What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2022-02-28 compared with 2021-02-26 · 187 added, 143 removed, 594 unchanged (36% of the section changed)

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We provide hospitality services to the natural resources industry in Canada, Australia and the U.S.

We provide a full suite of hospitality services for our guests, including lodging, food service, housekeeping and maintenance at accommodation facilities that we or our customers own.

We provide a full suite of hospitality 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 provide services that support the day-to-day operations of accommodation facilities, such as laundry, facility management and maintenance, water and wastewater treatment, power generation, communication systems, security and logistics.

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and villages in Australia, or at facilities owned by our customers.

We own and operate 28 lodges and villages with a total of approximately 30,000 rooms.

We own and operate 27 lodges and villages with over 28,000 rooms.

We operate approximately 9,500 rooms owned by our customers.

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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.

In 2020, demand for our services was impacted by the significant decline in oil prices stemming from global oversupply of oil coupled with the historic decline in oil demand due to the COVID-19 pandemic.

Canadian oil prices were also impacted by provincial oil production curtailments and continued insufficient long-term takeaway capacity.

Global oil demand has recovered throughout 2021 and into 2022 as COVID-19 lockdowns have begun to be lifted and other fossil fuels are experiencing supply shortages.

Oil supply did not keep up with the increase in demand in 2021, which was exacerbated by the impacts of Hurricane Ida in the Gulf of Mexico in the summer of 2021 and publicly-traded oil producers prioritizing returns of capital to shareholders over deploying capital to expand production capacity, resulting in falling inventories and a significant increase in oil prices.

Natural gas prices also influence oil sands activity as an input cost:

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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, 20-25%, of the headcounts experienced during construction.

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 demand, particularly in Asia, for LNG.

We expect that LNG 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.

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 Royal Dutch 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).

LNGC 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.

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 the COVID-19 pandemic.

See "Canada-Canadian British Columbia Lodge" for more information.

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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.

Since 2017, our customer service requirements have primarily been driven by production, maintenance and operational activities.

More recently, we have seen an increase in the number of significant maintenance projects, along with customers initiating projects to optimize their operations.

Our customer service requirements are primarily driven by production, maintenance and operational activities.

Recently, we have seen a stabilization in the number of significant maintenance projects, along with customers initiating projects to optimize their operations.

This work has also included some small mine expansion projects.

Current met coal prices and global economic and political uncertainty make it unlikely that our customers will move forward with major met coal expansionary projects in 2021.

Customer growth projects for met coal could be sanctioned later in 2021 and into 2022 should the global economy and met coal prices stabilize.

However, current high iron ore prices are conducive to customer growth projects and we expect to support several such growth projects in Western Australia in 2021.

Current met coal prices are at a level that may induce our customers to move forward with met coal expansionary projects in 2022.

However, global economic and political uncertainty due primarily to COVID-19 pandemic conditions still cast uncertainty over whether any met coal expansion projects will be approved, notwithstanding the current favorable met coal price.

Further, coal customers are experiencing difficulty gaining funding for new projects.

After a period of high iron ore prices in 2021, prices are expected to stabilize into 2022.

operations are primarily tied to activity in the U.S.

shale formations in the Permian Basin, the Mid-Continent, the Bakken and the Rockies, as well as activity in the Louisiana downstream and offshore Gulf of Mexico markets.

shorter investment horizon and decision cycle of our U.S.

Given the shorter investment horizon and decision cycle of our U.S.

customers, which is typically on a well-by-well basis, spending activities of U.S.

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at the end of 2021.

market for drilling rig accommodations is primarily supported by mobile assets, competition for well accommodations is primarily driven by the availability of permanent and temporary camp assets in the markets we service and pricing among our competitors, including hotels.

For the years ended December 31, 2020, 2019 and 2018, we generated $529.7 million, $527.6 million and $466.7 million in revenues and $147.2 million, $49.1 million and $88.1 million in operating loss, respectively.

market for drilling rig accommodations is primarily supported by mobile assets, competition for wellsite accommodations is primarily driven by the availability of permanent and temporary camp assets in the markets we service and pricing among our competitors, including hotels.

For the years ended December 31, 2021, 2020 and 2019, we generated $594.5 million, $529.7 million and $527.6 million in revenues and $6.1 million, $(147.2) million and $(49.1) 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.

