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UNITED STATES 
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K 
(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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, Canada
98-1253716
 
 
(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 Class
Name of Exchange on Which Registered
Common Shares, no par value
New 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 [X ]
 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
 
                  YES [  ]
NO [X ]
 

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.
 
                  YES [X]
NO [  ]
 

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).
 
                  YES [X]
NO [  ]
 



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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this form 10-K. [X]

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 Filer [  ]
Accelerated Filer [X]  
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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
                  YES [  ]
NO [X ]
 

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 29, 2018, was $577,165,294.
 
The Registrant had 166,115,535 common shares outstanding as of February 22, 2019.
 
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's Definitive Proxy Statement for the 2019 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.



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CIVEO CORPORATION
 
INDEX
 
 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 



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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.

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, coal, natural gas, iron ore and other minerals;

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

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;

our ability to implement our plans or otherwise achieve our forecasts and other expectations with respect to our 2018 acquisition of Noralta Lodge Ltd. and to realize the anticipated synergies and cost savings in the time frame anticipated or at all;

the level of demand 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;

fluctuations in currency exchange rates;

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


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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;

global weather conditions, natural disasters 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;

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.

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 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 Securities and Exchange Commission (the Commission). Also, these 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 are a hospitality company servicing 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 group 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 operate in some of the world’s most active oil, coal and iron ore producing regions, and our customers include major and independent oil companies, mining 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 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 accommodation 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 our fleet of mobile accommodation assets, particularly for shorter term projects such as pipeline construction and seasonal drilling programs, or our scalable lodge or village model, as well as serve guests in customer-owned facilities. As projects grow and headcount needs increase, we are able to meet our customers growing needs at our accommodations facilities or with our

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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 infrastructure are not accessible, sufficient or cost effective. Our hospitality services help facilitate efficient development and production of natural resources found in areas without sufficient housing, infrastructure or local labor. We support the development of these natural resources by providing hospitality services, including lodging, food service, housekeeping, recreation facilities, laundry and facilities management, as well as water and wastewater treatment, power generation, communications and group logistics. 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 villages in Australia, or at facilities owned by our customers. We own and operate 33 lodges and villages with an aggregate of more than 33,000 rooms. Additionally, in both Canada and the U.S., we also offer a fleet of mobile accommodation assets. 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.

On April 2, 2018, we completed our acquisition of Noralta Lodge Ltd. (Noralta). Please see Note 7 - Acquisitions to the notes to the consolidated financial statements in Item 8 of this annual report for further discussion.
 
Demand for our hospitality services is influenced by four primary factors: commodity prices, available infrastructure, headcount requirements and competition. Current commodity prices, and our customers’ expectations for future commodity prices, influence customers’ spending on current productive assets, maintenance on and expansion of existing assets and development of greenfield, brownfield or 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 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 to changes in oil prices, as customers consider their cash operating costs, rather than overall full-cycle returns. Likewise, construction and expansion projects underway have also been less sensitive to commodity price decreases, as customers generally focus on completion and incremental costs. Natural gas prices also influence oil sands activity as an input cost, so as natural gas prices fall, a significant component of our customers’ operating costs falls 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 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 liquefied natural gas (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. Should our customers or potential customers decide to invest in these LNG projects, demand for hospitality services over the next three years will be driven by (i) the construction of the LNG facilities on the coast of British Columbia and (ii) the construction of the related natural gas pipeline infrastructure across British Columbia. Facility construction will create demand for permanent lodge accommodations and services, while pipeline construction activity will drive demand for mobile camp accommodations.

Currently, Western Canada does not have any operational LNG export facilities. However, on October 1, 2018, LNG Canada (LNGC), a large LNG export project proposed by a joint venture between 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), Korea Gas Corporation (5 percent) and Mitsubishi Corporation (15 percent), announced that a positive final investment decision (FID) was reached on the proposed Kitimat liquefaction and export facility in Kitimat, British Columbia (Kitimat LNG Facility). See "Canada-Canadian British Columbia Lodge" for more information.


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Our Australian villages support similar activities as our Canadian lodges for the natural resources industry in Australia. Our customers are typically developing and producing metallurgical (met) coal 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 cancelled or deferred during periods of lower met coal 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. During the period from mid-year 2012 to mid-year 2016, much of the previous demand for our hospitality services from new construction activity had ceased. Subsequently, our customer service requirements were primarily 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 assets. This work has also included some small mine expansion projects. The rise in met coal prices since the fourth quarter of 2016 has improved market sentiment, and we are working closely with our existing and potential customers as they consider capital investment and expansion opportunities in the future. We expect that customers will assess the likelihood of a period of sustained higher prices before committing capital to new projects. 

Our U.S. operations are primarily tied to activity in the U.S. shale formations in West Texas, the Bakken, the mid Continent, and the Rockies, as well as activity in the Louisiana downstream and offshore Gulf of Mexico markets. Given the shorter investment horizon and decision cycle of our U.S. customers, typically on a well-by-well basis, spending activities of U.S. customers typically react more quickly to changes in oil and natural gas prices. These spending dynamics were clearly demonstrated over the past six years. With oil prices near $100 per barrel from 2012 to late 2014, drilling and completion activity levels grew. However, as oil prices fell beginning in August 2014, and remained at relatively low levels throughout 2015 and most of 2016, activity in the U.S. reacted swiftly, with the U.S. rig count falling over 50% in six months from its peak in the third quarter of 2014. After staging a significant recovery in 2017, the U.S. rig count was generally stable in 2018, finishing the year at 1,083 rigs. The Permian Basin remains the most active U.S. unconventional play, representing 45% of the rigs in the U.S. market at the end of 2018. Completion activity also grew, with the Permian Basin again seeing the majority of growth in the U.S. market. Unlike the Canadian and Australian markets, headcount requirements for drilling and completion activity are fairly uniform in the U.S. market. Given the U.S. market for accommodations is primarily supported by mobile camp assets, competition is primarily driven by the availability of assets and price.

