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UNITED STATES 
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K 
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________________________ to                                                                   

 Commission file number: 001-36246
 Civeo Corporation
____________

 (Exact name of registrant as specified in its charter) 
British Columbia, Canada98-1253716
(State or other jurisdiction of(I.R.S. Employer
incorporation or organization)Identification No.)
  
Three Allen Center, 333 Clay Street, Suite 4980,
 
Houston, Texas
77002
(Address of principal executive offices)(Zip Code)
713 510-2400
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s)Name of Exchange on Which Registered
Common Shares, no par valueCVEONew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes                  ☐No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
YesNo

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
YesNo

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
YesNo




Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of "accelerated filer," "large accelerated filer," "smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
(Check one):

Large Accelerated FilerAccelerated Filer
 
Emerging Growth Company
 
   
Non-Accelerated Filer Smaller Reporting Company
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
 
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
YesNo

The aggregate market value of common shares held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter, June 30, 2020, was $81,953,395.
 
The Registrant had 14,286,290 common shares outstanding as of February 22, 2021.
 
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Definitive Proxy Statement for the 2021 Annual General Meeting of Shareholders, which the registrant intends to file with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K, are incorporated by reference into Part III of this Annual Report on Form 10-K.




CIVEO CORPORATION
 
INDEX
 
  Page No.
 
   
   
  
Item 6.Selected Financial Data
   
  
   
  
   

 


i


PART I
 
This annual report on Form 10-K (annual report) contains certain “forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the Securities Act) and Section 21E of the Securities Exchange Act of 1934 (the Exchange Act). Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of known material factors that could affect our results, please refer to “Part I, Item 1. Business,” “Part I, Item 1A. Risk Factors,” “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this annual report.
 
In addition, in certain places in this annual report, we refer to reports published by third parties that purport to describe trends or developments in the energy industry. We do so for the convenience of our shareholders and in an effort to provide information available in the market that will assist our investors in a better understanding of the market environment in which we operate. However, we specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

On November 19, 2020, we effected a reverse share split where each twelve issued and outstanding common shares were converted into one common share (the Reverse Share Split). Our common shares began trading on a reverse share split-adjusted basis on November 19, 2020. All common share and per common share data included in this annual report have been retroactively adjusted to reflect the Reverse Share Split.

Cautionary Statement Regarding Forward-Looking Statements
 
We include the following cautionary statement to take advantage of the "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995 for any "forward-looking statement" made by us or on our behalf. All statements other than statements of historical facts included in this annual report are forward-looking statements. The forward-looking statements can be identified by the use of forward-looking terminology including “may,” “expect,” “anticipate,” “estimate,” “continue,” “believe” or other similar words. Such statements may include statements regarding our future financial position, budgets, capital expenditures, projected costs, plans and objectives of management for future operations and possible future strategic transactions. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf.
 
In any forward-looking statement where we, or our management, express an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result or be achieved or accomplished. Taking this into account, the following are identified as important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by, or on behalf of, us:

the level of supply and demand for oil, metallurgical coal, natural gas, iron ore and other minerals;

the level of activity, spending and developments in the Canadian oil sands;

the level of demand, particularly from China, for coal and other natural resources from and investments and opportunities in Australia;

the availability of attractive oil and natural gas field assets, which may be affected by governmental actions or environmental activists which may restrict drilling;

fluctuations in the current and future prices of oil, coal, natural gas, iron ore and other minerals;

failure by our customers to reach positive final investment decisions on, or otherwise not complete, projects with respect to which we have been awarded contracts to provide related hospitality services, which may cause those customers to terminate or postpone the contracts;

fluctuations in currency exchange rates;
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the impact of the ongoing COVID-19 pandemic and the response thereto;

general global economic conditions and the pace of global economic growth;

changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof, including taxing authorities not agreeing with our assessment of the effects of such laws, treaties and regulations;

changes to government and environmental regulations, including climate change;

global weather conditions, natural disasters, global health concerns and security threats;

our ability to hire and retain skilled personnel;

the availability and cost of capital, including the ability to access the debt and equity markets;

our ability to integrate acquisitions;

the development of new projects, including whether such projects will continue in the future; and

other factors identified in Item 1A. - "Risk Factors" of this annual report. 
 
Such risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements.
 
All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we do not undertake any obligation to publicly update or revise any forward-looking statements except as required by law.

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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 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. 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. 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 and related 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 28 lodges and villages with a total of approximately 30,000 rooms. We operate approximately 9,000 rooms owned by our customers. Additionally, in both Canada and the U.S., 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.
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Demand for our hospitality services is influenced by four primary factors: (1) commodity prices, (2) available infrastructure, (3) headcount requirements and (4) 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 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 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. 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. 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, 20-25%, 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.

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. 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. 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. 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.

Our U.S. 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. Given the
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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. customers normally react more quickly to changes in oil and natural gas prices. These spending dynamics were clearly demonstrated in 2020. With the decline in oil prices in April 2020 due to the COVID-19 pandemic and its impact on global oil demand, U.S. drilling and completion activity reached historic lows. By August 2020, the U.S. drilling rig count fell to an all-time low of 172. U.S. oil shale drilling and completion activity will continue to be dependent on sustained higher West Texas Intermediate oil prices, pipeline capacity and sufficient capital to support exploration and production (E&P) drilling and completion plans. The Permian Basin remains the most active U.S. unconventional play, representing 66% of the oil rigs active in the U.S. at the end of 2020. As the U.S. 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.
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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. 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 66% of our revenue for the year ended December 31, 2020. 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,
 202020192018
 (In thousands, except for room counts and average daily rate)
Accommodation Revenue (1)
   
Canada$202,534 $281,577 $266,899 
Australia144,070 126,047 117,896 
United States2,451 12,462 18,288 
Total Accommodation Revenue$349,055 $420,086 $403,083 
Mobile Facility Rental Revenue (2)
   
Canada$33,192 $9,575 $9,316 
United States16,837 28,119 20,389 
Total Mobile Facility Rental Revenue$50,029 $37,694 $29,705 
Food Service and Other Services Revenue (3)
   
Canada$33,923 $33,485 $15,601 
Australia90,472 30,046 1,342 
United States50 145 170 
Total Food Service and Other Services Revenue$124,445 $63,676 $17,113 
Manufacturing Revenue (4)
   
Canada$— $1,014 $4,196 
United States6,200 5,085 12,595 
Total Manufacturing Revenue$6,200 $6,099 $16,791 
Total Revenue$529,729 $527,555 $466,692 
Average Daily Rates for Lodges and Villages (5)
   
Canada$95 $91 $89 
Australia$73 $73 $78 
Total Billed Rooms for Lodges and Villages (6)
   
Canada2,095,784 3,078,727 3,007,229 
Australia1,968,284 1,717,186 1,512,030 
Average Exchange Rate   
Canadian dollar to U.S. dollar$0.75 $0.75 $0.77 
Australian dollar to U.S. dollar0.69 0.70 0.75 

(1)Includes revenues related to lodge and village rooms and hospitality services for 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.
(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.
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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 a 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 guests’ accommodations 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 its 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 integrated services) 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 for the natural resource industries. 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. 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, owned and in some cases operated the accommodations necessary to house their personnel in these remote regions because local labor and third-party owned
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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.

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, Fluor and ColtAmec 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, 2020, we generated approximately 51% 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 pipeline takeaway capacity; and, in 2020, 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. 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 38 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.
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Canadian Oil Sands Lodges
 
During the year ended December 31, 2020, activity in the Athabasca oil sands region generated approximately 61% 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, 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 2022 to 2028. In recent years, we have successfully renewed or extended all expiring land leases. 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 resides. The development permits are granted for a term ranging from one to ten years. Our development permits have expiration dates that range from 2021 to 2025. In recent years, we have successfully renewed or extended all expiring development permits. See “Item 1A. Risk Factors-Risks Related to Our Business-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, 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. 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. Our current expectation is that our contracted commitments associated with the CGL pipeline project will be completed in early 2022.

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Canadian Lodge Locations


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Rooms in our Canadian Lodges
   As of December 31,
 
Lodges
RegionExtraction
Technique
202020192018
Wapasu CreekN. Athabascamining5,246 5,246 5,246 
Athabasca (2)
N. Athabascamining2,005 2,005 2,005 
McClelland LakeN. Athabascamining1,997 1,997 1,997 
Henday (1)
N. Athabascamining/in-situ— — 1,698 
Beaver River (2)
N. Athabascamining1,094 1,094 1,094 
Fort McMurray Village:
Buffalo (1)
N. Athabascamining— — 573 
Black Bear (2)
N. Athabascamining531 531 531 
Bighorn (2)
N. Athabascamining763 763 763 
LynxN. Athabascamining855 855 855 
WolverineN. Athabascamining855 855 855 
BorealisN. Athabascamining1,504 1,504 1,504 
Grey WolfN. Athabascamining946 947 946 
Firebag (1)
N. Athabascain situ— — 664 
HudsonN. Athabascamining624 624 624 
Wabasca (2)
S. Athabascamining288 288 246 
Red Earth (2)
S. Athabascamining216 216 216 
Conklin (2)
S. Athabascamining/in-situ616 1,012 1,032 
AnzacS. Athabascain-situ526 526 526 
Mariana Lake (1)
S. Athabascamining— — 686 
Subtotal – Oil Sands  18,066 18,463 22,061 
Sitka LodgeKitimat, BCLNG958 1,186 646 
Total Rooms  19,024 19,649 22,707 

(1)Permanently closed as of December 31, 2020.
(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. generally accepted accounting principles (U.S. GAAP). See Note 4 - Impairment Charges to the notes to the consolidated financial statements in Item 8 of this annual report for further discussion.

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 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.

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. 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.

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Australia
 
Overview
 
During the year ended December 31, 2020, we generated 44% 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. 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 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.  

During the year ended December 31, 2020, our five villages in the Bowen Basin of central Queensland generated 55% 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 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.

Beyond the Pilbara and Bowen Basins, we serve several other markets with four additional villages and five customer-owned villages. At the end of 2020, 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 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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Australian Village Locations

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Owned Rooms in our Australian Villages
   As of December 31,
 
Villages
Resource
Basin
Commodity202020192018
CoppabellaBowenmet coal3,048 3,048 3,048 
DysartBowenmet coal1,798 1,798 1,798 
MoranbahBowenmet coal1,240 1,240 1,240 
MiddlemountBowenmet coal816 816 816 
BoggabriGunnedahmet/thermal coal622 622 622 
NarrabriGunnedahmet/thermal coal502 502 502 
NeboBowenmet coal490 490 490 
Calliope (1)
-LNG— — 300 
Kambalda-Gold, lithium232 232 232 
KarrathaPilbaraLNG, iron ore298 298 298 
Total Rooms  9,046 9,046 9,346 

(1) Sold in September 2019.
 
Our Australian segment includes nine company-owned villages with 9,046 rooms as of December 31, 2020, 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.

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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 Northwest Shelf. Our Kambalda village supports gold and lithium mining in southern Western Australia.

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 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 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. Mine site cleaning services are also provided at some of our customer-owned locations.

U.S.
 
Overview
 
During the year ended December 31, 2020, our U.S. business generated 5% of our revenue. Our U.S. business has operational exposure in the U.S. shale formations in the Permian Basin, the Mid-Continent, the Bakken and the Rockies. The business provides accommodations facilities with hospitality services and highly mobile smaller assets that follow drilling rigs and completion crews as well as accommodations, office and storage modules that are placed on offshore drilling rigs and production platforms. Our U.S. business also provides lodging and hospitality services to the downstream industry through a 300-room facility near Lake Charles, Louisiana.
 
U.S. Market
 
Onshore oil and natural gas development in the U.S. has historically been supported by local workforces traveling short to moderate distances to the worksites. With the development of substantial resources in regions such as the Bakken and Permian Basin, labor demand exceeded the local labor supply and accommodations infrastructure to support the demand. Consequently, demand for remote, scalable accommodations and hospitality services developed in the U.S. Demand for workforce accommodations in the U.S. has historically been tied to the level of oil and natural gas exploration and production activity, which is primarily driven by oil and natural gas prices. Activity levels have been, and we expect will continue to be, highly correlated with hydrocarbon commodity prices.