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Australia 145,335 144,070 126,047

United States 2,451 12,462 18,288

5,437 2,451 12,462

Total Accommodation Revenue $ 390,298 $ 349,055 $ 420,086

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Canada $ 62,856 $ 33,192 $ 9,575

United States 16,837 28,119 20,389

14,486 16,837 28,119

Total Mobile Facility Rental Revenue $ 77,342 $ 50,029 $ 37,694

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Australia 105,739 90,472 30,046

United States 50 145 170

Total Food Service and Other Services Revenue $ 124,785 $ 124,445 $ 63,676

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Canada $ — $ — $ 1,014

United States 6,200 5,085 12,595

2,038 6,200 5,085

Total Manufacturing Revenue $ 2,038 $ 6,200 $ 6,099

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dollar 0.75 0.69 0.70

(1) Includes revenues related to lodge and village rooms and hospitality services for owned rooms for the periods presented.

(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.

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(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 the periods presented.

(6) Billed rooms represents total billed days for Civeo owned rooms for the periods presented.

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.

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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 integrated services) to the mining industry in Western Australia.

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.

We provide hospitality services for the natural resource industries.

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 hospitality services such as lodging, food service, housekeeping, and maintenance, as well as operations, including laundry, water and wastewater treatment, power generation, communication systems, security and logistics.

Once facilities are deployed in the field, we also provide hospitality services such as lodging, catering and food service, housekeeping and maintenance, as well as operations, 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.

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and (4) oil production in the U.S.

Historically, Canadian oil sands developers and Australian mining companies built, owned and in some cases operated the accommodations necessary to house their personnel in these remote regions because local labor and third-party owned

rooms were not available.

Historically, Canadian oil sands developers and Australian mining companies built and owned the accommodations necessary to house their personnel in these remote regions because local labor and third-party owned rooms were not available.

Over the past 20 years, and increasingly over the past 10 years, some customers have moved away from the 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.

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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 pipeline takeaway capacity;

Demand for our Canadian lodges is secondarily impacted by oil takeaway capacity;

and, in 2018, a provincial oil production curtailment policy was imposed by the Government of Alberta.

However, monthly production limits were put on hold in December 2020 until further notice, allowing operators to produce freely at their discretion while the government monitors production.

Should forecasts show storage inventories approaching maximum capacity, the government may reintroduce production limits.

However, monthly production limits were put on hold in December 2020 until further notice, allowing operators to produce freely at their discretion in 2021 while the government monitors production and inventory levels.

Demand for hospitality services related to LNG is influenced by the global prices for LNG.

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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, very low exploration or reserve risk and relatively lower cash operating costs per barrel of bitumen produced.

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.

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In order to operate a lodge in Canada, we are required to obtain a development permit from the regional municipality in which the lodge resides.

The development permits are granted for a term ranging from one to ten years.

The development permits are granted for a term of five years.

Our development permits have expiration dates that range from 2022 to 2026.

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See “Item 1A.

Risk Factors-Risks Related to Our Business-The majority of our major Canadian lodges are located on land subject to leases.

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.

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Canadian British Columbia Lodge

As previously discussed, in October 2018, LNGC's partners announced a positive FID on the Kitimat LNG Facility.

British Columbia LNG activity and related Coastal GasLink (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.

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.

We previously announced contract awards for locations along the CGL pipeline project and room commitments for our Sitka Lodge.

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, including recent blockades that aim to delay construction.

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 and the COVID-19 pandemic.

Our current expectation is that our contracted commitments associated with the CGL pipeline project will be completed in early 2023.

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Athabasca mining 1,997 1,997 1,997

Athabasca mining/in-situ — — 1,698

Beaver River (2)

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Athabasca mining 946 946 947

Athabasca in situ — — 664

Athabasca mining 624 624 624

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Athabasca in-situ 526 526 526

Mariana Lake (1)

Athabasca mining — — 686

Subtotal – Oil Sands 17,988 18,066 18,463

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(1) Permanently closed as of December 31, 2021.

(2) Currently closed as of December 31, 2020, due to low activity level in the region.

All seven closed lodges are periodically assessed for impairment, in accordance with U.S.

(2) Currently closed as of December 31, 2021, 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 (U.S.