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For the years ended December 31, 2018, 2017 and 2016, we generated $466.7 million, $382.3 million and $397.2 million in revenues and $88.1 million, $98.0 million and $95.8 million in operating loss, respectively. The majority of our operations, assets and income are derived from the hospitality services provided at our lodges and villages that have historically been contracted by our customers on a take-or-pay basis for periods ranging from several months to three years. The hospitality services we provide at these facilities generate more than 85% of our revenue. Important performance metrics include revenue related to our major properties, aggregate billed rooms and average daily rate. The table below summarizes these key statistics for the periods presented in this annual report.  
 
Year Ended December 31,
 
2018
 
2017
 
2016
 
(In thousands, except for room counts and average daily rate)
Accommodation Revenue (1) 
 
 
 
 
 
Canada
$
266,899

 
$
228,062

 
$
238,221

Australia
117,896

 
111,221

 
106,815

United States
18,288

 
9,832

 
3,806

Total Accommodation Revenue
$
403,083

 
$
349,115

 
$
348,842

 
 
 
 
 
 
Mobile Facility Rental Revenue (2)
 
 
 
 
 
Canada
$
9,316

 
$
3,935

 
$
9,217

United States
20,389

 
8,764

 
6,243

Total Mobile Facility Rental Revenue
$
29,705

 
$
12,699

 
$
15,460

 
 
 
 
 
 
Food Service and Other Services Revenue (3)
 
 
 
 
 
Canada
$
15,601

 
$
11,891

 
$
14,280

Australia
1,342

 

 

United States
170

 
171

 
86

Total Food Service and Other Services Revenue
$
17,113

 
$
12,062

 
$
14,366

 
 
 
 
 
 
Manufacturing Revenue (4)
 
 
 
 
 
Canada
$
4,196

 
$
1,707

 
$
16,746

United States
12,595

 
6,693

 
1,816

Total Manufacturing Revenue
$
16,791

 
$
8,400

 
$
18,562

 
 
 
 
 
 
Total Revenue
$
466,692

 
$
382,276

 
$
397,230

 
 
 
 
 
 
Average Daily Rates for Lodges and Villages (5)
 
 
 
 
 
Canada
$
89

 
$
92

 
$
104

Australia
$
78

 
$
80

 
$
76

 
 
 
 
 
 
Total Billed Rooms for Lodges and Villages (6)
 
 
 
 
 
Canada
3,007,229

 
2,469,899

 
2,284,159

Australia
1,512,030

 
1,385,087

 
1,395,770

 
 
 
 
 
 
Average Exchange Rate
 
 
 
 
 
Canadian dollar to U.S. dollar
$
0.7719

 
$
0.7712

 
$
0.7551

Australian dollar to U.S. dollar
0.7480

 
0.7669

 
0.7439

__________
 
(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 camps 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.
(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 and a manufacturing facility, 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 built and sold to Syncrude in 1990 and 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. Through our experiences and service delivery model, our hospitality services have evolved to include fitness centers, water and wastewater treatment, laundry service and many other advancements. As our experience in the region grew, we were the first to introduce to the Canadian oil sands market suite-style accommodations for middle and upper-level management working in the region, with our Beaver River Executive Lodge in 2005. Since then, we have continued to innovate our service offerings to meet our customers’ growing and evolving needs. On April 2, 2018, we acquired Noralta, which provides remote hospitality services in Alberta, Canada (the Noralta Acquisition).  With eleven lodges comprising of over 5,700 owned rooms and 7,900 total rooms, Noralta has the capacity to house large workforces and the flexibility to meet our clients’ rapidly changing needs. From our entrepreneurial beginning, we have developed into Canada’s largest third-party provider of accommodations and hospitality services in the oil sands region.

Today, we also support customers’ logistical efforts in managing the movement of large numbers of personnel efficiently. At our Wapasu Creek location, we have introduced services that improve efficiencies for customers in transporting personnel to mine sites on a daily basis, as well as in rotating personnel when crews change.

During 2015, we entered the Canadian LNG market with our Sitka Lodge. Most of the Sitka Lodge’s 646 rooms were under contract through October 2017 to LNGC. On October 1, 2018, LNGC's participants announced that a positive FID had been reached on the Kitimat LNG Facility. With the project moving forward, British Columbia LNG activity and related pipeline projects could become a material driver of future activity for our Sitka Lodge, as well as for our mobile camp assets, which are well suited for 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 all our operating regions, our business is built on a culture of continuous service improvement to enhance the guest experience and reduce customers' workforce housing costs.

We take an active role in minimizing 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 waste-water treatment and water treatment facilities to recycle grey and black water on some of our sites, we are able to gain cost efficiencies as well as reduce the use of trucks related to water and wastewater hauling, which in turn, reduces our carbon footprint. In our Australian villages, we utilize passive-solar-design principles and smart-switching systems to reduce the need for electricity related to heating and cooling.

Our 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 day-to-day operations, such as laundry, water and wastewater treatment, power generation, communication systems, security and group 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, coal, natural gas and other resource reserves.  Our customers’ spending plans generally are based on their

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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 construction accommodations needs. Our facilities provide customers with cost efficiencies as they are able to share the costs of accommodations related infrastructure (power, water, sewer and IT) and central dining and recreation facilities with other customers operating projects in the same vicinity.

Our business is significantly influenced by the level of production of oil sands deposits in Alberta, Canada, activity levels in support of extractive industries in Australia, LNG and related pipeline activity in Canada and oil production in Canada and the U.S. Our two primary activity drivers are development and production activity in the Canadian oil sands region in Western Canada and the met coal region of Australia’s Bowen Basin.