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U.S. Locations
cveo-20201231_g3.gif

U.S. Mobile Assets
 
Our business in the U.S. consists primarily of mobile assets, both in the lower 48 states, including the (1) Permian Basin region, (2) Mid-Continent region, (3) Bakken region and (4) the Rockies region. 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.

Our mobile assets are rented on a per unit basis based on the number of days that a customer utilizes the asset. In cases where we provide food service or other hospitality services, the contract can provide for per unit pricing or cost-plus pricing. Customers are also typically responsible for mobilization and demobilization costs.

U.S. Lodges
  As of December 31,
 State202020192018
West PermianTX390 410 390 
Acadian AcresLA300 300 400 
KilldeerND235 235 235 
Total Rooms925 945 1,025 

We had three lodges in the U.S. comprised of 925 rooms as of December 31, 2020. 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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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 2020, the annual value of these contracts was approximately C$40 million.

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. 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. 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. 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.

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.

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 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 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 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.

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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, 2020, revenues from our lodges and villages represented over 66% of our consolidated revenues. Our customers typically contract for hospitality services under take-or-pay or exclusivity contracts with terms that most often range from several months to three years. 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. 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. 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. As of December 31, 2020, excluding exclusivity contracts and contracts without minimum room commitments, we had commitments for 22% of our rentable rooms for 2021 and 14% of our rentable rooms for 2022.

As of December 31, 2020, we had 8,948 rooms under contract. The table below details the expiration of those contracts: 
 Contracted Room Expiration
20211,983 
20222,492 
20231,000 
2024— 
2025— 
Thereafter3,473 
Total8,948 
 
The contracts expire throughout the year, and for many of the near-term expirations, we are in the process of negotiating extensions or new commitments. We cannot assure that we can renew existing contracts or obtain new business on the same or better terms, if at all.
 
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 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 and Rocky Mountain operations. Our U.S. offshore operations have historically been impacted by the Gulf of Mexico hurricane season from July through November.  
 
Human Capital Resources

We believe that our employees are one of our greatest resources. As of December 31, 2020, we had approximately 1,000 full-time employees and approximately 1,000 hourly employees on a consolidated basis, 54% of whom are located in Canada, 42% of whom are located in Australia and 4% of whom are located in the U.S.  We were party to collective bargaining agreements covering 885 employees located in Canada and 588 employees located in Australia as of December 31, 2020.

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.
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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 2020, we reached 9% Indigenous employment, excluding corporate staff, in Canada despite challenging market conditions that resulted in reduced hiring in the region. Approximately 11% of our total new hires in Canada were of Indigenous background during 2020. 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. 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 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. 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 roles with a specific focus on safety, customer service and leadership development. We also build competency required for future projects and positions through e-learning modules, face-to-face delivery 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
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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. 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. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations and enforcement policies or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities upon us or our customers that we cannot currently quantify.
 
Canadian Environmental Regulations

In Canada, the federal and provincial governments both have jurisdiction to regulate environmental matters. The provincial governments may also devolve jurisdiction over environmental matters to local governments. Our activities, or those of our customers, may be subject to environmental regulations imposed by these three levels of government. The following addresses updates to Canadian environmental regulations in 2020 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 and are expected to take effect in 2021. 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 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 with additional restrictions on vent gas emissions taking effect in 2022. 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. Meeting these regulatory requirements may result in additional costs or liabilities for our customers’ operations.

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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.

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. 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. 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 United States 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, with others deferred until January 1, 2023. 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
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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 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. The CFS, which is expected to come into force in 2022, will require 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, 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. 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. Consistent with its campaign promises, the new government repealed the CLA, thereby eliminating the provincially-imposed levy on GHG emissions. As a result of those actions by the new Alberta government, features of the federal backstop took effect in Alberta in January 2020. 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. In particular, the current government replaced the CCIR with a new Technology Innovation and Emissions Reduction Regulation ("TIER Regulation"), which took effect on January 1, 2020. Under the TIER Regulation, emissions from each facility are compared to either an industry-wide benchmark or a facility-specific benchmark. 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. The compliance options under the TIER Regulation are substantially the same as those which existed under the CCIR. Those facilities regulated under the CCIR were previously exempt from the Alberta-wide levy. Similarly, the federal government announced in December 2019 that those activities regulated under TIER would not be subject to the federal backstop. As noted, the federal backstop carbon price is expected to increase annually between 2021 and 2030. In order to remain "equivalent" to the federal backstop, it is likely that the per tonne cost of carbon emissions in Alberta will need to increase at the same or similar pace. The direct and indirect costs of these regulatory changes may adversely affect our operations and financial results as well as those of our customers with whom we conduct business.

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
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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. 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 government or Alberta government could affect the business of our customers with operations near caribou habitat.

Alberta’s Electricity Market

The previous government’s CLP set a target of 30 per cent of Alberta’s electricity generation coming from renewables by 2030. Toward attaining this goal, on November 3, 2016, Alberta released the details of its Renewable Electricity Program (REP), which included a procurement process for renewable generation. The first procurement process, REP Round 1, took place in 2017 and awarded long-term, indexed-price power contracts to approximately 596 MW of wind generation capacity. The second process, REP 2, took place in 2018 and awarded contracts to 363 MW of wind capacity in 2018, with eligible projects having a minimum of 25% Indigenous equity ownership. The third, REP 3, also in 2018, was structured similarly to REP 1 and awarded contracts to 400 MW of wind capacity. Three out of four REP 1 projects came into commercial operation in 2019, with the fourth project, REP 2 and REP 3-procured capacity expected to come online later, in 2021 or 2022. Funding for the REP was supposed to come from the Climate Change and Emissions Management Fund described above, backstopped by the government’s General Revenue Fund, rather than from direct electricity charges to our customers.

On June 10, 2019 the fourth REP round auction was canceled by the new conservative government. The Alberta Electric System Operator continues to honor the REP contracts from Rounds 1-3. Funding for these contracts will now rely solely upon the General Revenue Fund, after the Climate Change and Emissions Management Fund was folded into the General Revenue Fund in October 2019. The REP’s funding structure currently limits that program’s direct impact on electricity prices. However, the coming-online of REP-subsidized generation could negatively affect the performance of Alberta’s current electricity market. Negative impacts to the performance of Alberta's electricity market, should they materialize, could result in increased costs to our operations and the operations of our customers going forward.

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 assist Australia fulfils 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.
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If 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 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. 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 is currently on appeal in the Ninth Circuit.
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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 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, 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.

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.

In October 2015, the EPA finalized the Clean Power Plan, 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. 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.


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.

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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 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 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. 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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ITEM 1A. Risk Factors
 
We are subject to various risks and hazards due to the nature of the business activities we conduct. The risks summarized and discussed below, any of which could materially and adversely affect our business, financial condition, cash flows and results of operations and the price of our shares, are not the only risks we face. We may experience additional risks and uncertainties not currently known to us or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Summary of Risk Factors:

Set forth below is a summary of the risks more fully described in this Part I, Item 1A. “Risk Factors” of this Annual Report on Form 10-K. This summary should be read in connection with the Risk Factors more fully described below and should not be relied upon as an exhaustive summary of the material risks facing our business.

Risks Related to Our Macroeconomic-Business Environment
Certain of our customers’ spending may be directly, and our business may be indirectly, affected by volatile or low oil, coal or natural gas prices or unsuccessful exploration results.
We have been adversely affected by the coronavirus pandemic.

Risks Related to Our Customers
Our customers and their operations are exposed to a number of unique operating risks and challenges.
We depend on several significant customers.
Our failure to retain our current customers, renew our existing customer contracts and obtain new customer contracts, or the termination of existing contracts, could adversely affect our business.
Adverse events in areas where we operate could negatively impact our business, and our geographic concentration could limit the number of customers seeking our services.
We may be adversely affected if customers reduce their accommodations outsourcing.

Risks Related to Our Operations
We operate in a highly competitive industry, and if we fail to compete effectively, our business will suffer.
Our operations may suffer due to over-capacity of certain types of accommodations assets.
Increased operating costs and limited cost recovery through pricing or contract terms may constrain our ability to make a profit.
Employee and customer labor problems could adversely affect us.
A failure to maintain food safety or comply with government regulations related to food and beverages or serving alcoholic beverages may subject us to liability.
The majority of our major Canadian lodges are located on land subject to leases.
We are susceptible to seasonal earnings volatility due to adverse weather conditions in our regions of operations.
Failure to maintain positive relationships with the indigenous people in the areas where we operate could adversely affect our business.
Development of permanent infrastructure in the areas where we locate our assets could negatively impact our business.
We may be subject to risks associated with the transportation and installation of mobile accommodations.
Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.
Loss of key members of our management could adversely affect our business.

Financial/Accounting Risks
Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
Currency exchange rate fluctuations could adversely affect our U.S. dollar reported results of operations and financial position.
The cyclical nature of our business and a severe prolonged downturn has and could in the future negatively affect the value of our long-lived assets and our goodwill.
Our inability to control the inherent risks of identifying, acquiring and integrating businesses that we may acquire could adversely affect our operations.
We may not have adequate insurance for potential liabilities and insurance may not cover certain liabilities.

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Legal and Regulatory Risks
We do business in Canada and Australia, whose political and regulatory environments and compliance regimes differ from those in the United States.
We are subject to extensive and costly environmental laws and regulations.
We may be exposed to certain regulatory and financial risks related to climate change.
An accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.

Risks Related to Our Common Shares
The market price and trading volume of our common shares may be volatile.
The rights of holders of our common shares are subordinate to the rights of the holders of our preferred shares.
We are governed by the corporate laws in British Columbia, Canada.
Provisions contained in our articles and applicable Canadian and British Columbia laws could discourage a take-over attempt.
The enforcement of civil liabilities against Civeo may be more difficult.

Risks Related to Our Structure
We are subject to various Canadian and other taxes.
We remain subject to changes in tax law (in various jurisdictions) and other factors that could impact our effective tax rate.
The Canada Revenue Agency (CRA) may disagree with our conclusions on tax treatment.
Future potential changes to U.S. tax laws could result in Civeo being treated as a U.S. corporation for U.S. federal income tax purposes.

Risk Factors:

Risks Related to Our Macroeconomic-Business Environment

Certain of our customers’ spending may be directly, and our business may be indirectly, affected by volatile or low oil, coal or natural gas prices or unsuccessful exploration results.

Demand for our services is sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and gas and mining companies. Our business typically supports customer projects that are capital intensive and require several years to generate first production with production lasting for decades. The economic analyses conducted by our customers in oil sands, Australian mining and liquefied natural gas (LNG) investment areas have historically assumed a relatively conservative longer-term price outlook for production from such projects to determine economic viability. The oil and gas and mining industries’ willingness to explore, develop and produce depends largely upon the availability of attractive resource prospects and the prevailing view of future commodity prices, and expenditures by our oil and gas and mining customers generally lag changes in commodity prices by three to six months. However, with the extreme global oil demand destruction in 2020 due to the COVID-19 coronavirus (COVID-19) pandemic, our oil and gas customers in North America have changed their spending and production plans and have reduced or deferred, and may continue to reduce or defer, major expenditures.

Prices for oil, metallurgical (met) coal, LNG, natural gas and other natural resources are subject to large fluctuations in response to changes in supply of and demand for these commodities. For the past several years, commodity prices have remained relatively low, and continue to be volatile. Global oil prices dropped to historically low levels in April 2020 due to severely reduced global oil demand, the resulting high global crude inventory levels, uncertainty around timing and slope of worldwide economic recovery after COVID-19 related economic shut-downs and effectiveness of production cuts by major oil producing countries, such as Saudi Arabia, Russia and the U.S. Other factors beyond our control that affect commodity prices include:

worldwide economic activity including growth in, and demand for oil, coal and other natural resources, particularly from developing countries, such as China and India;
the level of activity and natural resource developments in Australia and the Canadian oil sands;
the level of global oil and gas exploration and production and the impact of government regulation or Organization of Petroleum Exporting Companies (OPEC) policies that impact production levels and oil prices;
the availability of transportation infrastructure and refining capacity for oil, natural gas, LNG and coal;
global weather conditions, natural disasters and global health concerns such as the COVID-19 pandemic or any future disaster or pandemic;
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rapid technological change and the timing and extent of energy resource development, including hydraulic fracturing of horizontally drilled wells in shale discoveries and LNG;
development, commercialization and availability of alternative fuels; and
government, tax and environmental regulation, including climate change legislation and clean energy policies.

