In recent years, we have successfully renewed or extended all expiring land leases which we have requested to renew or extend. 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 2023 to 2027. 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 hotel plus 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 medium-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 CGL pipeline projects are a material driver of activity for our Sitka Lodge, as well as for our mobile assets, which are contracted to serve several portions of the related pipeline construction activity. The actual timing of when revenue is realized from the CGL pipeline and Sitka Lodge contracts could be impacted by any delays in the construction of the Kitimat LNG Facility or the pipeline, such as protest blockades or COVID-19. Our current expectation is that our contracted commitments associated with the CGL pipeline project will be completed in 2023. 9 Canadian Lodge Locations Rooms in our Canadian Lodges As of December 31, Lodges Region Extraction Technique 2022 2021 2020 Wapasu Creek N. Athabasca mining/in-situ 5,174 5,174 5,246 Athabasca (1) N. Athabasca mining 2,005 2,005 2,005 McClelland Lake (2) N. Athabasca mining 1,997 1,997 1,997 Beaver River (1) N. Athabasca mining 1,094 1,094 1,094 Fort McMurray Village: Black Bear (1) 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 S. Athabasca mining/in-situ 610 610 616 Anzac (1) S. Athabasca in-situ 526 526 526 Subtotal – Oil Sands 17,988 17,988 18,066 Sitka Lodge Kitimat, BC LNG 961 959 958 Total Rooms 18,949 18,947 19,024 (1) Currently closed as of December 31, 2022, 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 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 expires in June 2023. See "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview and Macroeconomic Environment - Capital Expenditures” of this annual report for additional information. 10 Hospitality Services at Third-Party Owned Facilities We also provide hospitality services at facilities owned by our customers. 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 catering and 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, 2022, we generated 40% of our revenue from our Australian operations. As of December 31, 2022, we owned 8,814 rooms across eight villages, of which 7,392 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 three years) with minimum nightly room commitments. In addition, we provide integrated services to the mining industry in Western 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 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. 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 investment-grade, international mining companies. 11 Our Australian operations primarily serve the Bowen Basin of Queensland and the Pilbara region in Western Australia. During the year ended December 31, 2022, our five villages in the Bowen Basin generated 49% of our Australian 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 six customer locations in the Pilbara region, which is renowned for high grade iron ore production. Our villages and customer-based 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. The Chinese placed an embargo on several Australian products, including coal, in the fall of 2020. During the embargo, Australian met coal producers found new markets, including India and Europe, for their premium product. This led to a rebalancing of the market globally with China relying on domestic production along with increased met coal imports from the U.S., Canada and Mongolia. With the backdrop of continuing strong steel demand and met coal supply constraints, the spot price for met coal surged to record highs through the second half of 2021 into early 2022. The embargo was recently lifted during the first quarter of 2023. While met coal prices have receded from their all-time highs, they still remain over $350 per tonne as of February 24, 2023. Analysts forecast met coal prices to face downward pressure in early 2023 but to moderate during the year with supply improvement and weaker demand impacting prices. Downward pressure on prices could accelerate in the short term if demand in China worsens. Beyond the Pilbara and Bowen Basins, we serve several other markets with four additional villages and three customer-owned villages. At the end of 2022, 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 Southern Australia at seven 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. 12 Australian Village Locations Owned Rooms in our Australian Villages As of December 31, Villages Resource Basin Commodity 2022 2021 2020 Coppabella Bowen met coal 3,048 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 Kambalda (1) - gold, lithium — 232 232 Karratha Pilbara LNG, iron ore 298 298 298 Total Rooms 8,814 9,046 9,046 (1) Sold in the third quarter of 2022. Our Australian segment includes eight company-owned villages with 8,814 rooms as of December 31, 2022, 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 3,000 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 service 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 13 Northwest Shelf. Our Kambalda village was sold in the third quarter of 2022 to a customer, and we continue to operate the village as a customer-owned location. 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 operation services at 13 customer-owned locations, which represent over 10,000 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. U.S. Overview During the year ended December 31, 2022, our U.S. business generated 3% of our revenue. In the last half of 2022, we sold both our wellsite services and our offshore businesses. Our remaining U.S. business consists of two lodges - one in the Bakken region and one in Louisiana. As of December 31, State 2022 2021 2020 West Permian (1) TX — — 390 Acadian Acres LA 300 300 300 Killdeer ND 235 235 235 Total Rooms 535 535 925 (1) Sold in October 2021. Our Killdeer Lodge provides rooms to the Bakken Shale region in North Dakota. Our Acadian Acres Lodge provides rooms near Lake Charles, Louisiana to support the Louisiana downstream market. 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 of other First Nations-owned, Metis-owned and member-owned businesses including water hauling, snow removal and security services. In 2022, we purchased more than C$66.2 million in goods and services from the Indigenous business community, representing 30% of our total Canadian local spending. 