Historically, oil sands developers and Australian mining companies built, owned and in some cases operated the accommodations necessary to house their personnel in these remote regions because local labor and third-party owned rooms were not available. Over the past 20 years, and increasingly over the past 10 years, some customers have moved away from the insourcing business model for some of their accommodations 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 landscaped grounds where weather permits. Lodges and villages are generally supported by multi-year, take-or-pay contracts. These facilities are designed to serve the long-term needs of customers in constructing and operating their resource developments. Mobile camps 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 accommodations as they evaluate or initially develop a field or mine. Mobile camp projects can be dedicated and committed to a single customer or project or the camps can serve multiple customers.

The accommodations 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), Horizon North Logistics Inc. (Horizon North), Alta-Fab Structures Ltd. (Alta-Fab) and Northgate Industries Ltd. (Northgate), will build the modular accommodations for sale. Horizon North, Black Diamond Group Limited (Black Diamond), ATCO, Royal Camp Services Ltd. and Algeco Scotsman will primarily own and lease the 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 camp 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. We believe our service model provides value to our customers by reducing project timing and counterparty risks. In addition, with our holistic approach to hospitality services, we are able to identify and execute on efficiency opportunities for our customers by being able to bundle our services to meet their specific needs.
 
Canada
 
Overview
 
During the year ended December 31, 2018, we generated approximately 63% of our revenue from our Canadian operations.  We are 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 oil sands and in a variety of oil and natural gas drilling, mining and related natural resource applications, as well as disaster relief efforts.
 
Canadian Market
 
Demand for our hospitality services in the Canadian oil sands region is primarily influenced by the longer-term outlook for crude oil prices rather than current energy prices, given the multi-year production phase of oil sands projects and the costs associated with development of such large scale projects.  Utilization of our existing Canadian capacity and our future

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expansions will largely depend on continued oil sands spending related to existing production efforts, maintenance thereon 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 37 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 grown rapidly over the last decade, stressing their infrastructures and challenging them to respond to large-scale changes in demand. As such, the workforce accommodations market provides a cost effective solution to the problem of staffing large oil sands projects by sourcing labor largely throughout Canada to work on a rotational basis.

Canadian Oil Sands Lodges
 
During the year ended December 31, 2018, activity in the Athabasca oil sands region generated over 85% of our Canadian revenue. The oil sands region of northern Alberta, Canada continues to represent one of the world’s largest reserves for heavy oil. Our McClelland Lake, Wapasu, Henday, Athabasca, Beaver River, Fort McMurray Village, Grey Wolf, Hudson, Borealis and Firebag lodges are focused on the northern region of the Athabasca oil sands, where customers primarily utilize surface mining to extract the bitumen, or oil sands. 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, Mariana Lake, Anzac, Red Earth and Wabasca lodges, as well as a portion of our mobile camp assets, are focused in the southern portion of the region where we primarily serve in-situ operations and pipeline expansion 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 support construction and operating personnel for maintenance and expansionary projects, as well as ongoing operations associated with surface mining and in-situ oil sands projects, 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, or subleased from the resource developer, with initial terms of ten years. Our leases have expiration dates that range from 2020 to 2028. Currently, none of our Canadian lodges are on land with leases expiring prior to December 31, 2019. 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 two to ten years. Our development permits have expiration dates that range from 2019 to 2023. In recent years, we have successfully renewed or extended all expiring development permits. See “Item 1A. Risk Factors-Risks related to our business-All but three 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.  During 2018, with the exception of the Noralta Acquisition, no further rooms were added (net of retirements) to our major oil sands lodges.  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). Customers make a minimum nightly or monthly room 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
 
The initial development of our Sitka Lodge, in Kitimat, British Columbia, included 646 rooms built in 2015. Most of these rooms were under contract through October 2017 to LNGC. The initial phase of this location featured food service and recreational facilities and the ability to expand should demand for rooms in the region warrant.


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On October 1, 2018, LNGC's participants announced a positive FID on the Kitimat LNG Facility. With the project moving forward, British Columbia LNG activity and related pipeline projects could become a material driver of future activity for our Sitka Lodge, as well as for our mobile camp assets, which are well suited for the related pipeline construction activity. We previously announced contract awards totaling C$100 million in revenues to supply mobile accommodations for four locations along the Coastal GasLink (CGL) pipeline project in British Columbia, Canada. This pipeline would provide the natural gas for the Kitimat LNG Facility. We expect to deploy approximately C$10 million in capital, primarily in 2019, across all four locations. We expect to begin recognizing revenue from these contracts beginning in 2019. In addition, in the fourth quarter of 2018, we were awarded room commitments from LNGC, CGL and LNGC’s engineering, procurement and construction firm to provide rooms and services from Sitka Lodge. The award covers expected room needs over an initial 18 month time period with a minimum room commitment and options for extension of up to 36 months. We began recognizing revenue from this award beginning in November 2018. Revenues for the room commitments are estimated to be approximately C$70 million over the initial 18 months. 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. We expect to spend approximately C$15 million in capital to expand the Sitka Lodge to 1,100 rooms.