In 2018, the Government of Alberta announced it would mandate temporary curtailments of the province’s oil production. 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. The curtailment initially resulted in a narrowing of the discount (WCS Differential) at which Western Canadian Select (WCS) trades relative to West Texas Intermediate (WTI) in December 2018, which increased in 2019 before narrowing again in the first quarter of 2020. As of February 22, 2021, the WTI price was $61.49 and the WCS price was $49.95, resulting in a WCS Differential of $11.54. Should the price of WTI decline or the WCS discount to WTI widen further, our oil sands customers may delay or eliminate additional investments, further reduce their spending in the oil sands region or curtail or shut-down additional existing operations.

We have been adversely affected by the coronavirus pandemic.

The outbreak of COVID-19 has adversely impacted and continues to impact worldwide economic activity, including the natural resources industry in Canada, Australia and the U.S. The actions taken to mitigate the spread of COVID-19 and the risk of infection have altered, and are expected to continue to alter, governmental and private-sector policies and behaviors in ways that have had a significant negative effect on oil consumption, such as government-imposed or voluntary social distancing and quarantining, stay-at-home orders, health and safety considerations, reduced travel and remote work policies. We have experienced, and expect to continue to experience, some resulting disruptions and increased costs to our business as a result of the measures we have set in place to comply with governmental regulations and customer policies related to COVID-19. In addition, with lower and volatile oil prices due to reduced global oil demand and uncertainty around the continued economic impact of COVID-19, capital spending by oil and gas companies and customer demand for our services has been adversely affected. The ultimate extent of the impact of COVID-19 on our business, financial condition and results of operations will depend largely on future developments, including the duration and spread of the outbreak in the countries in which we operate and the related impact on the oil and gas industry, the impact of governmental actions designed to prevent the spread of COVID-19 and the development and availability of effective treatments and vaccines, all of which are highly uncertain and cannot be predicted with certainty at this time.

Risks Related to Our Customers

Our customers and their operations are exposed to a number of unique operating risks and challenges which could also adversely affect us.

We could be materially adversely affected by disruptions to our customers’ operations. The price of and demand for natural resources produced by our customers may impact their desire and/or ability to continue existing projects or start new projects. Customers may also experience unexpected problems, higher costs or delays in commencing or developing a project. Operating risks and challenges our customers face, which may ultimately affect their need for the accommodations and services we provide, include:

commodity price volatility;
unforeseen and adverse geological, geotechnical, seismic and mining conditions;
lack of availability or failure of the required infrastructure, including sourcing sufficient water or power, necessary to maintain or to expand their operations;
the breakdown or shortage of equipment and labor necessary to maintain their operations;
risks associated with the natural resources industry being subject to various regulatory approvals, including a government agency failing to grant an approval or failing to renew an existing approval, or the approval or renewal not being provided by the government agency in a timely manner or the government agency granting or renewing an approval subject to materially onerous conditions;
risks to land titles, mining titles and use thereof as a result of native title claims;
claims by persons living in close proximity to mining projects, which may have an impact on the consents granted; and
interruptions to the operations of our customers caused by governmental action, industrial accidents, disputes or public health emergencies.
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We depend on several significant customers.

We depend on several significant customers, including customers that operate in the oil and gas and mining industries, which has been adversely impacted by the effects of the COVID-19 pandemic. The loss of any one of our largest customers in any of our business segments or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations. In addition, the concentration of customers in the mining and oil and gas industries may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. With the current low and volatile oil and gas prices, some of our customers may face liquidity issues, which could impair their ability to pay or otherwise perform on their obligations. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. For a more detailed explanation of our customers, see “Business” in Item 1 of this annual report.

Our failure to retain our current customers, renew our existing customer contracts and obtain new customer contracts, or the termination of existing contracts, could adversely affect our business.

Our success depends on our ability to retain our current customers, renew or replace our existing customer contracts and obtain new business. Our ability to do so generally depends on a variety of factors, including overall customer expenditure levels and the quality, price and responsiveness of our services, as well as our ability to market these services effectively and differentiate ourselves from our competitors. We cannot assure you that we will be able to obtain new business, renew existing customer contracts at the same or higher levels of pricing, or at all, or that our current customers will not turn to competitors, cease operations, elect to self-operate or terminate contracts with us.

Our business is contract intensive and we are party to many contracts with customers. Due to the current volatile commodity price environment, our customers may not renew contracts on terms favorable to us or, in some cases, at all, and we may have difficulty obtaining new business. Several contracts have clauses that allow termination upon the payment of a termination fee. As a result, our customers may choose to terminate their contracts. The likelihood that a customer may seek to terminate a contract is increased during periods of market volatility like those we are currently experiencing. Finally, while we periodically review our compliance with contract terms and provisions, if customers were to dispute our contract determinations, the resolution of such disputes in a manner adverse to our interests, including customers withholding payments or modification of payment terms, could negatively affect sales and operating results. Customer contract cancellations, the failure to renew a significant number of our existing contracts or the failure to obtain new business would have a material adverse effect on our business and results of operations.

Due to the significant geographic concentration of our business, adverse events in areas where we operate could negatively impact our business, and our geographic concentration could limit the number of customers seeking our services.

Because of the concentration of our business in the oil sands region of Alberta, Canada and in the coal producing, Bowen Basin region of Queensland, Australia, two relatively small geographic areas, we have increased exposure to political, regulatory, environmental, labor, climate or natural disasters such as forest fires or flooding, events or developments that could disproportionately impact our operations and financial results. For example, in 2011 and 2017, cyclones and resulting flooding threatened our villages in Australia. Also in 2011 and 2016, forest fires in northern Alberta impacted areas near our Canadian oil sands lodges. Due to our geographic concentration, any adverse events or developments in our operating areas may disproportionately affect our financial results.

In addition, a limited number of potential customers operate in the areas in which our business is concentrated, and occupancy at each of our lodges may be constrained by the radius which potential customers are willing to transport their workers. Our geographic concentration could limit the number of customers seeking our services, and as to any single lodge or village, we may have few potential customers. Therefore, we are subject to volatility in occupancy in any location based on the capital spending plans of a limited number of customers, based on their changing decisions as to whether to outsource or use their own company-owned accommodations and whether other potential customers move into that lodge’s radius.

We may be adversely affected if customers reduce their accommodations outsourcing.

Our business and growth strategies depend in large part on customers outsourcing some or all of the services that we provide. Many oil and gas and mining companies in our core markets own their own accommodations facilities, while others outsource all or part of their accommodations requirements. Customers have largely built their own accommodations in the past but will outsource if they perceive that outsourcing may provide quality services at a lower overall cost or allow them to
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accelerate the timing of their projects. We cannot be certain that these customer preferences will continue or that customers that have previously outsourced accommodations will not decide to perform these functions themselves or only outsource accommodations during the development or construction phases of their projects. In addition, labor unions representing customer employees and contractors have, in the past, opposed outsourcing accommodations to the extent that the unions believe that third-party accommodations negatively impact union membership and recruiting. The reversal or reduction in customer outsourcing of accommodations could negatively impact our financial results and growth prospects.

Risks Related to Our Operations

We operate in a highly competitive industry, and if we fail to compete effectively, our business will suffer.

The workforce accommodations and hospitality industry in which we operate is highly competitive. To be successful, we must provide hospitality services that meet the specific needs of our customers at competitive prices. The principal competitive factors in the markets in which we operate are service quality and availability, price, technical knowledge and experience and safety performance. We compete with international and regional competitors, several of which are significantly larger than we. These competitors offer similar services in the geographic regions in which we operate. Many oil and gas and mining companies in our core markets own their own accommodations facilities and outsource their service requirements, while others outsource all or part of their accommodations requirements. As a result of competition, we may be unable to continue to provide our present services, to provide such services at historical operating margins or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Reduced levels of activity in the workforce accommodation industry can intensify competition and result in lower revenue to us.

Our operations may suffer due to over-capacity of certain types of accommodations assets.

The demand for and/or pricing of rooms and accommodation services is subject to the overall availability of rooms in the marketplace. If demand for our assets were to decrease, or to the extent that we and our competitors increase our capacity in excess of current demand, we may encounter decreased pricing for, or utilization of, our assets and services, which could adversely impact our operations and profits. The economic disruption in 2020 caused by the decline in the price of and demand for oil has impacted the activity in the Canadian oil sands and our U.S. business, and we have seen decreased customer demand for accommodations in those areas, and we have experienced a corresponding significant decrease in our occupancy and profitability.

Increased operating costs and limited cost recovery through pricing or contract terms may constrain our ability to make a profit.

Our profitability can be adversely affected to the extent we are faced with cost increases for food, wages and other labor related expenses, insurance, fuel and utilities, especially to the extent we are unable to recover such increased costs through increases in the prices for our services, due to one or more of general economic conditions, competitive conditions or contractual provisions in our customer contracts. Substantial increases in the cost of fuel and utilities have historically resulted in cost increases in our lodges and villages. From time to time we have experienced increases in our food costs. While we believe a portion of these increases were attributable to fuel prices, we believe the increases also resulted from rising global food demand. In addition, food prices can fluctuate as a result of foreign exchange rates and temporary changes in supply, including as a result of incidences of wildfires or severe weather such as droughts, heavy rains and late freezes, or other climate effects. While our multi-year contracts often provide for annual escalation in our room rates for food, labor and utility inflation, we may be unable to fully recover costs and such increases would negatively impact our profitability on contracts that do not contain such inflation protections.

Employee and customer labor problems could adversely affect us.

Our business is labor intensive requiring a significant number of employees to perform housekeeping, janitorial and food services at our locations or locations that we manage. As our operations grow or our occupancy increases, we require additional staff to take care of our guests at a standard we deem appropriate and to operate safely. If we are unable to hire a sufficient labor force, we may be required to increase wages or use temporary labor at a higher cost and reduced efficiency. Inefficient operations or higher labor costs would negatively impact our profitability and could damage our reputation with our customers.

Additionally, as of December 31, 2020, we were party to collective bargaining agreements covering 885 employees in Canada and 588 employees in Australia. Efforts have been made from time to time to unionize other portions of our workforce. In addition, our facilities serving oil sands development work in Northern Alberta, Canada and mining operations in Australia
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house both union and non-union customer employees. We have not experienced strikes, work stoppages or other slowdowns in the past, but we cannot guarantee that we will not experience such events in the future. A prolonged strike, work stoppage or other slowdown by our employees or by the employees of our customers could cause us to experience a disruption of our operations, which could adversely affect our business and results of operations. Additional unionization efforts and new collective bargaining agreements also could materially increase our costs or limit our flexibility. Collective bargaining agreements in our Canadian operations have individual expiration dates, but in no case extend beyond 2023. Enterprise bargaining agreements in our Australian operations cover certain employees working at our villages in Queensland, New South Wales and Western Australia, as well as certain employees working at our integrated services customer owned sites in Western Australia. These agreements have individual expiration dates, but in no case extend beyond 2022.

A failure to maintain food safety or comply with government regulations related to food and beverages or serving alcoholic beverages may subject us to liability.

Claims of illness or injury relating to food quality or food handling are common in the food service industry, and a number of these claims may exist at any given time. Because food safety issues could be experienced at the source or by food suppliers or distributors, food safety could, in part, be out of our control. Regardless of the source or cause, any report of food-borne illness or other food safety issues such as food tampering or contamination at one of our locations could adversely impact our reputation, hindering our ability to renew contracts on favorable terms or to obtain new business, and have a negative impact on our sales. Future food product recalls and health concerns associated with food contamination may also increase our raw materials costs and, from time to time, disrupt our business.