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Historically, this has been focused around natural resource production-related housing facilities that are owned by oil production companies.

The facilities we manage range anywhere from 100 to 1,500 rooms.

The facilities we manage typically range anywhere from 100 to 1,500 rooms.

We customize our service offerings depending on our customer’s needs.

Hospitality services can be performed on an end-to-end basis with food service, housekeeping, maintenance and utility services included or in segments such as food service only.

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 quickly configured to serve a multitude of short to medium-term accommodation needs.

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.

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During the year ended December 31, 2021, we generated 42% of our revenue from our Australian operations.

As of December 31, 2020, we owned 9,046 rooms across nine villages, of which 7,392 rooms service the Bowen Basin region of Queensland, one of the premier met coal basins in the world.

As of December 31, 2021, we owned 9,046 rooms across nine villages, of which 7,392 rooms service the Bowen Basin of 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.

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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 and Kimberly regions of Western Australia, which are renowned for high grade iron ore production.

In addition, we provide village operation and mine site cleaning services at five customer locations in the Pilbara and Kimberly regions of Western Australia, which are 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.

Currently China and Australia are in a trade dispute that has led to China implementing an unofficial trade embargo on Australian coal.

China has historically accounted for approximately 22% of Australia’s met coal exports.

The continuing uncertainty in the demand for met coal, related to the impact of Chinese bans on the importation of Australian commodities, led to a decrease in the met coal spot price to US$103 per tonne at December 31, 2020.

The softening of the met coal spot price at the end of 2020 has been exacerbated as Chinese mills and traders resell stranded Australian met coal at a discount.

As a result, there is currently a shuffling of global export trade flows, coupled with growing demand for steel with an infrastructure led recovery which may lead to near term growth in Australian met coal spot pricing.

Should this dispute continue, it could negatively impact pricing and demand for Australian met coal.

To date, we have not seen an overall material decline in occupancy at our Australian villages resulting from the COVID-19 pandemic or the Chinese trade dispute.

Currently, the Chinese embargo on certain Australian exports, including exported Australian met coal, continues without any resolution foreseeable in the near term.

However, Australian met coal producers have found new markets, including India and Europe, for their premium product.

This has led to a rebalancing of the market globally, with China relying on domestic production along with much higher volumes of imports of U.S., Canadian and Mongolian met coal in 2021.

With the backdrop of continuing strong steel demand and met coal supply constraints, the spot price for met coal surged to record highs of over $400 in October 2021 and remain at this level.

Analysts expect elevated met coal prices to persist in the short-term, while steel demand and prices remain strong and until met coal supply issues are resolved.

If the trade impasse with China remains unresolved, there remains a possibility of further volatility in the short to medium term.

Beyond the Pilbara and Bowen Basins, we serve several other markets with four additional villages and five customer-owned villages.

At the end of 2021, 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 and gold production in the Goldfields region through our Kambalda village.

In Western Australia, we serve workforces related to LNG facilities operations on the Northwest Shelf through our Karratha village and lithium and gold production in the Goldfields region through our Kambalda village.

In addition, we provide hospitality services in Western Australia at five customer-owned villages which support workforces related to nickel, copper, zinc, silver and gold production in the Goldfields-Esperance region and lithium production in the Pilbara region.

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Nebo Bowen met coal 490 490 490

- LNG — — 300

Kambalda - Gold, lithium 232 232 232

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Total Rooms 9,046 9,046 9,046

(1) Sold in September 2019.

Our Australian segment includes nine company-owned villages with 9,046 r ooms as of December 31, 2020, which are strategically located near long-lived, low-cost mines operated by large mining companies.

Our Australian segment includes nine company-owned villages with 9,046 rooms as of December 31, 2021, 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.

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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 eleven customer-owned locations, which represent over 7,000 rooms, primarily in the Pilbara region of Western Australia, one of the premier iron ore bodies in the world, and in the Kimberly and Goldfields-Esperance regions of Western Australia.

The facilities we manage range anywhere from 200 to 1,750 rooms.

We provide village operation services at ten customer-owned locations, which represent over 7,000 rooms, primarily in the Pilbara region of Western Australia, one of the premier iron ore bodies in the world, and in the Kimberly and Goldfields-Esperance regions of Western Australia.