Canadian Lodge Locations
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Rooms in our Canadian Lodges
 
 
 
 
 
 
As of December 31,
 
Lodges
 
Region
 
Extraction
Technique
 
2018
 
2017
 
2016
Wapasu
 
N. Athabasca
 
mining
 
5,246

 
5,246

 
5,246

Athabasca
 
N. Athabasca
 
mining
 
2,005

 
2,005

 
2,005

McClelland Lake
 
N. Athabasca
 
mining
 
1,997

 
1,997

 
1,997

Henday (1)
 
N. Athabasca
 
mining/in situ
 
1,698

 
1,698

 
1,698

Beaver River
 
N. Athabasca
 
mining
 
1,094

 
1,094

 
1,094

Fort McMurray Village:
 
 
 
 
 
 
 
 
 
 
Buffalo (2)
 
N. Athabasca
 
mining
 
573

 

 

Black Bear (2)
 
N. Athabasca
 
mining
 
531

 

 

Bighorn (2)
 
N. Athabasca
 
mining
 
763

 

 

Lynx (2)
 
N. Athabasca
 
mining
 
855

 

 

Wolverine (2)
 
N. Athabasca
 
mining
 
855

 

 

Borealis (1) (2)
 
N. Athabasca
 
mining
 
1,504

 

 

Grey Wolf (2)
 
N. Athabasca
 
mining
 
946

 

 

Firebag (1) (2)
 
N. Athabasca
 
in situ
 
664

 

 

Hudson (1) (2)
 
N. Athabasca
 
mining
 
624

 

 

Wabasca (2)
 
S. Athabasca
 
mining
 
246

 

 

Red Earth (1) (2)
 
S. Athabasca
 
mining
 
216

 

 

Conklin
 
S. Athabasca
 
mining/in situ
 
1,032

 
1,032

 
1,032

Anzac (1)
 
S. Athabasca
 
in situ
 
526

 
526

 
526

Mariana Lake (1)
 
S. Athabasca
 
mining
 
686

 
686

 
686

Subtotal – Oil Sands
 
 
 
 
 
22,061

 
14,284

 
14,284

Sitka Lodge
 
Kitimat, BC
 
LNG
 
646

 
436

 
436

Total Rooms
 
 
 
 
 
22,707

 
14,720

 
14,720

                                                                     
(1)
Currently closed 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).  Please see Note 4 - Impairment Charges to the notes to the consolidated financial statements in Item 8 of this annual report for further discussion. 
(2)
Lodges acquired in the Noralta Acquisition.

Hospitality Services at Third-Party Owned Facilities

We 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 the natural resource owners. Currently, we operate camp facilities for third-party customers. The facilities we manage range anywhere from 200 to 1,500 rooms. We are able to customize our service offerings depending on our client’s needs. Hospitality services can be performed on an end-to-end basis with food service, maintenance and utility services included or in segments such as food service only.

Recently, we have engaged in developing a related food service brand, Red Table. This diversification initiative targets food service and facility management opportunities outside of the natural resources industry, including educational, entertainment, healthcare and traditional catering events. Currently, Red Table operates more than ten facilities, and includes a food production facility, which began operations in the second quarter of 2018.

Canadian Mobile Accommodations
Our mobile accommodations 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. The 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 camp management services, including fresh water and sewage hauling services. Our mobile camps 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. The 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.


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Our mobile camp 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 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 the business nature of servicing client-owned facilities, this business easily fits into our overall business. Aside from the traditional workforce accommodations, we are expanding our target markets to areas such as institutional, educational and entertainment facilities.

Australia
 
Overview
 
During the year ended December 31, 2018, we generated 26% of our revenue from our Australian operations.  As of December 31, 2018, we had 9,346 rooms across ten 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 five years) with minimum nightly room commitments. During 2018, no further rooms were added to our Australian villages.
 
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. The growth of Australian natural resource commodity exports over the last decade has been largely driven by strong Asian demand for 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 develop 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 and 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, 2018, our five villages in the Bowen Basin of central Queensland generated 80% of our Australian revenue. The Bowen Basin contains one of the largest coal deposits in Australia and is renowned for its premium met coal. Met coal is used in the steel making process and demand has largely been driven by global demand for steel finished goods and steel construction materials. In recent years, growth in construction demand for steel products in emerging economies, particularly China, slowed significantly, negatively impacting demand for the commodity. However, the rebounding of steel demand in 2017 and 2018 led to improved pricing for met coal in 2017 and 2018. Australia is the largest exporter of met coal in the world, in addition to being in close proximity to the largest steel producing countries in the world. Our villages are focused on the mines in the central portion of the basin and are well positioned for the active mines in the region.

Beyond the Bowen Basin, we serve several markets with four additional villages. At the end of 2018, 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 the gold fields through our Kambalda village.


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Australian Village Locations
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Rooms in our Australian Villages
 
 
 
 
 
 
As of December 31,
 
Villages
 
Resource
Basin
 
Commodity
 
2018
 
2017
 
2016
Coppabella
 
Bowen
 
met coal
 
3,048

 
3,048

 
3,048

Dysart
 
Bowen
 
met coal
 
1,798

 
1,798

 
1,798

Moranbah
 
Bowen
 
met coal
 
1,240

 
1,240

 
1,240

Middlemount
 
Bowen
 
met coal
 
816

 
816

 
816

Boggabri
 
Gunnedah
 
met/thermal coal
 
622

 
622

 
662

Narrabri
 
Gunnedah
 
met/thermal coal
 
502

 
502

 
502

Nebo
 
Bowen
 
met coal
 
490

 
490

 
490

Calliope (1)
 
-
 
LNG
 
300

 
300

 
300

Kambalda
 
-
 
Gold, lithium
 
232

 
232

 
232

Karratha
 
Pilbara
 
LNG, iron ore
 
298

 
298

 
298

Total Rooms
 
 
 
 
 
9,346

 
9,346

 
9,386

                                                    
(1)     Currently closed due to low activity level in the region. This village was assessed for impairment upon its closure, and written down to its fair market value in 2015. Please see Note 4 - Impairment Charges to the notes to the consolidated financial statements in Item 8 of this annual report for further discussion.
 
Our Australian segment includes ten villages with 9,346 rooms as of December 31, 2018 and are strategically located near long-lived, low-cost mines operated by large mining companies.  Our Australian business provides hospitality services to mining and related service companies under short- and medium-term contracts.  Our growth plan for this part of our business continues to include enhanced occupancy and expansion of these properties where we believe there is durable long-term demand, as well as to provide hospitality services at customer owned assets.