A variety of regulations at various governmental levels relating to the handling, preparation and serving of food (including, in some cases, requirements relating to the temperature of food), cleanliness of food production facilities and hygiene of food-handling personnel are enforced primarily at the local public health department level. We can give no assurances that we are in full compliance with all applicable laws and regulations at all times or that we will be able to comply with any future laws and regulations. Furthermore, legislation and regulatory attention to food safety is very high. Additional or amended regulations in this area may significantly increase the cost of compliance or expose us to liabilities.

We serve alcoholic beverages at some of our facilities, and must comply with applicable licensing laws, as well as local service laws. These laws generally prohibit serving alcoholic beverages to certain persons such as a patron who is intoxicated or a minor. If we violate these laws, we may be liable to the patron and/or third parties for the acts of the patron. We cannot guarantee that certain patrons will not be served or that liability for their acts will not be imposed on us. There can be no assurance that additional regulation in this area would not limit our activities in the future or significantly increase the cost of regulatory compliance. We must also obtain and comply with the terms of licenses in order to sell alcoholic beverages in the jurisdictions in which we serve alcoholic beverages. If we are unable to maintain food safety or comply with government regulations related to food, beverages or alcoholic beverages, the effect could be materially adverse to our business and results of 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.

The majority of our major Canadian lodges are located on land subject to provincial leases. Accordingly, while we own the accommodations assets, we only own a leasehold in those properties. If we are found to be in breach of a lease, we could lose the right to use the property. In addition, our leases generally have an initial term of ten years and will expire between 2022 and 2028 unless extended. Unless we can extend the terms of these leases before their expiration, as to which no assurance can be given, we will lose our right to operate our facilities located on these properties upon expiration of the leases. In that event, we would be required to remove our accommodations assets and remediate the site. As of December 31, 2020, we had an asset retirement obligation (ARO) liability on our balance sheet of $15.0 million. Consistent with US GAAP, this liability is the estimated present value of the amount of required asset removal and site remediation costs related to the retirement of assets at these locations. Should the remediation requirement be accelerated, our near term cash obligation could be significantly larger than the liability currently on our balance sheet and could negatively impact our cash flows and liquidity.

Also, in certain areas in which we operate, we are required to seek permits from local government agencies in order to build a new lodge or operate an existing lodge on leased land. A proposed regulation in a Regional Municipality of Wood Buffalo, Alberta, where we have eight facilities, would require us to seek renewal of such permits every four years; however, this proposal was abandoned in late 2019, and no update has been provided. We can provide no assurances that we will be able to renew our leases or permits upon expiration on similar terms, or at all. If we are unable to renew our leases or permits on similar terms, it may have an adverse effect on our business and results of operations.
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We are susceptible to seasonal earnings volatility due to adverse weather conditions in our regions of operations.

Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada and Australia, and, to a lesser extent, the Permian Basin. A portion of our Canadian operations is conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. The spring thaw in these frontier regions restricts operations in the spring months and, as a result, adversely affects our operations and our ability to provide services in the second and, to a lesser extent, third quarters. During the Australian rainy season, generally between the months of November and April, our operations in Queensland and the northern parts of Western Australia can be affected by cyclones, monsoons and resultant flooding. Severe winter weather conditions in the Permian Basin of the United States can restrict access to work areas for our customers. Furthermore, the areas in which we operate are susceptible to wildfires, which could interrupt our operations and adversely impact our earnings.

Failure to maintain positive relationships with the indigenous people in the areas where we operate could adversely affect our business.

A component of our business strategy is based on developing and maintaining positive relationships with the indigenous people and communities in the areas where we operate. These relationships are important to our operations and customers who desire to work on traditional indigenous lands. The inability to develop and maintain relationships and to be in compliance with local requirements could have an adverse effect on our business and results of operations.

Development of permanent infrastructure in the areas where we locate our assets could negatively impact our business.

We specialize in providing hospitality services for workforces in remote areas which often lack the infrastructure typically available in nearby towns and cities. If permanent towns, cities and municipal infrastructure develop, grow or otherwise become available in the oil sands region of northern Alberta, Canada, the west coast of British Columbia or regions of Australia where we locate villages, then demand for our hospitality services could decrease as customer employees move to the region and choose to utilize permanent housing and food services.

We may be subject to risks associated with the transportation and installation of mobile accommodations.

In connection with our Canadian and U.S. businesses, we currently have several contracts to transport and install modular, skid-mounted accommodations and central facilities that can be quickly configured to serve a multitude of short to medium-term accommodation needs. In connection with the transportation and installation of these facilities, we may be exposed to various risks, including

delays in necessary approvals to install the facilities or objections to our activities or those of our customers aired by aboriginal or community interests, environment and/or neighborhood groups which may cause delays in the granting of such approvals and/or the overall progress of a project;
challenges during installation, including problems, defects, inclement weather conditions, land contamination, cultural heritage claims, difficult site access or industrial relations issues; and
risks related to the quality of our materials and workmanship, including warranties and defect liability obligations.

Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.

We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable or hold them for ransom; threats to the safety of our employees; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure; and threats from terrorist acts. Although we utilize various procedures and controls to monitor these threats and mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.

Cybersecurity attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, ransomware attacks and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of or denial of access to confidential or otherwise protected information and corruption of data. In 2018, we experienced a minor data security breach resulting from unauthorized access to our systems, which had no material impact on our operations; however, there is no assurance that such impacts will not be material in the future.
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Loss of key members of our management could adversely affect our business.

We depend on the continued employment and performance of key members of our management. If any of our key managers resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain “key man” life insurance for any of our officers.

Financial/Accounting Risks

Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.

We currently have a substantial amount of indebtedness. As of December 31, 2020, we had approximately $187.5 million outstanding under the term loan portion of our credit agreement (as amended from time to time, the Amended Credit Agreement), $63.6 million outstanding under the revolving portion of the Amended Credit Agreement, $4.5 million of outstanding letters of credit and capacity to borrow an additional $99.3 million under the revolving portion of the Amended Credit Agreement. If market or other economic conditions remain depressed or further deteriorate, our borrowing capacity may be further reduced.

Our Amended Credit Agreement contains, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us and may limit our ability to, among other things, borrow funds, dispose of assets, pay dividends and make certain investments. In addition, these covenants also may limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Our ability to comply with these covenants may be affected by events beyond our control. Declines in commodity prices, or a prolonged period of commodity prices at depressed levels, could eventually result in our failing to meet one or more of the financial covenants under the Amended Credit Agreement, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A failure to comply with these covenants, ratios or tests could also result in an event of default. A default under the Amended Credit Agreement, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder. The accelerated debt would become immediately due and payable. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. In addition, in the event of an event of default under the Amended Credit Agreement, the lenders could foreclose on the collateral securing the credit facility and require repayment of all borrowings outstanding. If the amounts outstanding under the credit facility or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders. Moreover, any new indebtedness we incur may impose financial restrictions and other covenants on us that may be more restrictive than our existing debt agreements.

Our ability to service our debt, including repaying outstanding borrowings under our Amended Credit Agreement at maturity, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our business does not generate sufficient cash flows from operations to enable us to meet our obligations under our indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital. We may not be able to effect any of these remedies on satisfactory terms or at all, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Currency exchange rate fluctuations could adversely affect our U.S. dollar reported results of operations and financial position.

Our reporting currency is the U.S. dollar, and we are exposed to currency exchange risk primarily between the U.S. dollar and the Canadian and Australian dollars. For the year ended December 31, 2020, 95% of our revenues originated from subsidiaries outside of the U.S. and were denominated in either the Canadian dollar or the Australian dollar. As a result, a material decrease in the value of these currencies relative to the U.S. dollar has had, and may have in the future, a negative impact on our reported revenues, net income, financial condition and cash flows. Any currency controls implemented by local monetary authorities in countries where we currently operate could also adversely affect our business, financial condition and results of operations. We may attempt to limit the risks of currency fluctuation where possible by entering into financial instruments to protect against foreign currency exposure, but, to date, we have not entered into any foreign currency financial
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instruments. Our efforts to limit exchange risks may be unsuccessful, thereby exposing us to foreign currency fluctuations that could cause our results of operations, financial condition and cash flows to deteriorate.

The cyclical nature of our business and a severe prolonged downturn has, and could in the future, negatively affect the value of our long-lived assets and our goodwill.

We recorded impairments of our long-lived assets of $50.5 million, $6.2 million and $28.7 million in 2020, 2019 and 2018, respectively. We also recorded goodwill impairments of $93.6 million and $19.9 million in 2020 and 2019, respectively. As of December 31, 2020, goodwill at our Australian reporting unit represented 1% of total assets, or $8.7 million.

Factors that may cause us to recognize further impairment losses on our long-lived assets or on the goodwill at our Australian reporting unit include, among other things, extended periods of limited or no activity by our customers at our lodges or villages, increased or unanticipated competition, and downward forecast revisions or restructuring plans or if certain of our customers do not reach positive final investment decisions on projects with respect to which we have been awarded contracts to provide related accommodation, which may cause those customers to terminate the contracts.

Our inability to control the inherent risks of identifying, acquiring and integrating businesses that we may acquire, including any related increases in debt or issuances of equity securities, could adversely affect our operations.

Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our growth strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements could impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to shareholders. In addition, overpayment of an acquisition could cause potential impairments which could affect our results of operations.

We expect to gain certain business, financial and strategic advantages as a result of business combinations we undertake, including synergies and operating efficiencies. Our forward-looking statements assume that we will successfully integrate our business acquisitions and realize these intended benefits. The success of any acquisitions we make depends, in large part, on our ability to realize the anticipated benefits, including operating synergies from combining our businesses, which were previously operated independently, and retaining and integrating key employees, vendors and customers from the acquired businesses. An inability to realize expected strategic advantages as a result of the acquisition would negatively affect the anticipated benefits of the acquisition.

Additionally, an acquisition may bring us into businesses we have not previously conducted and expose us to additional business risks that are different from those we have previously experienced. Our future success depends, in part, upon our ability to manage this expanded business, which will pose substantial challenges for our management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. If we fail to manage any of these risks successfully, our business could be harmed. Our capitalization and results of operations may change significantly following an acquisition, and our shareholders may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

We may not have adequate insurance for potential liabilities and insurance may not cover certain liabilities.

Our operations are subject to many hazards. In the ordinary course of business, we become the subject of various claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to the activities of businesses that we have acquired, even though these activities may have occurred prior to our acquisition of such businesses. We maintain insurance to cover many of our potential losses, including cyber risk insurance, and we are subject to various self-retentions and deductibles under our insurance policies. It is possible, however, that a judgment could be rendered against us in cases in which we could be uninsured and beyond the amounts that we currently have reserved or anticipate incurring for such matters. Even a partially uninsured or underinsured claim, if successful and of significant size, could have a material adverse effect on our results of operations or consolidated financial position. In addition, we are insured under the insurance policies of Oil States International, Inc. (Oil States) for occurrences prior to the completion of our spin-off from Oil States in May 2014 (the Spin-Off). The specifications and insured limits under those policies, however, may be insufficient for such claims. We also face other risks related to our insurance coverage, including (1) we may not be able to continue to obtain insurance on commercially reasonable terms; (2) the counterparties to our insurance contracts may pose credit risks; and (3) we may incur losses from interruption of our business that exceed our insurance coverage
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Legal and Regulatory Risks

We do business in Canada and Australia, whose political and regulatory environments and compliance regimes differ from those in the United States.

A significant portion of our revenue is attributable to operations in Canada and Australia. These activities accounted for 95% of our consolidated revenue in the year ended December 31, 2020. Risks associated with our operations in Canada and Australia include, but are not limited to, (1) different taxing regimes; (2) changing political conditions at the federal, provincial or state level; (3) changing international and U.S. monetary policies; and (4) regional economic downturns.