The facilities we manage range anywhere from 200 to over 1,700 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 food service, housekeeping and site maintenance included or in segments such as food service only.

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.

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We provide a variety of sizes and configurations to meet the needs of E&P companies, completion companies, infrastructure construction projects and offshore drilling and completion activity.

With the recent volatility in oil prices and a resulting reduction in spending by E&P companies, we have exited the Bakken and reduced our presence in the Rockies regions for our mobile assets.

Those assets will either be sold or transported to our Permian Basin and Mid-Continent district locations.

This process is underway and we expect it to be completed during the first half of 2021.

With the recent volatility in oil prices and a resulting reduction in spending by E&P companies, we exited the Bakken and reduced our presence in the Rockies regions for our U.S.

mobile assets.

Those assets were either sold or transported to our Permian Basin and Mid-Continent district locations.

Our mobile assets are rented on a per unit basis based on the number of days that a customer utilizes the asset.

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State 2021 2020 2019

West Permian TX 390 410 390

West Permian (1)

Acadian Acres LA 300 300 300

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Total Rooms 535 925 945

We had three lodges in the U.S.

(1) Sold in October 2021.

We had two lodges in the U.S.

comprised of 535 rooms as of December 31, 2021.

Our Killdeer Lodge provides rooms to the Bakken Shale region in North Dakota.

Our West Permian Lodge supports the Permian Basin in West Texas.

Our Acadian Acres Lodge provides rooms near Lake Charles, Louisiana to support the Louisiana downstream market.

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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 2020, the annual value of these contracts was approximately C$40 million.

In 2021, we purchased more than C$56.5 million in goods and services from the Indigenous business community, representing 32% 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 were awarded 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.

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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.

Our partnerships in British Columbia are tied to accommodations contracts secured by Civeo for the Kitimat LNG Facility and for the Coastal Gas Link pipeline project that originates in the North Montney region of north east British Columbia.

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 between Edmonton, Alberta and Burnaby, British Columbia.

Beyond revenue sharing, these arrangements provide procurement, employment, training, and ancillary business opportunities for Indigenous owned businesses.

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These improvements provide necessary infrastructure, allowing the local communities an opportunity to expand and improve.

In addition, we have five unincorporated joint venture partnerships with indigenous landowners in Western Australia.

These agreements assist to develop the business capacity, project management skills and expertise of the indigenous joint venture members and also provide local employment opportunities and training.

Three of the five unincorporated joint venture partnerships entitle indigenous landowners to a profit distribution calculated in accordance with the unincorporated joint venture deeds.

The remaining two agreements incentivize the joint venture members via milestone payments for business objectives achieved.

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$5.7 million each year 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.

The remaining agreement incentivizes the joint venture members via milestone payments for business objectives achieved.

Customers and Competitors

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To a lesser extent, we also support other activities, including pipeline construction, forestry and humanitarian aid.

Our largest customers in 2020 were Fortescue Metals Group Ltd and Imperial Oil Limited (a company controlled by ExxonMobil Corporation) who each accounted for more than 10% of our 2020 revenues.

Our largest customers in 2021 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 2021 revenues.

Our primary competitors in Canada in lodge and mobile asset hospitality services include ATCO, Black Diamond, Dexterra and Clean Harbors, Inc.

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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 and Compass Group 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 Algeco Group) and Fleetwood Corporation.

We also compete against Sodexo, Compass Group and Cater Care for third-party facility management services.

In the U.S., we primarily offer our lodge and mobile asset hospitality services and compete against Peak Oilfield Services (a subsidiary of Select Energy Services), Stallion Oilfield Holdings, Inc., Target Hospitality, HB Rentals (a subsidiary of Superior Energy Services), Oil Patch and Black Diamond.

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 Algeco 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.

Historically, many customers have invested in their own accommodations.

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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.

In some contracts, customers have a contractual right to terminate rooms, for reasons other than a breach, in exchange for a termination fee.

In some contracts, customers have a contractual right to terminate, for reasons other than a breach, in exchange for a termination fee.

As of December 31, 2021, excluding exclusivity contracts and contracts without minimum room commitments, we had commitments for 29% of our rentable rooms for 2022 and 9% of our rentable rooms for 2023.

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Contracted Room Expiration

Thereafter 3,473

The contracts expire throughout the year, and for many of the near-term expirations, we are in the process of negotiating extensions or new commitments.