Our Coppabella, Dysart, Moranbah, Middlemount and Nebo villages are located in the Bowen Basin. Coppabella, at over 3,000 rooms, is our largest village and provides rooms and related hospitality services to a variety of customers. Each of these villages supports both operational workforce needs and contractor needs with resort style amenities, including swimming pools, gyms, a walking track and a tavern. Our Nebo, Dysart, Moranbah and Middlemount Villages have a long history of providing service in the region.


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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. 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.

U.S.
 
Overview
 
During the year ended December 31, 2018, our U.S. business generated 11% of our revenue. Our U.S. business has operational exposure in the U.S. shale formations in West Texas, the Bakken, the mid Continent, and the Rockies and offshore Gulf of Mexico markets. The business provides accommodations facilities with hospitality services and highly mobile smaller camps 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 400-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, Rockies and Permian Basin, labor demand has exceeded the local labor supply and accommodations infrastructure to support the demand. Consequently, demand for remote, scalable accommodations and hospitality services has developed in the U.S. over the past several years. Demand for hospitality services 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.

U.S. Locations
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U.S. Mobile Camps
 
Our business in the U.S. consists primarily of mobile camp assets, both in the lower 48 states, including the Rocky Mountain corridor, the Bakken Shale region, the mid Continent region, the Permian Basin region of Texas, and in the Gulf of Mexico. 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. We provide quality hospitality services such as food service and housekeeping services as well.

Our mobile camps 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,
 
 
State
 
2018
 
2017
 
2016
West Permian
 
TX
 
390

 
326

 
310

Acadian Acres
 
LA
 
400

 

 

Killdeer
 
ND
 
235

 
235

 
235

Total Rooms
 
1,025

 
561

 
545


We had three lodges in the U.S. comprised of 1,025 rooms as of December 31, 2018. Our Killdeer Lodge, which we opened in October 2013, 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, which we acquired in February 2018, provides rooms near Lake Charles, Louisiana to support the Louisiana downstream market.
 
Modular Construction
 
The capability of our Canadian business includes the design, engineering, transportation and installation of a variety of modular buildings, predominately for our own use. As of December 31, 2018, we owned one modular construction and manufacturing plant near Edmonton, Alberta, Canada. During the fourth quarter of 2017, we made the decision to sell this plant due to changing geographic and market needs. In line with our Australian and U.S. strategy, we are now subcontracting modular construction from third-party manufacturers for our Canadian business. In Canada, we continue to retain a staff of experts who have designed and delivered large and small modular construction projects. We are capable of taking highly replicable and well-designed manufactured buildings and our expertise in site layout, combined with site-built components including landscaping, recreational facilities and certain common facilities, to create a comfortable community within a community. We design accommodations facilities to suit the climate, terrain and population of a specific project site.

Community Relations
 
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 and member-owned businesses to deliver water hauling, snow removal and security services. The annual value of these contracts exceeds C$10 million.

Our Indigenous partnership initiatives were recognized in 2011 and 2012 with awards from the Alberta Chamber of Commerce. In addition, 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 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 new arrangements provide employment, training, and ancillary business opportunities for indigenous owned businesses.


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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.

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, humanitarian aid and disaster relief, and support for military operations.  Our largest customers in 2018 were Imperial Oil Limited (a company controlled by ExxonMobil Corporation), Fort Hills Energy LP (a partnership between Suncor Energy Inc., Total E&P Canada Ltd and Teck Resources Limited) and Suncor Energy Inc., who each accounted for more than 10% of our 2018 revenues.

Our primary competitors in Canada in lodge and mobile camp hospitality services include ATCO, Black Diamond, Horizon North 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 and Compass Group for third-party facility management and hospitality services.

Our primary competitors in Australia for our village hospitality services are Ausco Modular (a subsidiary of Algeco Scotsman) and Fleetwood Corporation.  We also compete against Sodexo and Compass Group for third-party facility management services.

In the U.S., we primarily offer our lodge and mobile camp 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) and Black Diamond.

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, 2018, revenues from our lodges and villages represented over 80% 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, utilities and maintenance for workers staying in the lodges and villages. In multi-year contracts, our rates typically have annual contractual 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 a minimum number of rooms over a determined 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, 2018, we had commitments for 24% of our rentable rooms for 2019 and 11% of our rentable rooms for 2020.


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As of December 31, 2018, we had 5,472 rooms under contract. The table below details the expiration of those contracts: 
 
Contracted
Room Expiration
2019
1,541

2020
3,613

2021
318

2022

2023

Thereafter

Total
5,472

 
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.   
 
Employees
 
As of December 31, 2018, we had approximately 700 full-time employees and approximately 1,500 hourly employees on a consolidated basis, 73% of whom are located in Canada, 18% of whom are located in Australia and 9% of whom are located in the U.S.  We were party to collective bargaining agreements covering approximately 1,100 employees located in Canada and 140 employees located in Australia as of December 31, 2018.

Government Regulation
 
Our business is significantly affected by foreign 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 compliance costs or additional operating restrictions associated with our operations or our customers’ operations;

other increased costs to our business or our customers’ business;

reduced demand for oil, natural gas, and other natural resources that our customers produce; and

reduced demand for our services.
  
To the extent that these laws and regulations impose more stringent requirements or increased costs or delays upon our customers in the performance of their operations, the resulting demand for our services by those customers may be adversely affected, which impact could be significant and long-lasting. Moreover, climate change laws or regulations could increase the cost of consuming, and thereby reduce demand for, oil and natural gas, which could reduce our customers’ demand for our services. We cannot predict changes in the level of enforcement of existing laws and regulations, how these laws and regulations may be interpreted or the effect changes in these laws and regulations may have on us or our customers or on our

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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.  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, provincial and local governments have jurisdiction to regulate environmental matters. We or our customers may be subject to environmental regulations imposed by these three levels of government. The following addresses updates to Canadian environmental regulations in 2018 that may affect us or our customers.