The regulatory regimes in these countries are substantially different than those in the United States, and may be unfamiliar to U.S. investors. Violations of non-U.S. laws could result in monetary and criminal penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.

We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.

All of our operations are significantly affected by stringent and complex foreign, federal, provincial, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. We could be exposed to liabilities for cleanup costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third-parties. Environmental laws and regulations are subject to change in the future, possibly resulting in more stringent requirements. The implementation of new laws and regulations could result in materially increased costs, stricter standards and enforcement, larger fines and liability and increased capital expenditures and operating costs, particularly for our customers, and could have an adverse effect on our business or demand for our services. See Item 1. “Business - Government Regulation” of this annual report for a more detailed description of our risks associated with environmental laws and regulations. It should also be noted that scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.

Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our business and results of operations, including the issuance of administrative, civil and criminal penalties; denial or revocation of permits or other authorizations; reduction or cessation of operations; and performance of site investigatory, remedial or other corrective actions.

We may be exposed to certain regulatory and financial risks related to climate change.

Climate change is receiving increasing attention from the media, scientists and legislators alike which has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas emissions, such as carbon dioxide and methane. Significant focus is being made on companies that are active producers of fossil fuels, or companies which serve such producers.

Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels, including plans developed in connection with the Paris climate conference in December 2015 and the Katowice climate conference in December 2018. There are a number of legislative and regulatory proposals to address greenhouse gas emissions, including increased fuel efficiency standards, carbon taxes or cap and trade systems, restrictive permitting, and incentives for renewable energy, which are in various phases of discussion or implementation. Moreover, such legislation, regulations and proposals are subject to frequent change by regulatory authorities, including in connection with the change in the U.S. federal administration in January 2021. The outcome of Canadian, Australian and U.S. federal, regional, provincial and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could both (1) directly impact us due to increased costs associated with our operations, and (2) indirectly impact us due to increased costs of and/or reduced demand for our customers' operations, and resulting reduced demand for our services.

Any adoption of these or similar proposals by Canadian, Australian, U.S. federal, regional, provincial or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry, including negatively impacting the price of oil relative to other energy sources, reducing demand for hydrocarbons and other minerals or limiting drilling or mining in the areas in which we operate. Although it is not possible at
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this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for our services. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. See Item 1. “Business - Government Regulation” of this annual report for a more detailed description of our climate-change related risks.

An accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.

There is inherent risk of environmental costs and liabilities in our business as a result of (1) our handling of petroleum hydrocarbons, (2) air emissions and waste water discharges related to our operations, and (3) historical industry operations and waste disposal practices. Certain environmental statutes impose joint and several strict liability for these costs. For example, an accidental release by us in the performance of services at one of our or our customers’ sites could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover some or any of these costs from insurance.

Risks Related to Our Common Shares

The market price and trading volume of our common shares may be volatile.

On November 19, 2020, we effected the Reverse Share Split, where each twelve issued and outstanding common shares were converted into one common share. Our common shares began trading on a reverse share split-adjusted basis on November 19, 2020. All common share and per common share data included in this annual report have been retroactively adjusted to reflect the Reverse Share Split.

The market price of our common shares has historically experienced and may continue to experience volatility. For example, during 2019, the market price of our common shares, adjusted to reflect the Reverse Share Split, ranged from a low of $9.01 per share to a high of $34.20 per share. During 2020, the market price of our common shares, adjusted to reflect the Reverse Share Split, ranged from a low of $4.08 per share to a high of $18.48 per share. The market price of our common shares may be influenced by many factors, some of which are beyond our control, including those described above and the following:

changes in financial estimates by analysts and our inability to meet those financial estimates;
strategic actions by us or our competitors;
announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;
variations in our quarterly operating results and those of our competitors;
general economic and stock market conditions;
risks related to our business and our industry, including those discussed above;
changes in conditions or trends in our industry, markets or customers;
terrorist acts;
future sales of our common shares or other securities by us, members of our management team or our existing shareholders; and
investor perceptions of the investment opportunity associated with our industry or common shares relative to other investment alternatives.

These broad market and industry factors may materially reduce the market price of our common shares, regardless of our operating performance. In addition, price volatility may be greater if the public float and trading volume of our common shares is low.

In addition, in recent years the stock market has experienced substantial price and volume fluctuations. This volatility has had a significant effect on the market prices of securities issued by many companies for reasons potentially unrelated to their operating performance. For example, our share price may experience substantial volatility due to uncertainty regarding commodity prices. These market fluctuations, regardless of the cause, may materially and adversely affect our share price, regardless of our operating results. Furthermore, the trading market for our common shares is influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of
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our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our share price or trading volume to decline.

The rights of holders of our common shares are subordinate to the rights of the holders of our preferred shares.

The holders of the preferred shares issued in the Noralta Acquisition have rights and preferences superior to those of the holders of our common shares, including the right to receive a 2% annual dividend, paid quarterly in cash or, at our option, by increasing the preferred shares’ liquidation preference, or any combination thereof and the right to receive a liquidation preference prior to any distribution of our assets to the holders of our common shares. In addition, holders of the preferred shares may convert their shares into common shares at an initial conversion price of $39.60 per common share, which may not be the fair market value of such shares at the time of conversion.

We are governed by the corporate laws in British Columbia, Canada which in some cases have a different effect on shareholders than the corporate laws in Delaware, United States.

There are material differences between the Business Corporations Act (British Columbia) (BCBCA) as compared to the Delaware General Corporation Law (DGCL). For example, some of these material differences include the following: (a) for material corporate transactions (such as amalgamations, arrangements, the sale of all or substantially all of our undertaking, and other extraordinary corporate transactions), the BCBCA, subject to the provisions of our Articles, generally requires two-thirds majority vote by shareholders, whereas DGCL generally only requires a majority vote of shareholders for similar material corporate transactions; and (b) under the BCBCA, a holder of 5% or more of our common shares can requisition a general meeting of shareholders for the purpose of transacting any business that may be transacted at a general meeting, whereas the DGCL does not give this right. We cannot predict if investors will find our common shares less attractive because of these material differences. If some investors find our common shares less attractive as a result, there may be a less active trading market for our common shares and our share price may be more volatile.

Provisions contained in our articles and applicable Canadian and British Columbia laws could discourage a take-over attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, the ability of our shareholders to sell their shares for a premium.

Provisions contained in our articles provide for a classified board of directors, limitations on the removal of directors, limitations on shareholder proposals at meetings of shareholders and limitations on shareholder action by written consent, which could make it more difficult for a third-party to acquire control of us. Our articles, subject to the corporate law of British Columbia, also authorize our board of directors to issue series of preferred shares without shareholder approval. If our board of directors elects to issue preferred shares, it could increase the difficulty for a third-party to acquire us, which may reduce or eliminate our shareholders’ ability to sell their common shares at a premium. In addition, in Canada, we may become subject to applicable securities laws, including National Instrument 62-104 Take-Over Bids and Issuer Bids of the Canadian Securities Administrators, which provide a heightened threshold for shareholder acceptance of third-party acquisition offers and could discourage take-over attempts that could result in a premium over the market price for our common shares.

As a British Columbia company, we may be subject to additional Canadian laws and regulations. The application of additional Canadian laws and regulations could make it more difficult for third parties to acquire control of us. For example, such laws and regulations may, depending on the circumstances, result in regulatory reviews of and may require regulatory approval for any proposed take-over attempts.

Any of the foregoing could prevent or delay a change of control and may deprive or limit strategic opportunities for our shareholders to sell their common shares and/or affect the market price of our common shares.

The enforcement of civil liabilities against Civeo may be more difficult.

Civeo is a British Columbia company and a substantial portion of our assets are located outside the U.S. As a result, investors could experience more difficulty enforcing judgments obtained against us in U.S. courts than would be the case for U.S. judgments obtained against a U.S. company. In addition, some claims may be more difficult to bring against Civeo in Canadian courts than it would be to bring similar claims against a U.S. company in a U.S. court.

Risks Related to Our Structure

We are subject to various Canadian and other taxes.

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Our effective tax rates (including our Canadian tax rate) are dependent on a variety of factors, many of which are beyond our ability to control, such as changes in the rate of economic growth in Canada, currency exchange rate fluctuations (especially between Canadian and U.S. dollars), and significant changes in trade, monetary or fiscal policies of Canada, including changes in interest rates, withholding taxes, tax treaties and federal and provincial tax rates generally. The impact of these factors, individually and in the aggregate, is difficult to predict, in part because the occurrence of any number of the events or circumstances described in such factors may be (and, in fact, often seem to be) interrelated, and the impact to us of the occurrence of any one of these events or circumstances could be compounded or, alternatively, reduced, offset, or more than offset, by the occurrence of one or more of the other events or circumstances described in such factors.

Canada’s tax rules under the Income Tax Act (Canada) (the Canadian Tax Act) allow for favorable tax treatment insofar as the repatriation of certain dividends from foreign affiliates. These tax rules are complicated and could change over time. Any such changes could have a material impact on our overall tax rate.

Canada has also introduced tax rules governing “foreign affiliate dumping” in the Canadian Tax Act that can have adverse tax consequences in respect of non-Canadian business activities and investments for Canadian corporations that are controlled by non-Canadian corporations. These rules would have a negative impact on us to the extent that we became controlled by a non-Canadian resident corporation.

We remain subject to changes in tax law (in various jurisdictions) and other factors that could impact our effective tax rate.

The tax laws of Canada, Australia and the U.S. could change in the future, and such changes could cause a material change in our effective corporate tax rate. As a result, our realized effective tax rate may be materially different from our current expectation. Our provision for income taxes will be based on certain estimates and assumptions made by management in consultation with our tax and other advisors. Our consolidated income tax rate will be affected by the amount of net income earned in Canada and our other operating jurisdictions, the availability of benefits under tax treaties, and the rates of taxes payable in respect of that income. We will enter into many transactions and arrangements in the ordinary course of business in respect of which the tax treatment is not entirely certain. We will therefore make estimates and judgments based on our knowledge and understanding of applicable tax laws and tax treaties, and the application of those tax laws and tax treaties to our business, in determining our consolidated tax provision. The final outcome of any audits by taxation authorities may differ from the estimates and assumptions we may use in determining our consolidated tax provisions and accruals. This could result in a material adverse effect on our consolidated income tax provision, financial condition and the net income for the period in which such determinations are made.

The U.S. Congress, government agencies in non-U.S. jurisdictions where we and our affiliates do business, and the Organization for Economic Co-operation and Development have recently focused on issues related to the taxation of multinational corporations. One example is found in the area of “base erosion and profit shifting”, where profits are claimed to be earned for tax purposes in low-tax jurisdictions, or payments are made between affiliates from a jurisdiction with high tax rates to a jurisdiction with lower tax rates. As a result, the tax laws in the U.S. and other countries in which we and our affiliates do business could change on a prospective or retroactive basis (or both), and any such changes could materially adversely affect us.

The Canada Revenue Agency (CRA) may disagree with our conclusions on tax treatment, and the CRA has not provided (and we have not requested), a ruling on the Canadian tax aspects of our redomestication.

We completed our redomestication from Delaware to British Columbia, Canada in 2015 (the Redomicile Transaction). We do not believe that the Redomicile Transaction resulted in any material Canadian federal income tax liability to us; however, the CRA did not provide (and we did not request) a ruling on the Canadian tax aspects of the Redomicile Transaction, and there can be no assurance that the CRA will agree with our interpretation of the tax aspects of the Redomicile Transaction or any related matters associated therewith. If the CRA were to disagree with our views about the tax implications of the Redomicile Transaction, it could take the position that material Canadian federal income tax liabilities or amounts on account thereof are payable by us as a result of the Redomicile Transaction, in which case, we expect that we would contest such assessment. To contest such assessment, we would be required to remit cash equal to half of the amount in dispute, or provide security acceptable to the CRA, to prevent the CRA from seeking enforcement actions pending the dispute of such assessment. If we were unsuccessful in disputing the assessment, the implications could be materially adverse to us. The CRA has not provided (and we have not requested) a ruling on the Canadian tax aspects of the Redomicile Transaction. There can be no assurance that the CRA will agree with our interpretation of the tax aspects of the Redomicile Transaction or any related matters associated therewith.
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Future potential changes to U.S. tax laws could result in Civeo being treated as a U.S. corporation for U.S. federal income tax purposes.