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We were party to collective bargaining agreements covering 1,071 employees located in Canada and 617 employees located in Australia as of December 31, 2021.

Attracting, retaining and mentoring the talent required to address the needs of our business is the basis of our human capital strategy.

Not only do we provide what we believe to be a competitive and well-rounded compensation package, but we also believe that our exceptional safety record attracts and retains exceptional talent.

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.

During 2020, we formed a Diversity and Inclusion Committee to help us serve our employees, clients and communities better as we strive to build a culture of inclusion.

In Canada, we are committed to hiring Indigenous Peoples and expanding our Indigenous workforce, excluding corporate staff, to 10%.

In Canada, we endeavor to hire Indigenous Peoples and expand our Indigenous workforce, excluding corporate staff, to 10%.

In 2021, we reached 7% Indigenous employment, excluding corporate staff, in Canada despite challenging market conditions that resulted in reduced hiring in the region.

Approximately 7% of our total new hires in Canada were of Indigenous background during 2021.

In addition, our Indigenous Procurement Policy in Canada helps foster strong community relationships while ensuring a local and diverse supply chain of business partners.

In 2020, we purchased more than C$39 million in goods and services from the Indigenous business community, representing 25% of our total Canadian local spending.

In Australia, 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$1.4 million each year into Indigenous-owned and operated companies, and we are always looking for more opportunities to partner with these businesses.

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.

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Because we are committed to protecting the health and safety of our people, we operate in accordance with rigorous standards documented in an award-winning Health and Safety Process that has been recognized by industry associations as one of the best.

In response to the COVID-19 pandemic, we have taken measures to help ensure the health and well-being of our employees, guests and contractors, including screening of individuals that enter our facilities, social distancing practices, enhanced cleaning and deep sanitization, the suspension of nonessential employee travel and implementation of work-from-home policies, where applicable.

We continue to closely monitor the COVID-19 pandemic and have taken measures to help ensure the health and well-being of our employees, guests and contractors, including screening of individuals that enter our facilities, social distancing practices, enhanced cleaning and deep sanitization, the suspension of nonessential employee travel and implementation of work-from-home policies, where applicable.

Our safety culture is driven by our leaders, in conjunction with active employee engagement.

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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.

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

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.

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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.

We believe that we are in substantial compliance with existing environmental laws and regulations and 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.

However, 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.

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.

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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 and are expected to take effect in 2021.

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 will set 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.

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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 2021, with additional requirements set to take effect in 2022.

Meeting these regulatory requirements may result in additional costs or liabilities for our customers’ operations.

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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.

There is considerable uncertainty about whether and how the Impact Assessment Act and its regulations will be administered and whether the time and cost associated with completing the planning, assessment and decision-making phases of that act will increase substantially compared to CEAA 2012.

One of the stated objectives of the Impact Assessment Act was to shorten review times for projects that are subject to review under that Act.

However, concerns about lengthy reviews that require substantial information from project proponents remain even after the implementation of the Impact Assessment Act.

Our customers operate in the aforementioned industries and could be considering future projects that would be subject to the Impact Assessment Act.

To the extent our customers are required to comply with this legislation, it is possible that the uncertainty regarding cost and timelines for navigating the planning, assessment, and decision-making processes may negatively impact our customers' decisions on whether to proceed with those projects.

In 2019, the Government of Alberta initiated a challenge to the constitutionality of the Impact Assessment Act and regulations made under that Act.

The Alberta Court of Appeal has not yet issued a decision in that case, and it is likely that any decision issued by that Court would be appealed to the Supreme Court of Canada.

The Government of Alberta, supported by the governments of Ontario and Saskatchewan, has challenged the constitutionality of the Impact Assessment Act and requested that the federal legislation be invalidated by the Alberta Court of Appeal on the basis that it encroaches on provincial jurisdiction.

A decision on that litigation is pending, and it is likely that any decision issued by that Court would be appealed to the Supreme Court of Canada.

As a result, there is significant uncertainty about the future application of Canada's federal environmental assessment legislation to our customers.

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These requirements may result in additional costs or liabilities for our customers’ operations.