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 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 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 14 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 have been able to direct approximately 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 three 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. Two of the three unincorporated joint venture partnerships entitle Indigenous landowners to a profit distribution calculated in accordance with the unincorporated joint venture deeds. Additionally, two of the three 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 2022 were Suncor Energy Inc, Imperial Oil Limited (a company controlled by ExxonMobil Corporation) and Fortescue Metals Group Ltd who each accounted for more than 10% of our 2022 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 Delaware North) and Cater Care for third-party facility management services. In the U.S., we primarily offer our lodge hospitality services and compete against Target Hospitality, hotels, and local mobile home and RV parks. 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 the Canadian oil sands and 50% of the rooms in the Australian coal mining regions. Our Lodge and Village Contracts During the year ended December 31, 2022, revenues from our lodges and villages represented over 62% of our consolidated revenues. Our contract terms generally provide for a rental rate for a reserved room and an occupied room rate that compensates us for hospitality services, including meals, 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 expected 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 15 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, 2022, we billed approximately 2.5 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, 2023, we have commitments for 1.2 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, 2022, we billed approximately 0.9 million room nights under our short-term take-or-pay contracts. For the year ended December 31, 2023, we have commitments for 0.2 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, 2022, we billed approximately 1.2 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, 2022, we billed approximately 0.2 million room nights to casual or walk-in customers. Our Integrated Services Contracts During the year ended December 31, 2022, revenues from our customer-owned locations represented 21% of our consolidated revenues. Our contract terms generally provide for a per guest per day rate for hospitality services, including meals and housekeeping. Similar to our owned lodge and villages contracts, in most multi-year contracts, our rates typically have annual escalation provisions to cover expected 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, 2022, we billed approximately 2.3 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. In the U.S., winter weather in the first quarter and the resulting spring break up in the second quarter have historically negatively impacted our Bakken operations. Human Capital Resources We believe that our employees are one of our greatest resources. As of December 31, 2022, we had approximately 1,400 full-time employees and approximately 1,400 hourly employees on a consolidated basis, 59% of whom are located in Canada, 39% of whom are located in Australia and 2% of whom are located in the U.S. We were party to collective bargaining agreements covering 1,123 employees located in Canada and 768 employees located in Australia as of December 31, 2022. As a company, we recognize the importance of a diverse workforce represented by people from different backgrounds, experiences and ways of looking at the world. We endeavor to hire Indigenous Peoples and expand our Indigenous workforce, excluding corporate staff, to 10% in Canada. In 2022, we reached 7% Indigenous employment, excluding corporate staff, in Canada despite challenging market conditions that resulted in reduced hiring across the region. Approximately 6% of our total new hires in Canada were of Indigenous background during 2022. 16 Civeo strives to offer competitive compensation, benefits and services that meet the needs of its 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. Civeo is committed to operating in a safe, secure and responsible manner for the benefit of its employees, customers and the communities Civeo serves in Canada, Australia and the U.S. Because we are committed to protecting the health and safety of our people, we operate in accordance with rigorous standards documented in our Making Zero Count initiative, which recognizes the importance of zero harm, while focusing on the process to achieve excellent performance. We continue to monitor the COVID-19 pandemic to help ensure the health and well-being of our employees, guests and contractors. Most of our previously implemented measures have been revised to reflect improved conditions, and are currently being integrated into a more comprehensive communicable illness plan. Our safety culture is driven by our leaders, in conjunction with active employee engagement. At Civeo, we believe that investing in our people is an investment in our own 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 provide training in the technical and managerial skills needed for employees' current and future roles, with a specific focus on safety, customer service and leadership development. Our learning and development program includes a mix of e-learning modules, face-to-face training and nationally certified programs as well as licensing training offered by external providers. 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, 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. 17 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 2022 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 that regulation took effect beginning in 2021 and the regulation sets additional monitoring and requirements for operators beginning in 2022 and 2023. These regulations will 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 Oil and Gas Commission (BCOGC) is responsible for regulating oil and gas activity in British Columbia. BCOGC 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, new 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 BCOGC completed consultation in 2022 on proposed amendments to the Drilling and Production Regulation to maintain equivalency with federal requirements. Those amendments are expected to be finalized in 2023. Meeting these regulatory requirements may result in additional costs or liabilities for our customers’ operations. Environmental Assessment of Major Projects Following a review process that began in January of 2016, Canada introduced new legislation to "rebuild public trust" in Canada's environmental review process. 