Although, as noted above, we believe that we are treated as a foreign corporation for U.S. federal income tax purposes, changes to Section 7874 of the Internal Revenue Code or the U.S. Treasury regulations promulgated thereunder or official interpretations thereof, could adversely affect Civeo’s status as a foreign corporation for U.S. federal income tax purposes. For example, members of Congress from time to time have proposed changes to the Internal Revenue Code, and the U.S. Treasury has taken and may continue to take regulatory action, in connection with so-called inversion transactions. The timing and substance of any such change in law or regulatory action is uncertain. Any such change of law or regulatory action could adversely impact the treatment of Civeo as a foreign corporation for U.S. federal income tax purposes and could adversely impact its tax position and financial position and results in a material manner. The precise scope and application of any legislative or regulatory proposals will not be clear until they are actually issued, and, accordingly, until such legislation or regulations are issued and fully understood, we cannot be certain as to their potential impact. Any such changes could apply retroactively to a date prior to the date of the Redomicile Transaction. If Civeo were to be treated as a U.S. corporation for U.S. federal income tax purposes, it could be subject to substantially greater U.S. federal income tax liability.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties
 
The following table presents information about our principal properties and facilities as of December 31, 2020. Except as indicated, we own all of the properties or facilities listed below. Each of the properties is encumbered by our secured credit facilities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and Note 11 – Debt to the notes to consolidated financial statements included in Item 8 of this annual report for additional information concerning our credit facilities. For a discussion about how each of our business segments utilizes its respective properties, see Item 1, “Business” of this annual report.
 
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LocationApproximate 
Square
Footage/Acreage
Description
Canada:  
Fort McMurray, Alberta (leased land)240 acresWapasu Creek and Henday Lodges
Fort McMurray, Alberta (leased land)138 acresFort McMurray Village
Fort McMurray, Alberta (leased land)135 acresConklin Lodge
Fort McMurray, Alberta (leased land)128 acresBeaver River and Athabasca Lodges
Fort McMurray, Alberta (leased land)78 acresMcClelland Lake Lodge
Kitimat, British Columbia59 acresSitka Lodge
Fort McMurray, Alberta (leased land and lodges)58 acresHudson and Borealis Lodges
Acheson, Alberta (lease)40 acresOffice and warehouse
Edmonton, Alberta33 acres
Manufacturing facility (1)
Fort McMurray, Alberta (leased land)30 acresGreywolf Lodge
Grimshaw, Alberta (lease)20 acresEquipment yard
Fort McMurray, Alberta (leased land)18 acresAnzac Lodge
Edmonton, Alberta (lease)86,376 sq. feetOffice and warehouse
Calgary, Alberta (lease)7,000 sq. feetOffice
Australia:  
Coppabella, Queensland, Australia192 acresCoppabella Village
Narrabri, New South Wales, Australia82 acresNarrabri Village
Boggabri, New South Wales, Australia52 acresBoggabri Village
Dysart, Queensland, Australia50 acresDysart Village
Middlemount, Queensland, Australia37 acresMiddlemount Village
Karratha, Western Australia, Australia (owned and leased land)34 acresKarratha Village
Kambalda, Western Australia, Australia27 acresKambalda Village
Nebo, Queensland, Australia26 acresNebo Village
Moranbah, Queensland, Australia17 acresMoranbah Village
Sydney, New South Wales, Australia (lease)11,518 sq. feetOffice
Perth, Western Australia, Australia (lease)8,988 sq. feetOffice
Brisbane, Queensland, Australia (lease)5,543 sq. feetOffice
United States:  
Houston, Texas (lease)8,900 sq. feetPrincipal executive offices
Sulphur, Louisiana44 acresAcadian Acres Lodge and yard
Killdeer, North Dakota39 acresKilldeer Lodge
Pecos, Texas (leased land)35 acresWest Permian Lodge
Yukon, Oklahoma (lease)12 acresMobile asset facility and yard
Belle Chasse, Louisiana10 acresManufacturing facility and yard
Carlsbad, New Mexico (lease)10 acresMobile asset facility and yard
LaSalle, Colorado (lease)6 acresMobile asset facility and yard
Pecos, Texas (lease)7 acresMobile asset facility and yard
Wright, Wyoming (lease)5 acresMobile asset facility and yard
Bloomfield, New Mexico (lease)2 acresMobile asset facility and yard
Longmont, Colorado (lease)4,377 sq. feet
Office (2)

(1) This facility is under contract for sale at December 31, 2020. Such sale is expected to be completed in the first quarter of 2021.
(2) This lease expires at the end of February 2021 and is not expected to be renewed.

We also own various undeveloped properties in British Columbia.

We believe that our leases are at competitive or market rates and do not anticipate any difficulty in leasing additional suitable space upon expiration of our current lease terms.
 
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Leased land for our lodge properties in Canada refers to land leased from the Alberta government. We also lease land for our Karratha Village from the state government in Australia. Generally, our leases have an initial term of ten years and are scheduled to expire between 2021 and 2028.

ITEM 3. Legal Proceedings
 
We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses, and in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

ITEM 4. Mine Safety Disclosures
 
Not applicable.

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PART II

ITEM 5. Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
 
Market for Our Common Shares
 
Our common shares trade on the NYSE under the trading symbol “CVEO”.

Holders of Record
 
As of February 22, 2021, there were 19 holders of record of Civeo common shares.
 
Dividend Information
 
We do not currently pay any cash dividends on our common shares. The declaration and amount of all dividends will be at the discretion of our board of directors and will depend upon many factors, including our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements of our business, covenants associated with certain debt obligations, legal requirements, regulatory constraints, industry practice and other factors the board of directors deems relevant. We can give no assurances that we will pay a dividend in the future.

The preferred shares we issued in the Noralta Acquisition are entitled to receive a 2% annual dividend on the liquidation preference (initially $10,000 per share), paid quarterly in cash or, at our option, by increasing the preferred shares’ liquidation preference, or any combination thereof. Quarterly dividends have been paid in-kind for each quarterly period beginning June 30, 2018 through December 31, 2020, thereby increasing the liquidation preference to $10,563 per share as of December 31, 2020. We currently expect to pay dividends on the preferred shares for the foreseeable future through an increase in liquidation preference rather than cash. For further information, see Note 19 - Preferred Shares to the notes to the consolidated financial statements included in Item 8 of this annual report.

Performance Graph

The share price performance shown on the graph is not necessarily indicative of future price performance. Information used in the graph was obtained from Research Data Group, Inc., a source believed to be reliable, but we are not responsible for any errors or omissions in such information.
The following performance graph and chart compare the cumulative total return to holders of our common shares with the cumulative total returns of the Standard & Poor's 500 Stock Index, Philadelphia OSX and with that of our peer group, for the period from December 31, 2015 to December 31, 2020. The graph and chart show the value, at the dates indicated, of $100 invested at December 31, 2015 and assume the reinvestment of all dividends, as applicable.

Our peer group consists of Basic Energy Services, Inc., Black Diamond Group Limited, Dexterra Group Inc., Exterran Corporation, Forum Energy Technologies, Inc., Matrix Service Company, Newpark Resources, Inc., Nine Energy Service Inc., Quintana Energy Services Inc.(1), Oil States International, Inc., Precision Drilling Corporation, Select Energy Services Inc., Source Energy Services Ltd., Step Energy Services Ltd., Tetra Tech Inc. and Total Energy Services Inc.

(1) This company was acquired in July 2020.
 

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cveo-20201231_g4.jpg
 12/31/1512/31/1612/31/1712/31/1812/31/1912/31/20
Civeo Corporation$100.00 $154.93 $192.25 $100.70 $90.85 $81.57 
S&P 500$100.00 $111.96 $136.40 $130.42 $171.49 $203.04 
PHLX Oil Service Sector$100.00 $118.98 $98.51 $53.97 $53.67 $31.09 
Current Peer Group$100.00 $143.88 $124.27 $77.10 $85.50 $77.83 
 
The performance graph above is furnished and not filed for purposes of the Securities Act and the Exchange Act. The performance graph is not soliciting material subject to Regulation 14A.
 
Unregistered Sales of Equity Securities and Use of Proceeds
 
None.

Repurchases of Equity Securities by Registrant or its Affiliates in the Fourth Quarter
 
None.

ITEM 6. Selected Financial Data

Not applicable.

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act that are based on management’s current expectations, estimates and projections about our business operations.  Please read “Cautionary Statement Regarding Forward Looking Statements.”  Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of numerous factors, including the known material factors set forth in Item 1A. “Risk Factors” of this annual report.  You should read the following discussion and analysis together with our consolidated financial statements and the notes to those statements in Item 8 of this annual report.

This section of this annual report generally discusses key operating and financial data as of and for the years ended 2020 and 2019 and provides year-over-year comparisons for such periods. For a similar discussion and year-over-year comparisons to our 2018 results, please refer to "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020.
 
Description of the Business
 
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. 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. 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. We operate in three principal reporting business segments – Canada, Australia and the U.S.

Reverse Share Split

On November 19, 2020, we effected a reverse share split where each twelve issued and outstanding common shares were converted into one common share (Reverse Share Split). Our common shares began trading on a reverse share split adjusted basis on November 19, 2020. All common share and per common share data included in this annual report have been retroactively adjusted to reflect the Reverse Share Split.

See Note 1 - Description of Business and Basis of Presentation to the notes to the consolidated financial statements in Item 8 of this annual report for further discussion regarding the Reverse Share Split.
 
Basis of Presentation
 
Unless otherwise stated or the context otherwise indicates: (i) all references in these consolidated financial statements to “Civeo,” “us,” “our” or “we” refer to Civeo Corporation and its consolidated subsidiaries; and (ii) all references in this annual report to “dollars” or “$” are to U.S. dollars.
 