In March 2016, as a further effort to meet Canada’s INDC, representatives of the federal and the majority of provincial governments committed to imposing a price on carbon pollution, beginning at $10 per tonne in 2018 and increasing at a rate of $10 annually to $50 per tonne in 2022.

In December 2020, the Canada's federal government announced that, after 2022, the price on carbon pollution would increase by $15 per tonne annually, reaching $170 per tonne in 2030.

To implement its INDC and PCF commitments, the federal government introduced the Greenhouse Gas Pollution Pricing Act , which as of its assent in June 2018 implements a federal legislative carbon pricing “backstop”.

This applies a benchmark carbon price in any province that does not establish an equivalent framework at or above the benchmark level.

This allows GHG regulation to take place at the provincial level, where provinces may choose between an explicit price-based

system (as exists in British Columbia) or a cap-and-trade system (as exists in Quebec).

The federal backstop is only being applied to provinces in which no equivalent framework is in place.

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.

Under current federal plans, this price will escalate by $10 per year until it reaches a price of $50/tonne of CO2e in 2022.

On December 11, 2020, however, the federal government announced its intention to continue the annual price increases beyond 2022, such that, commencing in 2023, the benchmark price per tonne of CO2e will increase by $15 per year

until it reaches $170/tonne of CO2e in 2030.

Starting April 1, 2021, the minimum price permissible under the GGPPA is $40/tonne of CO2e.

Alberta, Saskatchewan, and Ontario challenged the constitutionality of the GGPPA through separate proceedings in their respective Courts of Appeal.

Following split decisions by the provincial appellate courts, the appeals were consolidated and heard by Supreme Court of Canada.

On March 5, 2021, the Supreme Court issued its decision upholding the GGPPA as a valid exercise of federal legislative jurisdiction.

On November 19, 2020, the federal government introduced the Canadian Net-Zero Emissions Accountability Act in Parliament.

That Act was passed by Parliament and received Royal Assent on June 29, 2021 and binds the Government of Canada to a process intended to help Canada achieve net-zero emissions by 2050.

It also establishes rolling five-year emissions-reduction targets and requires the government to develop plans to reach each target.

The federal government is required to support those efforts by creating a Net-Zero Advisory Body and by publishing annual reports that describe how departments and Crown corporations are considering the financial risks and opportunities of climate change in their decision-making.

At the 26th Conference of the Parties to the UNFCCC (COP 26), held in Glasgow between October 31 and November 13, 2021, Canada presented a strengthened climate plan and committed to an enhanced emissions reduction target of between 40 and 45 percent below 2005 levels by 2030.

Following a 2021 federal election, the Government of Canada delivered a new Throne Speech in November 2021 which reiterated its intent to take action that would "go further, faster" to fight climate change.

Among other things, the federal government pledged to cap and cut oil and gas sector emissions while accelerating on the path to 100 percent net zero electricity.

Details on the implementation of these policy commitments evolve over time and are likely to continue to do so for the foreseeable future.

To the extent acting on Canada's COP 26 commitments results in additional legislative or executive action, such action could result in additional costs or liabilities for our customers’ operations.

In December 2020, the federal government published draft regulations referred to as the Clean Fuel Standard (CFS), 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.

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In Alberta, the previous provincial government's Climate Leadership Plan (CLP), was launched in November 2015.

This framework was approved as meeting the PCF benchmark and exempting Alberta from the federal backstop.

Among other things, the CLP proposed a framework for managing GHG emissions by reducing specified gas emissions, relative to total production from facilities that emit over 100,000 tons of carbon dioxide equivalent per year.

This framework was approved as meeting the GGPPA benchmark and exempting Alberta from the federal backstop.

Among other things, the CLP proposed a framework for managing GHG emissions by reducing greenhouse gas emissions, relative to total production from facilities that emit over 100,000 tons of carbon dioxide equivalent per year.

The details of this framework were set out in legislation and regulations issued after the CLP.

The previous Alberta government then passed the Climate Leadership Act (CLA), implementing the broad economy-wide levy on GHG emissions, subject to limited exceptions as well as the Oil Sands Emissions Limit Act, which imposes a 100 mega-ton annual limit on GHG emissions from oil sands sites.

The CLP also targeted the phasing out of coal-generated electricity (or the emissions therefrom) by 2030.