Air Quality Management

The Government of Alberta (Alberta) and the Government of Canada (Canada) each have frameworks for air quality management that may affect us and our customers.

At the federal level, the Multi-Sector Air Pollutants Regulations impose mandatory air emissions standards that limit the amount of nitrogen oxides and sulphur dioxides that can be emitted from certain boilers, heaters and gaseous-fuel-fired engines used in industrial facilities as well as from cement kilns. These regulations may impact emission performance standards for compressors and boilers used by our customers in conventional and steam assisted gravity operations in the oil sands 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 the province, oversees compliance with Directive 60, which 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 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 per cent 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, with the first such report covering the 2019 calendar year and coming due on June 1, 2020. Meeting these regulatory requirements may result in additional costs or liabilities for our customers’ operations.

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.  On January 29, 2010, Canada affirmed its desire to be associated with the Copenhagen Accord that was negotiated in December 2009 as part of the international meetings on climate change regulation in Copenhagen.  The Copenhagen Accord, which is not legally binding, allows countries to commit to specific efforts to reduce GHG emissions, although how and when the commitments may be converted into binding emission reduction obligations, if ever, is currently uncertain.  Pursuant to the Copenhagen Accord process, Canada has indicated an economy-wide GHG emissions target that equates to a 17 percent reduction from 2005 levels by 2020, and the former Canadian Conservative federal government indicated an objective of reducing overall Canadian GHG emissions by 60 percent to 70 percent from 2006 levels by 2050.  However, with current climate change measures in place, Canada’s GHG emissions are forecast to be just under 6% below 2005 levels by 2020.

In December 2015, 195 nations, including Canada, Australia, and the U.S., adopted the Paris Agreement at the 21st “Conference of the Parties” (COP 21). The Paris Agreement does not set legally binding emission reduction targets but does set

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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 it must take to achieve them. These measures are left to each participating nation. In September 2016, the 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 come 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 certain 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. 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 legislative carbon pricing “backstop” applying a benchmark carbon price in any province that does not establish an equivalent framework at or above the benchmark level. The backstop allows individual provinces to choose between an explicit price-based system (as exists in British Columbia) or a cap-and-trade system (as exists in Quebec). Features of the backstop come into effect at various points in 2019 in Ontario, New Brunswick, Manitoba, Saskatchewan, Yukon, Nunavut and Prince Edward Island. Saskatchewan and Ontario are challenging the backstop in court on the basis that the federal government lacks the constitutional ability to implement the measure. The outcome of this litigation is uncertain and could affect our customers compliance requirements in provinces subject to the backstop or which may become subject to the backstop in the future.

Additionally, GHG regulation can take place at the provincial level. For example, Alberta’s Climate Change and Emissions Management Act provides 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 are set out in the Carbon Competitiveness Incentive Regulation (CCIR), which was issued in 2018 to replace the former Specified Gas Emitters Regulation, following changes announced as part of government’s Climate Leadership Plan (CLP) launched in November 2015. Like its predecessor, the CCIR incentivizes emissions reductions through the use of emissions intensity targets. A company can 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. 

Between 2015 and 2017, the government of Alberta increased the price per fund credit from $15 to $30 per credit. There are financial penalties for non-compliance for every ton of carbon dioxide equivalent over a facility’s net emission intensity limit as well as for contraventions of other provisions contained in the CCIR. Further, the CCIR imposes GHG emissions reporting requirements on a company that has GHG emissions of 50,000 tons or more of carbon dioxide equivalent from a facility in a calendar year.  In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations in approvals and under other environmental regulations.

The implementation of the CCIR in 2018 largely maintained the preceding Specific Gas Emitters Regulation’s emissions reduction framework, but, as anticipated following the CLP’s announcement, introduced a number of changes that increase the regime’s stringency. Most notably, for the purposes of calculating emissions limits, the CCIR largely replaces the facility-specific baselines of its predecessor with product-specific benchmarks based on either 80% of production-weighted average emissions, best-in-class or top quartile production methodologies. Each of these benchmarks has a 1% tightening rate applicable to the 2020 compliance years and beyond that results in the benchmark becoming more stringent over time. The CCIR also imposes caps on the percentage of a facility’s emissions compliance obligation that can be met using emission

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performance credits and offsets, thereby requiring either greater fund credit purchases or emissions improvements from affected facilities. These changes, among others, may significantly increase the cost of compliance for some of our customers.

The 2015 CLP also proposed introducing a broad economy-wide levy on GHG emissions from the combustion of fossil fuels, subject to limited exceptions. In May 2016, Alberta passed the Climate Leadership Act, implementing the broad economy-wide levy on GHG emissions contemplated in the CLP. Under that Act, all fuel consumption - including gasoline, diesel, and natural gas consumption - is subject to a carbon levy. The levy was set at $20 per ton in 2017 and rose to $30 per ton in 2018, adding to the cost of most fossil-based fuels. While the federal government’s backstop carbon price is set to rise from $30 per ton in 2020 to $40 per ton in 2021, the Alberta government declared in August 2018 that it would be pulling out of the federal PCF until its concerns with progress on the stalled Trans-Mountain Expansion Project pipeline are resolved. As such, further increases in the carbon levy affecting our customers are uncertain at this time. The carbon levy could also be affected by the result of an Alberta provincial election set to take place before May 31, 2019 and existing court challenges to the PCF’s carbon-pricing scheme.

The CLP also targets a 45 percent reduction in methane emissions from oil and gas operations by 2025, consistent with the subsequently-issued Federal Methane Regulations described above. The AER was assigned the task of developing Alberta’s parallel regulatory framework. In December 2018, the AER released amended directives to require reporting of methane emissions on an annual basis, with annual recording of emissions beginning in the 2019 calendar year for a first report due to the AER on June 1, 2020, together with various facility-specific emissions limits.