Overview and Macroeconomic Environment
 
Demand for our services can be attributed to two phases of our customers’ projects: (1) the development or construction phase; and (2) the operations or production phase. Historically, initial demand for our hospitality services has been driven by our customers’ capital spending programs related to the construction and development of natural resource projects and associated infrastructure, as well as the exploration for oil and natural gas. Long-term demand for our services has been driven by natural resource production and operation of those facilities as well as expansion of those sites. In general, industry capital spending programs are based on the outlook for commodity prices, economic growth, global commodity supply/demand dynamics and estimates of resource production. As a result, demand for our hospitality services is largely sensitive to expected commodity prices, principally related to oil, met coal, LNG and iron ore. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in Canada, Australia, the U.S. and other markets, including governmental measures introduced to fight climate change or to help slow the spread or mitigate the impact of COVID-19.
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Our business is predominantly located in northern Alberta, Canada; British Columbia, Canada; Queensland, Australia; and Western Australia. We derive most of our business from natural resource companies who are developing and producing oil sands, met coal, LNG and iron ore resources and, to a lesser extent, other hydrocarbon and mineral resources. Approximately 66% of our revenue is generated by our lodges in Canada and our villages in Australia. Where traditional accommodations and infrastructure are insufficient, inaccessible or cost ineffective, our lodge and village facilities provide comprehensive hospitality services similar to those found in an urban hotel. We typically contract our facilities to our customers on a fee-per-person-per-day basis that covers lodging and meals and is based on the duration of customer needs, which can range from several weeks to several years.
Generally, our core Canadian oil sands and Australian mining customers are making significant capital investments to develop their prospects, which have estimated reserve lives ranging from ten years to in excess of 30 years. Consequently, these investments are primarily dependent on those customers’ long-term views of commodity demand and prices.
The spread of COVID-19 and the response thereto have negatively impacted the global economy. The actions taken to mitigate the spread of COVID-19 and the risk of infection have altered, and are expected to continue to alter, governmental and private-sector policies and behaviors in ways that have had a significant negative effect on oil consumption, such as government-imposed or voluntary social distancing and quarantining, reduced travel and remote work policies. Additionally, global oil prices dropped to historically low levels in March and April 2020 due to severely reduced global oil demand, high global crude inventory levels, uncertainty around timing and slope of worldwide economic recovery after COVID-19 related economic shut-downs and effectiveness of production cuts by major oil producing countries, such as Saudi Arabia, Russia and the U.S. In mid-April 2020, OPEC+ (the combination of historical OPEC members and other significant oil producers, such as Russia) announced production cuts of up to approximately 10 million barrels per day. However, oil prices remained at depressed levels throughout most of 2020, before modest improvement late in the year and into early 2021. Prices are expected to remain relatively volatile throughout 2021.
The economic disruption caused by the spread of COVID-19 and decline in the price of and demand for oil have impacted the activity in the Canadian oil sands, and we have seen a decrease in demand for rooms by our oil sands customers. The reduction in the occupancy at our Canadian oil sands lodges negatively impacted our business in 2020 and could continue to negatively impact our business if oil prices continue to remain volatile. Due to lower oil prices in 2020 and the economic disruption caused by COVID-19, we implemented certain cost containment initiatives, including salary and total compensation reductions of 20% for the Board and Chief Executive Officer for 2020 from March levels, salary reductions for senior management in Canada and the U.S., headcount reductions in North America of approximately 33% from March through December 2020, and decreases to 2020 capital spending by approximately 25%. 
Despite the aforementioned negative impact of COVID-19 on the global economy, the impact on the Australian mining industry in 2020 was relatively muted. Due to strong Chinese steel demand, supply disruptions in other countries and limited COVID-19 cases in Australia, Australian met coal and iron ore activity was relatively buoyant in 2020.
We continue to closely monitor the COVID-19 situation 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.
Alberta Canada. In Canada, Western Canadian Select (WCS) crude is the benchmark price for our oil sands customers. Pricing for WCS is driven by several factors, including the underlying price for West Texas Intermediate (WTI) crude, the availability of transportation infrastructure (consisting of pipelines and crude by railcar) and recent actions by the Alberta provincial government to limit oil production from the province. Historically, WCS has traded at a discount to WTI, creating a “WCS Differential,” due to transportation costs and capacity restrictions to move Canadian heavy oil production to refineries, primarily along the U.S. Gulf Coast. The WCS Differential has varied depending on the extent of transportation capacity availability.
Certain expansionary oil pipeline projects have the potential to both drive incremental demand for mobile assets and to improve take-away capacity for Canadian oil sands producers over the longer term. While these pipeline projects, including Kinder Morgan’s Trans Mountain Pipeline (TMX), have recently received incremental regulatory approvals, it is still not certain if any of the proposed pipeline projects will ultimately be completed. Certain segments of the TMX pipeline have begun construction; however, the construction timeline continues to be delayed due to the lack of agreement between the Canadian federal government, which supports the pipeline projects, and the British Columbia provincial government. The Canadian federal government acquired TMX pipeline in 2018, approved the expansion of the project and is currently working through the revised construction timeline. In April 2020, the Alberta provincial government announced its intent to financially support the construction of the Keystone XL pipeline (KXL). The construction of this pipeline expansion was suspended due to the U.S.
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Supreme Court refusing to renew a water permit for the KXL pipeline in July 2020. After President Biden's inauguration in January 2021, he implemented an executive order to revoke a necessary cross-border permit, canceling the project.
WCS prices in the fourth quarter of 2020 averaged $31.34 per barrel compared to a low of $19.73 in the second quarter of 2020 and a high of $49.93 in the second quarter of 2018. The WCS Differential decreased from $22.49 per barrel at the end of the fourth quarter of 2019 to $15.35 at the end of the fourth quarter 2020. In 2018, the Government of Alberta announced it would mandate temporary curtailments of the province’s oil production. 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. The curtailment initially resulted in a narrowing WCS Differential in December 2018, which increased in 2019 before narrowing again in the first quarter of 2020. As of February 22, 2021, the WTI price was $61.49 and the WCS price was $49.95, resulting in a WCS Differential of $11.54.
The depressed price levels of both WTI and WCS materially impacted 2020 maintenance and production spending and activity by Canadian operators and, therefore, demand for our hospitality services. While some of our Canadian oil sands customers conducted maintenance projects in the third quarter 2020, activity was negatively impacted by the current environment. Customers began increasing production activity in the fourth quarter of 2020. Continued uncertainty, including about the impact of COVID-19, and commodity price volatility and regulatory complications 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. Additionally, if oil prices do not improve or stabilize, the resulting impact could continue to negatively affect the value of our long-lived assets.
British Columbia, Canada. Our Sitka Lodge supports the LNG Canada project and related pipeline projects. From a macroeconomic standpoint, LNG demand continued to grow despite the COVID-19 pandemic, reinforcing the need for the global LNG industry to expand access to natural gas. Evolving government energy policies around the world have amplified support for cleaner energy supply, creating more opportunities for natural gas and LNG. Accordingly, the current view is additional investment in LNG supply will be needed to meet the expected long-term LNG demand growth.
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). 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 Costal Gas Link 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 pipeline construction.
In late March 2020, LNGC announced steps being taken to reduce the spread of COVID-19, including reduction of the workforce at the project site to essential personnel only. This resulted in a reduction in occupancy at our Sitka Lodge during the second quarter of 2020. Occupancy at the Sitka Lodge returned to expected levels during July 2020 and remained at expected levels thorough the end of 2020.
Australia. In Australia, 82% of our rooms are located in the Bowen Basin of Queensland, Australia and primarily serve met coal mines in that region. Met coal pricing and production growth in the Bowen Basin region is predominantly influenced by the levels of global steel production, which decreased by 0.9% during 2020 compared to 2019. As of February 22, 2021, met coal spot prices were $138.50 per metric tonne. Long-term demand for steel is expected to be driven by global infrastructure spending and increased steel consumption per capita in developing economies, such as China and India, whose current consumption per capita is a fraction of developed countries. In 2020, the impact of the outbreak of COVID-19 led to a high level of uncertainty for demand of iron ore and met coal. The impact on the demand for steel with the closure or curtailment of manufacturing in economies affected by COVID-19, which will only return to normal levels of consumption once jurisdictions lift quarantine requirements and manufacturing facilities are reopened, is also uncertain. However, a new round of stimulus spending in China and recovering steel production in other regions continues to support demand for raw materials, particularly iron ore.
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 Chinese demand for Australian met coal led to a decrease in the met coal spot price to US$103 per tonne at December 31, 2020, though, as noted above, prices recovered somewhat to $138.50 per metric tonne at February 22, 2021. The softening of the met coal spot price 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
46


infrastructure led recovery which may lead to near term volatility in Australian met coal spot pricing. If this dispute continues, it could continue to 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.

Activity in Western Australia is driven primarily by iron ore production, which is a key steel-making ingredient.  As of February 22, 2021, iron ore spot prices were $168.48 per metric tonne.
On July 1, 2019, we acquired Action, a provider of integrated services to the mining industry in Western Australia. Accordingly, we also have contracts in place to service customer-owned villages in Western Australia which service primarily iron ore mines in addition to gold, lithium and nickel mines. We believe prices are currently at a level that may contribute to increased activity over the long term if our customers view these price levels as sustainable.
Met coal and iron ore prices to date have remained at levels that should support the current levels of occupancy in our Australia villages and the customer locations that we manage under our integrated services business. Accordingly, we plan to continue focusing on enhancing the quality of our operations, maintaining financial discipline, proactively managing our business as market conditions continue to evolve.
U.S. Our U.S. business supports oil shale drilling and completion activity and is primarily tied to WTI oil prices in the U.S. shale formations in the Permian Basin, the Mid-Continent, the Bakken and the Rockies. During 2019, the U.S. oil rig count and associated completion activity decreased due to the oil price decline in late 2018 and early 2019 coupled with other market dynamics negatively impacting exploration and production (E&P) spending, finishing the year at 677 rigs. In 2020, the U.S. oil rig count and associated completion activity further decreased due to the global oil price decline discussed above. Only 267 oil rigs were active at the end of 2020. The Permian Basin remains the most active U.S. unconventional play, representing 66% of the oil rigs active in the U.S. at the end of 2020. The lower U.S. rig count and decline in oil prices resulted in decreased U.S. oil production from an average of 12.2 million barrels per day in 2019 to an average of 11.3 million barrels per day in 2020. As of February 19, 2021, there were 305 active oil rigs in the U.S. (as measured by Bakerhughes.com). 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 U.S. mobile assets. Those assets have either been 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. U.S. oil shale drilling and completion activity will continue to be dependent on sustained higher WTI oil prices, pipeline capacity and sufficient capital to support E&P drilling and completion plans. In addition, consolidation among our E&P customer base in the U.S. has historically created short-term spending and activity dislocations. Should the current trend of industry consolidation continue, we may see activity, utilization and occupancy declines in the near term.

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Recent Commodity Prices. Recent WTI crude, WCS crude and met coal pricing trends are as follows:
 
 
Average Price (1)
 Hard 
QuarterWTI CrudeWCS CrudeCoking Coal (Met Coal)
ended(per bbl)(per bbl)(per tonne)
First Quarter through 2/22/2021$54.77 $42.14 $133.18 
12/31/202042.63 31.34 109.37 
9/30/202040.90 31.15 113.30 
6/30/202027.95 19.73 120.27 
3/31/202045.38 27.92 156.17 
12/31/201956.85 37.94 141.39 
9/30/201956.40 43.88 160.25 
6/30/201959.89 47.39 204.78 
3/31/201954.87 44.49 203.30 
12/31/201859.32 25.66 223.02 
9/30/201869.61 41.58 188.46 
6/30/201867.97 49.93 189.41 
3/31/201862.89 37.09 228.82 
12/31/201755.28 38.65 202.33 
(1)Source: WTI crude prices are from U.S. Energy Information Administration (EIA), and WCS crude prices are from Bloomberg and hard coking coal prices are from IHS Markit.

Foreign Currency Exchange Rates. Exchange rates between the U.S. dollar and each of the Canadian dollar and the Australian dollar influence our U.S. dollar reported financial results. Our business has historically derived the vast majority of its revenues and operating income (loss) in Canada and Australia. These revenues and profits/losses are translated into U.S. dollars for U.S. GAAP financial reporting purposes. The following tables summarize the fluctuations in the exchange rates between the U.S. dollar and each of the Canadian dollar and the Australian dollar:
Year Ended December 31,
20202019ChangePercentage
Average Canadian dollar to U.S. dollar$0.746$0.754(0.008)(1.1)%
Average Australian dollar to U.S. dollar$0.691$0.695(0.004)(0.6)%

As of December 31,
20202019ChangePercentage
Canadian dollar to U.S. dollar$0.785$0.7700.0152.0%
Australian dollar to U.S. dollar$0.773$0.7000.07310.4%
 
These fluctuations of the Canadian and Australian dollars have had and will continue to have an impact on the translation of earnings generated from our Canadian and Australian subsidiaries and, therefore, our financial results.

Capital Expenditures. We continue to monitor the COVID-19 global pandemic and the responses thereto, the global economy, the price of demand for crude oil, met coal, LNG and iron ore and the resultant impact on the capital spending plans of our customers in order to plan our business activities. We currently expect that our 2021 capital expenditures, exclusive of any business acquisitions, will total approximately $20.0 million to $25.0 million, compared to 2020 capital expenditures of $10.1 million. See “Liquidity and Capital Resources below for further discussion of 2021 and 2020 capital expenditures.

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Results of Operations
 
Unless otherwise indicated, discussion of results for the year ended December 31, 2020 is based on a comparison with the corresponding period of 2019.
 