In addition, the previous Alberta provincial government issued the Carbon Competitiveness Incentive Regulation (CCIR) to replace the former Specified Gas Emitters Regulation.

Like its predecessor, the CCIR sought to incentivize emissions reductions through the use of emissions intensity targets.

Under CCIR, a company could meet the applicable emissions limits by making emissions intensity improvements at regulated facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring “fund credits” (akin to allowances) by making payments for each ton of GHG emissions over the required reduction target to the Alberta Climate Change and Emissions Management Fund.

In April 2019, the previous Alberta government was replaced with a new conservative government following a general election.

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Features of the backstop also took effect at various points in 2019 in Ontario, New Brunswick, Manitoba, Saskatchewan, Yukon, Nunavut and Prince Edward Island.

Alberta, Saskatchewan and Ontario are challenging the federal backstop in court on the basis that the federal government lacks the constitutional ability to implement the measure.

The Supreme Court of Canada heard arguments on the constitutionality of the federal backstop in 2020 and is expected to release its decision in 2021.

The outcome of this litigation is uncertain and could affect our customers’ compliance requirements in provinces subject to the backstop.

In addition, the Oil Sands Emissions Limit Act remains in force.

While the current Alberta government eliminated the provincially-imposed economy-wide levy on GHG emissions, facilities that emit more than 100,000 tons of GHG emissions in a calendar year continue to be subject to regulations that impose costs on those emissions.

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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.

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.

In 2019, certain First Nations groups and environmental organizations commenced litigation intended to force the federal minister of environment to recommend that the federal government implement certain protections for woodland caribou habitat.

That litigation was discontinued in 2020, with the federal and Alberta governments announcing an agreement to collaborate on developing measures to achieve woodland caribou conservation and recovery.

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.

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Conservation measures imposed by the federal government or Alberta government could affect the business of our customers with operations near caribou habitat.

Abandonment and Remediation of Oil and Gas Infrastructure

As the lifecycle regulator for energy resource activities, the AER oversees closure requirements, including the abandonment and reclamation of wells, well sites, facilities, facility sites, and pipelines.

Historically, the AER discharged this role through its Liability Management Rating Program (AB LMR Program).

The AB LMR Program relied on the ratio of a company's assets and liabilities (Liability Management Ratio or LMR) to assess whether the company would be able to address closure obligations.

Where a company's liabilities exceeded their assets (resulting in a LMR of less than 1.0), the AER could require the company to post security to bring the ratio to 1.0.

The AB LMR Program was developed during a period of rapid growth in the province when companies were focused on well and infrastructure expansion.

In recent years, it became clear that the LMR Program needed to be updated to reflect declining production and aging infrastructure.

As a result of the Supreme Court of Canada's decision in Orphan Well Association v Grant Thornton (also known as the Redwater decision), receivers and trustees can no longer avoid the AER's legislated authority to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a license transfer when any such licensee is subject to formal insolvency proceedings.

This means that insolvent estates can no longer disclaim assets that have reached the end of their productive lives (and therefore represent a net liability) in order to deal primarily with the remaining productive and valuable assets without first satisfying any abandonment and reclamation obligations associated with the insolvent estate's assets.

In April 2020, the Government of Alberta passed the Liabilities Management Statutes Amendment Act, which places the burden of a defunct licensee's abandonment and reclamation obligations first on the defunct licensee's working interest partners, and second, the AER may order the orphan fund (Orphan Fund) established under the Oil and Gas Conservation Act (OGCA) to assume care and custody and accelerate the clean-up of wells or sites which do not have a responsible owner.

These changes will come into force on proclamation.

As a result of the changing landscape and new direction from the Redwater decision, in July 2020, the Government of Alberta began implementing changes to its liability management policy.

In particular, in July 2020, the Province released a new Liability Management Framework (AB LMF) which includes a series of mechanisms and requirements to improve and expedite reclamation efforts and to require industry to better manage clean-up of oil and gas wells, pipelines and facilities.

Notably, the AB LMF provided policy direction allowing the AER to take "Licensee Special Action" to assist operators in managing their assets and maintaining operations under certain circumstances.

The Government of Alberta followed the announcement of the AB LMF with amendments to the Oil and Gas Conservation Rules and the Pipeline Rules in late 2020.