Further, as contemplated in the CLP, Alberta passed the Oil Sands Emissions Limit Act which caps oil sands emissions at 100 million tonnes annually. The CLP also targets the phasing out of coal-generated electricity (or the emissions therefrom) by 2030. The combination of the carbon levy and coal phase-out is expected to increase fuel and electricity prices, which could have an impact on our operating costs. 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 financial condition and results of operations.

The Canadian Species at Risk Act is intended to prevent wildlife species in Canada from disappearing and to provide for the recovery of wildlife species that no longer exist in the wild in Canada, or that are endangered or threatened as a result of human activity, and to manage species of special concern to prevent them from becoming endangered or threatened. The designation of previously unprotected species as threatened or endangered in areas of Canada where our customers’ oil and natural gas exploration and production operations are conducted could cause them to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities, which could have an adverse impact on demand for our services.

Alberta’s Electricity Market

The 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 includes 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. REP 1-procured capacity will come into commercial operation by the end of 2019, with REP 2 and REP 3-procured capacity coming online later, in mid-2021. Funding for the REP will 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.

Alberta further announced on November 23, 2016, that it would restructure its power market to include a parallel “capacity market” by 2021. The effect of this change will be to create two revenue streams for power generators in Alberta, one for energy produced (with payments structured similarly to the existing market) and the other for the provision of generating capacity itself (with payments based on outcomes in the new capacity market). The capacity market, managed by the Alberta Electric System Operator, will award rights to “capacity payments” to the lowest bidders in auctions to be held periodically in which all Alberta generation, excepting REP assets, will be eligible to participate. This reform is expected to increase revenue certainty in the sector and stimulate needed investment, while avoiding the risk of cost overruns associated with procuring all

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new capacity pursuant to centrally-managed government procurement processes. The details of the capacity market are currently the subject of Alberta Utilities Commission (AUC) proceedings that, pursuant to amendments to the province’s Electric Utilities Act, will take place between 2019 and 2021 in order to finalize new market rules ahead of the first capacity market-procured capacity coming online. However, provisional rules will be approved by the AUC to be in place ahead of the first capacity auctions scheduled for late 2019.

There is still considerable uncertainty regarding the future of the REP and Alberta’s proposed two-market structure, both of which could potentially increase costs to our customers in the form of higher electricity prices. 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. This may be mitigated by the introduction of the capacity market, which the Alberta government expects to result in more stable power prices without sacrificing affordability to power consumers. However, capacity market outcomes depend on the details of the market’s rules framework, which are the subject of the above-noted AUC proceedings, and the results of numerous capacity auctions scheduled into the future. Both reforms may also be affected by the outcome of a provincial election scheduled for 2019.
 
Australian Environmental Regulations
 
Our Australian segment is regulated by general statutory environmental controls at both the state and federal level which may result in land use approval and compliance risk. These controls include: land use and urban design controls; the regulation of hard and liquid waste, including the requirement for tradewaste 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); and the regulation of pollution and site contamination. Some specified activities, for example, sewage treatment works, may require regulation at a state level by way of environmental protection licenses which also impose monitoring and reporting obligations on the holder. 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. 

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, but in January 2018 released a final rule that delays implementation of the rule revising the WOTUS definition until 2020 to allow time for EPA to reconsider the definition of “waters of the United States.” In August 2018, the U.S. District Court for the District of South Carolina issued a nationwide injunction against EPA’s rule delaying implementation of the WOTUS definition. Pursuant to the court’s order, the 2015 Clean Water Rule is now in effect in 22 states, the District of Columbia, and the U.S. territories. Litigation surrounding this rule is ongoing. More recently, on December 11, 2018, the EPA and the U.S. Army Corps of Engineers released a proposal to revise the 2015 Clean Water Rule so as to narrow the regulatory definition of waters of the U.S., with a 60-day comment period to follow. 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. 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.

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. The EPA has also announced that it intends to impose methane emission standards for existing sources and has issued information collection requests for oil and natural gas facilities. The EPA is currently engaged in rulemaking to stay the effective date of these rules. In April 2018, a coalition of states filed a lawsuit in the U.S. District Court for the District of Columbia aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is pending. 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

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during oil and natural gas production activities on onshore federal and Indian lands, but then proposed a revised rule which scaled back the waste-prevention requirements of the 2016 rule. Environmental groups sued in federal district court a day later to challenge the legality of aspects of the revised rule, and the outcome of this litigation is currently uncertain. In October 2015, the EPA finalized the Clean Power Plan, which imposes additional obligations on the power generation sector to reduce GHG emissions. However, on February 9, 2016, the U.S. Supreme Court stayed implementation of the Clean Power Plan pending resolution of legal challenges to the rule, and in October 2017 the EPA proposed to repeal the rule before proposing a replacement rule, the Affordable Clean Energy Rule, which would scale back the obligations of the Clean Power Plan. 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, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years.  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. also participated in the creation of the Paris Agreement at COP 21 in December 2015 but has subsequently announced its intention to withdraw from the agreement. 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.

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 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

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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. This litigation is pending. 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 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.
 
Risks Related to Our Business

Decreased customer expenditure levels have adversely affected and may continue to adversely affect our results of operations.

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. Although we saw increases in oil prices beginning in late 2016 through the third quarter of 2018, oil prices have remained volatile and significantly decreased during the fourth quarter of 2018. We are not expecting significant improvement in oil-related customer activity in the near-term, as we anticipate that our customers’ expenditures will generally lag increased oil prices by nine to 12 months. If our customers’ expenditures fail to increase in regions where our facilities are located, our business will be adversely impacted. 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, which over the past year, has not been positive. Prices for oil, coal, natural gas, and other minerals are subject to large fluctuations in response to changes in the supply of and demand for these commodities, market uncertainty, and a variety of other factors that are beyond our control. Accordingly, a sudden or long-term decline in commodity pricing, or a continuation of the current volatile commodity price environment, would have material adverse effects on our results of operations.