Results of Operations – Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
 
 Year Ended
December 31,
 20202019Change
 ($ in thousands)
Revenues   
Canada$269,649 $325,651 $(56,002)
Australia234,542 156,093 78,449 
U.S. 25,538 45,811 (20,273)
Total revenues529,729 527,555 2,174 
Costs and expenses   
Cost of sales and services   
Canada209,283 239,624 (30,341)
Australia144,709 89,090 55,619 
U.S. 28,096 38,100 (10,004)
Total cost of sales and services382,088 366,814 15,274 
Selling, general and administrative expenses53,656 59,586 (5,930)
Depreciation and amortization expense96,547 123,768 (27,221)
Impairment expense144,120 26,148 117,972 
Other operating expense 506 290 216 
Total costs and expenses676,917 576,606 100,311 
Operating loss(147,188)(49,051)(98,137)
Interest expense and income, net(17,050)(27,305)10,255 
Other income20,823 7,281 13,542 
Loss before income taxes(143,415)(69,075)(74,340)
Income tax benefit10,635 10,741 (106)
Net loss(132,780)(58,334)(74,446)
Less: Net income attributable to noncontrolling interest1,470 157 1,313 
Net loss attributable to Civeo Corporation(134,250)(58,491)(75,759)
Less: Dividends attributable to Class A preferred shares1,887 1,849 38 
Net loss attributable to Civeo common shareholders$(136,137)$(60,340)$(75,797)
 
We reported net loss attributable to Civeo for 2020 of $136.1 million, or $9.64 per diluted share. As further discussed below, net loss included (i) a $93.6 million pre-tax loss ($93.6 million after-tax, or $6.63 per diluted share) resulting from the impairment of goodwill in our Canada segment included in Impairment expense, (ii) a $38.1 million pre-tax loss ($38.1 million after-tax, or $2.69 per diluted share) resulting from the impairment of long-lived assets in our Canada segment included in Impairment expense and (iii) a $12.4 million pre-tax loss ($12.4 million after-tax, or $0.88 per diluted share) resulting from the impairment of long-lived assets in our U.S. segment included in Impairment expense. Net loss was partially offset by $4.7 million pre-tax income ($4.7 million after-tax, or $0.33 per diluted share) associated with the settlement of a representations and warranties claim related to the Noralta acquisition included in our Canada segment in Other income.

We reported net loss attributable to Civeo for 2019 of $60.3 million, or $4.33 per diluted share. As further discussed below, net loss included (i) a $19.9 million pre-tax loss ($19.9 million after-tax, or $1.43 per diluted share) resulting from the impairment of goodwill in our Canada segment included in Impairment expense, (ii) a $6.2 million pre-tax loss ($6.1 million after-tax, or $0.44 per diluted share) resulting from the impairment of fixed assets included in Impairment expense, and (iii) a $0.2 million gain on sale of assets related to the sale of a village in Australia and related $2.2 million release of an asset retirement obligation (ARO) liability assumed by the buyer.
 
Revenues. Consolidated revenues increased $2.2 million, or 0%, in 2020 compared to 2019. This increase was primarily due to the full year impact in 2020 of our Australia integrated services business due to the Action acquisition completed in July 2019, increased occupancy at our Bowen Basin villages in Australia and increased mobile asset activity from our pipeline
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project in Canada. These items were partially offset by lower revenue from reduced occupancy at our lodges in Canada resulting from the COVID-19 pandemic, lower oil prices and the global oil market dislocation. Additionally, lower activity levels in certain markets in the U.S. and weaker Canadian dollars relative to the U.S. dollar in 2020 compared to 2019 also offset the increased revenues. See the discussion of segment results of operations below for further information.
 
Cost of Sales and Services. Our consolidated cost of sales increased $15.3 million, or 4%, in 2020 compared to 2019. This increase was primarily due to increased activity at our Australian integrated services business due to the Action acquisition, increased occupancy at our Bowen Basin villages in Australia and increased mobile asset activity from our pipeline project in Canada. These items were partially offset by decreased cost of sales and services due to reduced occupancy at our oil sands lodges in Canada resulting from the COVID-19 pandemic and lower oil prices. Additionally, lower activity levels in certain markets in the U.S. and weaker Canadian dollars relative to the U.S. dollar in 2020 compared to 2019 offset the increased cost of sales and services. See the discussion of segment results of operations below for further information.
 
Selling, General and Administrative Expenses. SG&A expense decreased $5.9 million, or 10%, in 2020 compared to 2019. This decrease was primarily due to lower share-based compensation expense, travel and entertainment expenses and compensation expense, partially offset by higher incentive compensation costs. The decrease in share-based compensation was due to a reduction in the amount of phantom share awards outstanding and the reduction in our average stock price during 2020 compared to 2019. The decrease in travel and entertainment expenses was largely a result of reduced travel due to COVID-19.

Depreciation and Amortization Expense. Depreciation and amortization expense decreased $27.2 million, or 22%, in 2020 compared to 2019. The decrease was primarily due to (i) the impairment of certain long-lived assets in Canada and the U.S. during the first quarter of 2020, (ii) the extension of the remaining life of certain long-lived accommodation assets in Canada during the fourth quarter of 2019 and (iii) certain assets and intangibles becoming fully depreciated during 2019. These items were partially offset by additional depreciation and intangible amortization expense related to our Action acquisition in 2019.

Impairment Expense. Impairment expense of $144.1 million in 2020 included the following items:

Pre-tax impairment expense of $93.6 million related to the impairment of goodwill in our Canadian reporting unit.
Pre-tax impairment expense of $38.1 million associated with long-lived assets in our Canadian segment.
Pre-tax impairment expense of $12.4 million associated with long-lived assets in our U.S. segment.

Impairment Expense. Impairment expense of $26.1 million in 2019 included the following items:

Pre-tax impairment expense of $19.9 million related to the impairment of goodwill in our Canadian reporting unit.
Pre-tax impairment expense of $0.7 million associated with long-lived assets in our Canadian segment.
Pre-tax impairment expense of $5.5 million associated with long-lived assets in our Australian segment. This includes $1.0 million of impairment expense related to an error corrected in the second quarter 2019. We identified a liability related to an ARO at one of our villages in Australia that should have been recorded in 2011. We determined that the error was not material to our previously issued financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2018, and therefore, corrected the error in the second quarter of 2019. Specifically, we recorded the following amounts in our second quarter 2019 unaudited consolidated statements of operations related to prior periods: (1) additional accretion expense related to the ARO of $0.9 million, (2) additional depreciation and amortization expense of $0.5 million related to amortization of the asset retirement cost and (3) additional impairment expense related to the impairment of the asset retirement cost of $1.0 million offset by recognition of an ARO liability totaling $2.3 million as of June 30, 2019.

See Note 4 - Impairment Charges to the notes to the consolidated financial statements included in Item 8 of this annual report for further discussion.
 
Operating Loss. Operating loss increased $98.1 million, or 200%, in 2020 compared to 2019 primarily due to impairments of goodwill and long-lived assets, partially offset by increased operating profit in Australia, as well as lower depreciation and amortization expense.

Interest Expense and Income, net. Net interest expense decreased $10.3 million, or 38%, in 2020 compared to 2019 primarily related to lower average debt levels and lower interest rates on term loan and revolving credit facility borrowings during 2020 compared to 2019.

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Other Income. Other income increased $13.5 million, or 186%, in 2020 compared to 2019, primarily due to $13.0 million of other income related to proceeds from the Canada Emergency Wage Subsidy (CEWS) and $4.7 million of other income associated with the settlement of a representations and warranties claim related to the Noralta Acquisition, partially offset by smaller gains on sale of assets in 2020 compared to 2019. Other income in 2019 also included $2.6 million of other income related to proceeds from an insurance claim associated with maintenance-related operational issues and a gain on sale of assets related to the sale of a village in Australia and related $2.2 million release of an ARO liability assumed by the buyer.

Income Tax Benefit.  Our income tax benefit for 2020 totaled $10.6 million, or 7.4% of pretax loss, compared to a benefit of $10.7 million, or 15.5% of pretax loss for 2019.  Our effective tax rate for 2020 was lower than the Canadian federal statutory rate of 15%, primarily due to a non-deductible Canadian goodwill impairment charge of $95.3 million, as well as the release of a valuation allowance of $9.1 million against the net deferred tax assets in Australia. This was partially offset by a valuation allowance of $6.4 million established against net deferred tax assets in the U.S. and Canada.

Our effective tax rate for 2019 was lower than the Canadian combined federal and provincial statutory rate of 26.5%, primarily due to a non-deductible Canadian goodwill impairment charge of $19.9 million and a release of a valuation allowance of $2.3 million against the net deferred tax assets in Australia due to the Action acquisition. This was partially offset by pre-tax losses in Australia and the U.S. for which no tax benefit was recorded. As a result, a valuation allowance of $3.2 million was established against net deferred tax assets in the U.S. and Australia.
 
Other Comprehensive Income (Loss). Other comprehensive income increased $6.2 million in 2020 compared to 2019 primarily as a result of foreign currency translation adjustments due to changes in the Canadian and Australian dollar exchange rates compared to the U.S. dollar. The Canadian dollar exchange rate compared to the U.S. dollar increased 2% in 2020 compared to a 5% increase in 2019. The Australian dollar exchange rate compared to the U.S. dollar increased 10.4% in 2020 compared to remaining flat in 2019.
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Segment Results of Operations – Canadian Segment
 
 Year Ended
December 31,
 20202019Change
Revenues ($ in thousands)   
Accommodation revenue (1)
$202,534 $281,577 $(79,043)
Mobile facility rental revenue (2)
33,192 9,575 23,617 
Food service and other services revenue (3)
33,923 33,485 438 
Manufacturing revenue (4)
— 1,014 (1,014)
Total revenues$269,649 $325,651 $(56,002)
Cost of sales and services ($ in thousands)   
Accommodation cost$143,213 $187,679 $(44,466)
Mobile facility rental cost24,842 7,493 17,349 
Food service and other services cost30,616 30,595 21 
Manufacturing cost611 1,025 (414)
Indirect other cost10,001 12,832 (2,831)
Total cost of sales and services$209,283 $239,624 $(30,341)
Gross margin as a % of revenues22.4 %26.4 %(4.0)%
Average daily rate for lodges (5)  
$95 $91 $
Total billed rooms for lodges (6)
2,095,784 3,078,727 (982,943)
Average Canadian dollar to U.S. dollar$0.746 $0.754 $(0.008)

(1)Includes revenues related to lodge rooms and hospitality services for 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 for the periods presented.
(4)Includes revenues related to modular construction and manufacturing services for the periods presented.
(5)Average daily rate is based on billed rooms and accommodation revenue.
(6)Billed rooms represents total billed days for owned assets for the periods presented.

Our Canadian segment reported revenues in 2020 that were $56.0 million, or 17%, lower than 2019. Excluding the impact of a weaker Canadian dollar exchange rate, the segment experienced a 16% decrease in revenues. This decrease was driven by reduced occupancy at our lodges related to lower oil prices and the COVID-19 pandemic. The weakening of the average exchange rate for the Canadian dollar relative to the U.S. dollar by 1% in 2020 compared to 2019 resulted in a $2.6 million period-over-period decrease in revenues. Partially offsetting these items, revenue was favorably impacted by increased mobile asset activity from a pipeline project.

Our Canadian segment cost of sales and services decreased $30.3 million, or 13%, in 2020 compared to 2019. The weakening of the average exchange rate for the Canadian dollar relative to the U.S. dollar by 1% in 2020 compared to 2019 resulted in a $2.1 million period-over-period decrease in cost of sales and services. Excluding the impact of the weaker Canadian exchange rate, the decreased cost of sales and services was driven by reduced occupancy at our lodges in the oil sands region and reduced indirect other costs from a continued focus on cost containment and operational efficiencies. These decreases were partially offset by increased mobile asset activity from a pipeline project and increased costs related to the implementation of enhanced measures during the COVID-19 pandemic.

Our Canadian segment gross margin as a percentage of revenues decreased from 26% in 2019 to 22% in 2020. This was primarily driven by increased costs related to the implementation of enhanced safety measures during the COVID-19 pandemic, as well as reduced operating efficiencies due to lower occupancy.

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Segment Results of Operations – Australian Segment
 
 Year Ended
December 31,
 20202019Change