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 18 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 May of 2022, the Alberta Court of Appeal released its opinion on that challenge (Opinion), with a majority concluding that the Impact Assessment Act is beyond the constitutional authority of the federal government on the basis that it encroaches too far into areas of exclusive provincial authority. The opinion is not binding and does not invalidate the Impact Assessment Act. The federal government has appealed the ruling to the Supreme Court of Canada. A decision on that appeal is expected in mid-late 2023. 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. Further, 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. These requirements may result in additional costs or liabilities for our customers’ operations. 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, 2023, the backstop price is $65 per tonne of CO2e. The current government plan is to continue increasing that price by $15 per 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 19 the path to 100 percent net zero electricity. In July 2022, the federal government published a discussion paper on options to “cap and cut oil and gas sector greenhouse gas emissions” to achieve its emissions targets and solicited feedback on different regulatory options. It is expected to publish draft regulations to implement the emissions cap in 2023. These requirements, if implemented, may result in additional costs or liabilities for our customers’ operations. In July 2022, Canada finalized Clean Fuel Regulations (CFR), which form part of its plan to reduce emissions, accelerate the use of clean technologies and fuels, and create good jobs in a diversified economy. The CFR requires liquid fuel suppliers to gradually reduce the carbon intensity of the fuels they produce and sell for use in Canada over time. Compliance with this new regulation is expected to increase the price of liquid fuels which, in turn, could increase operating costs for our customers while potentially lowering demand for some of their products. 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 December 2022, the Alberta government announced changes to the administration of the TIER Regulation, including planned increases to the carbon price and increases to annual benchmark tightening rates. These changes were announced in order to ensure that the TIER Regulation maintains equivalency with the framework established by GGPPA. Planned 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. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations and our financial condition. 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 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 20 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 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. 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. 21 Australian Environmental Regulations Our Australian segment is regulated by general statutory environmental 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 Environmental Impact Assessment (EIA). In October 2020, the findings of an independent review recommended reforms of the EPBC Act including (but not limited to) introduction of legally binding ‘National Environmental Standards’ and a ‘climate change’ referral trigger, stronger compliance and enforcement powers and proposals for new bilateral agreements with the States and Territories to streamline the EPBC Act approval process. Bills to effect many of the recommended reforms are currently before Parliament. Notably, the recommended climate change referral trigger will ensure Australia fulfills its obligations under the Paris Agreement by triggering EIA of emissions-intensive activities. It will also introduce criminal penalties for offenses relating to emissions-intensive actions. In December 2022 the federal government announced further major reforms to the EPBC Act (in response to the October 2020 review and with similar proposed reforms) and foreshadowed that a draft bill will be released mid 2023. If any of these bills are assented to, 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 policy and legislative changes may affect our customers’ operations and have impacts on the non-renewable resources sector generally. 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 island use rights which are administered by each States’ independent environment protection regulator (e.g. Queensland’s Environmental Protection Agency). If Parliament assents to the bill proposing to effect new bilateral agreements under EPBC Act, the States and Territories will be given further power to assess and approve actions under 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 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) material environmental harm. Examples of material environment harm include effluent overflow, chemical leaks and chemical fires. Failure to discharge this obligation can attract significant financial penalties. There is an increasing emphasis from state and federal 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 22 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 national legislation. 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. 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. The EPA published a final rule outlining its position on the federal jurisdictional reach over waters of the U.S. in June 2015. However, the EPA rescinded this rule in 2019 and promulgated the Navigable Waters Protection Rule in 2020. The Navigable Waters Protection Rule defined what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction and has generally been viewed as narrowing the scope of waters of the United States as compared to the 2015 rule. Litigation in multiple federal district courts is currently challenging the rescission of the 2015 rule and the promulgation of the Navigable Waters Protection Rule. On December 7, 2021, the U.S. EPA and the Department of the Army (the agencies) announced a proposed rule to revise the definition of “waters of the United States.” The agencies propose to put back into place the pre-2015 definition of “waters of the United States,” updated to reflect consideration of Supreme Court decisions. The public comment period on the proposed rule closed on February 7, 2022. On January 24, 2022, the Supreme Court agreed to consider the jurisdictional reach of the Clean Water Act again in Sackett v. EPA . Many of our U.S. properties and operations require permits for discharges of wastewater and/or storm water, and we have developed a system for securing and maintaining these permits. In April 2020, a Montana federal judge vacated the U.S. Army Corps of Engineers (Corps) Nationwide Permit (NWP) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with U.S. Fish and Wildlife Service (USFWS) under Endangered Species Act (ESA) regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and gas pipelines, and that order was partially vacated by the Ninth Circuit Court of Appeals as moot based on the Corps’ re-issuance of NWPs in 2021. In re-issuing NWP-12 in 2021, the Corps again elected not to consult with USFWS. Environmental groups have already challenged the re-issued NWP-12 in federal court. On March 28, 2022, the Corps published notice that it is undertaking formal review of NWP-12. The public comment period ended on May 27, 2022. 