The changes to these rules fall into three broad categories:

(i) they introduce "closure" as a defined term, which captures both abandonment and reclamation;

(ii) they expand the AER's authority to initiate and supervise closure;

and (iii) they permit qualifying third parties on whose property wells or facilities are located to request that licensees prepare a closure plan.

The AB LMF provided Government of Alberta policy direction on managing energy sector closure requirements.

The AER implements and administers that policy through directives.

In April 2021, the AER made changes to Directive 067:

Eligibility Requirements for Acquiring and Holding Energy Licenses and Approvals (Directive 067) 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 067, 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 088:

Licensee Life-Cycle Management (Directive 088) and supporting guidance information to further support implementing the AB LMF.

Among other things, Directive 088 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 088 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 088 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.

Alberta’s Electricity Market

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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.

Many of our U.S.

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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 is currently on appeal in the Ninth Circuit.

However, the Montana district court’s decision spawned other NWP 12-based challenges and may indicate that the rest of the NWPs, some of which are relied upon by oil and gas projects, are vulnerable to similar challenge.

The Corps has proposed a new set of NWPs, which would replace the NWPs for dredge or fill discharges into waters of the United States that the Corps last issued and made available in 2017.

However, the Corps has elected not to consult with USFWS at this time.

If this status quo does not change, when the Corp re-issues the NWPs, the NWPs could be subject to the same legal challenges unless and until the ongoing litigation resolves the questions surrounding the need for a formal ESA consultation.

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.

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.

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In addition, the EPA has finalized new regulations that would further restrict GHG emissions, such as new standards for methane and volatile organic compound (VOC) emissions from new and modified oil and gas sources, which the EPA published in June 2016.

On September 11, 2018, the EPA proposed targeted improvements to the rule, including amendments to the rule’s fugitive emissions monitoring requirements, and is in the process of finalizing the amendments, which it originally expected to do in late 2019.

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 NSPS updates and emission guidelines to reduce methane and other pollutants from the oil and gas industry.

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.

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Furthermore, separately, in October 2020, the federal district court of Wyoming vacated the original 2016 rule.

In October 2015, the EPA finalized the Clean Power Plan, which imposes additional obligations on the power generation sector to reduce GHG emissions.

This 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.

Both the appropriateness of the repeal of the 2015 regulations and the adequacy of ACE are currently subject to litigation.

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.

The power of EPA to reissue the CPP under Section 111(d) of the CAA will be decided by the Supreme Court in 2022.

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.

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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.

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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 a process sometimes used to stimulate production of hydrocarbons from tight formations.

The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production.

Hydraulic fracturing is typically regulated by state oil and natural gas regulators, but EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (SDWA) over, and issued permitting guidance in February 2014 for, certain hydraulic fracturing activities involving the use of diesel fuels.

In May 2014, EPA issued an advance notice of proposed rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act (TSCA) to require companies to disclose information regarding the chemicals used in hydraulic fracturing.

In March 2015, BLM issued a final rule that imposes requirements on hydraulic fracturing activities on federal and Indian lands, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water;

similar final rules were published in November 2016 for hydraulic fracturing activities on National Park and National Wildlife Refuge System lands.

In June 2016, the U.S.

District Court for the District of Wyoming struck down the BLM final rule, finding that BLM lacked authority to promulgate the rule, but this ruling was vacated on appeal in September 2017.

Regardless, BLM rescinded this rule in December 2017.

In January 24, 2018, California and a coalition of environmental groups each filed lawsuits in the Northern District of California to challenge BLM’s rescission of the 2015 rule.

The Northern District of California upheld the rescission in 2020, but this decision was then appealed to the Ninth Circuit Court of Appeals.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of chemicals used in the hydraulic fracturing process.

Some states and local governments also have adopted or are considering adopting regulations to restrict or ban hydraulic fracturing in certain circumstances.

Moreover, ongoing governmental reviews of the environmental impacts of hydraulic fracturing by EPA and other agencies could lead to further regulation of hydraulic fracturing.

For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.

The final report concluded that hydraulic fracturing activities can impact drinking water under some circumstances, including large volume spills and inadequate mechanical integrity of wells.

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.

Litigation challenging the BLM's 2016 final rule as well as the 2018 final rule rescinding the 2016 rule has been pursued by various states, industry and environmental groups.

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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business