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 October 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. In addition, in June 2016 the EPA published new regulations to further restrict GHG emissions, such as new standards for methane and volatile organic compound (VOC) emissions from new and modified oil and gas sources. On September 11, 2018, the EPA proposed targeted improvements to the rule, including amendments to the rule’s fugitive emissions monitoring requirements, which were finalized in August 2020. Separately, in 2020, the EPA rescinded methane and volatile organic compound emissions standards for new and modified oil and gas transmission and storage infrastructure, as well as methane limits for new and modified oil and gas production and processing equipment. The EPA also relaxed requirements for oil and gas operators to monitor emissions leaks. In November 2021, the EPA proposed New Source Performance Standards (NSPS) updates and emission guidelines to reduce methane and other pollutants from the oil and gas industry. In December 2022, the EPA issued a supplemental proposal to update, strengthen, and expand the November 2021 proposed standards and further reduce methane and volatile organic compound emissions from oil and natural gas facilities. The public comment period on the proposed rule ended on January 5, 2023. 23 Additionally, in November 2016, the Bureau of Land Management (BLM) issued new regulations to reduce “waste” of natural gas, of which methane is a primary constituent, from venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian lands. In 2018, the BLM announced a revised rule which scaled back the waste-prevention requirements of the 2016 rule. This revised rule was vacated by a California federal district court in 2020, a decision which BLM has appealed to the Ninth Circuit Court of Appeals. Furthermore, separately, in October 2020, the federal district court of Wyoming vacated the original 2016 rule, a decision which BLM has appealed to the Tenth Circuit Court of Appeals. In November 2022, the BLM proposed a new iteration of the regulations. The public comment period on the proposed rule ended on January 30, 2023. Litigation is ongoing and future implementation of the BLM rules, and the Biden Administration’s reaction, is uncertain at this time. In October 2015, the EPA finalized the Clean Power Plan (CPP), which imposes additional obligations on the power generation sector to reduce GHG emissions. In August 2019, the EPA finalized the repeal of the 2015 regulations and replaced them with the Affordable Clean Energy rule (ACE), which designates heat rate improvement, or efficiency improvement, as the best system of emissions reduction for carbon dioxide from existing coal-fired electric utility generating units. In 2021, the U.S. Court of Appeals for the District of Columbia struck down the ACE rule but did not reinstate the former CPP regulation. In June 2022, the Supreme Court struck down the CPP, holding that Congress did not grant EPA the authority to devise emissions caps based on the generation-shifting approach the EPA took in the CPP. 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. 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. In addition, the Biden Administration has issued multiple executive orders pertaining to environmental regulations and climate change, including the Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and Executive Order on Tackling the Climate Crisis at Home and Abroad. In the latter executive order, President Biden established climate change as a primary foreign policy and national security consideration, affirmed that achieving net-zero greenhouse gas emissions by or before midcentury is a critical priority, affirmed the Biden Administration’s desire to establish the U.S. as a leader in addressing climate change, generally further integrated climate change and environmental justice considerations into government agencies’ decision making, and eliminated fossil fuel subsidies, among other measures. 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. For example, in the U.S., the federal Resource Conservation and Recovery Act, as amended (RCRA) and comparable state statutes regulate the generation, storage, treatment, transportation, disposal and cleanup of hazardous and non-hazardous solid wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. In the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. Moreover, the federal Comprehensive Environmental Response, Compensation and Liability Act, as amended (CERCLA), also known as the Superfund law, and 24 comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred and anyone who transported, disposed or arranged for the transport or disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate materials in the course of our operations that may qualify as hazardous substances. In the event of mismanagement or release of regulated substances upon properties where we conduct operations, we could become subject to liability and/or obligations under CERCLA, RCRA and/or analogous 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 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. Additionally, in 2016, the federal Bureau of Land Management (BLM) under the Obama Administration published a final rule imposing more stringent standards on hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity, and handling of flowback water. However, in late 2018, the BLM under the Trump Administration published a final rule rescinding the 2016 final rule. While the 2016 rule has been rescinded, new or more stringent regulations may be promulgated by the Biden administration. 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. 25