During the first quarter of 2016, global oil prices dropped to their lowest levels in over ten years due to concerns over global oil demand, global crude inventory levels, worldwide economic growth and price cutting by major oil producing countries, such as Saudi Arabia. Increasing global supply, including increased U.S. shale oil production, also negatively impacted pricing. Since Western Canadian Select (WCS) has historically traded at a discount to West Texas Intermediate (WTI), falling WTI oil prices have also led to falling WCS prices. While WTI and WCS oil prices have rebounded in recent periods, they continue to remain volatile. For example, WCS prices significantly decreased during the second half of 2018, widening the discount at which WCS trades to WTI. WCS prices in the fourth quarter of 2018 averaged $25.66 per barrel compared to a low of $20.26 in the first quarter of 2016 and a high of $83.78 in the second quarter of 2014. On December 2, 2018, the Government of Alberta announced it would mandate temporary curtailments of the Province’s oil production. This curtailment resulted in an increase to the WCS price in December 2018, which has continued into the first quarter of 2019. As of February 22, 2019, the WTI price was $57.11, and the WCS price was $44.26.
 
In addition, met coal prices fluctuated in recent years, due to a declining global demand for steel and the impact of a stronger U.S. dollar, falling to approximately $89.00/metric tonne as of December 31, 2016. The rebounding of steel demand in 2017 and 2018, particularly in China, led to higher met coal pricing in 2017 and 2018. As of February 22, 2019, spot prices for met coal were $210.05/metric tonne. However, the increase in met coal pricing in 2017 and 2018 has not led our customers to approve any significant new projects.

Despite recent rebounds, the low and volatile commodity price environment has depressed exploration, development, and production activity. A deterioration of this price environment is likely to continue to depress activity levels, often reflected as reductions in employees or resource production, and have a material adverse effect on our financial position, results of operations or cash flows.

Additionally, significant new regulatory requirements, including climate change legislation, could have an impact on the demand for and the cost of producing oil, coal and natural gas in the regions where we operate. Many factors affect the supply of and demand for oil, coal, natural gas and other minerals and, therefore, influence product prices, including:

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

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

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

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the availability of transportation infrastructure for oil, natural gas, LNG and coal, refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;

global weather conditions and natural disasters;

worldwide economic activity including growth in developing countries, such as China and India;

national government political requirements, including the ability of the Organization of Petroleum Exporting Companies (OPEC) to set and maintain production levels and prices for oil and government policies which could nationalize or expropriate oil and natural gas exploration, production, refining or transportation assets;

the level of oil and gas production by non-OPEC countries, particularly the U.S. and Russia;

rapid technological change and the timing and extent of energy resource development, including LNG or other alternative fuels;

environmental regulation; and

U.S. and foreign tax policies.

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. Because of 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. Additionally, 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. Further, certain of our customers may 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. 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 cyclical nature of the natural resources industry, our business may be adversely affected by extended periods of low oil, coal or natural gas prices or unsuccessful exploration results may decrease our customers’ spending and therefore our results.

Commodity prices have been and are expected to remain volatile. This volatility causes oil and gas and mining companies to change their strategies and expenditure levels. Prices of oil, coal and natural gas can be influenced by many factors, including reduced demand due to lower global economic growth, surplus inventory, improved technology such as the hydraulic fracturing of horizontally drilled wells in shale discoveries, access to potential productive regions and availability of required infrastructure to deliver production to the marketplace. In particular, global demand for both oil and metallurgical coal is, at least partially, dependent on the growth of the Chinese economy. Should gross domestic product growth in China slow further or contract, demand for oil and metallurgical coal and, correspondingly, our accommodations would fall, which would negatively impact our financial results.

Our business typically supports projects that are capital intensive and require several years to generate first production. The economic analyses conducted by our customers in oil sands, Australian mining and LNG investment areas have historically assumed a relatively conservative longer-term price outlook for production from such projects to determine economic viability. Because of the recent volatile commodity price environment, our customers have reduced or deferred, and may continue to reduce or defer, major expenditures, particularly in Canada and Australia, given the long-term nature of many large scale development projects, adversely affecting our revenues and profitability.


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In Canada, WCS crude is the benchmark price for our oil sands accommodations customers. Pricing for WCS is driven by several factors, including the underlying price for WTI and the availability of transportation infrastructure. Historically, WCS has traded at a discount to WTI. 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. Similarly, the volumes and prices of the mineral products of our customers, including coal and gold, have historically varied significantly and are difficult to predict. The demand for, and price of, these minerals and commodities is highly dependent on a variety of factors, including international supply and demand, the price and availability of alternative fuels, actions taken by governments and global economic and political developments. Mineral and commodity prices have fluctuated in recent years and may continue to fluctuate significantly in the future. No assurance can be given regarding future volumes or prices relating to the activities of our customers. We have experienced in the past, and expect to experience in the future, significant fluctuations in operating results based on these changes.

In addition, the carrying value of our lodges or villages could be reduced by extended periods of limited or no activity by our customers, which has required us to record impairment charges equal to the excess of the carrying value of the lodges or villages over fair value. We recorded impairments of our long-lived assets of $28.7 million, $31.6 million and $46.1 million in 2018, 2017 and 2016, respectively. We may incur additional asset impairment charges in the future, which charges will affect negatively our results of operations and financial condition.

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

Currency exchange rate fluctuations can create volatility in our consolidated financial position, results of operations and/or cash flows. Because our consolidated financial results are reported in U.S. dollars, if we generate net revenues or earnings in countries whose currency is not the U.S. dollar, the translation of such amounts into U.S. dollars can result in an increase or decrease in our reported revenues, net income, financial condition and cash flows depending upon exchange rate movements. For the year ended December 31, 2018, 89% 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.

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. We may attempt to limit the risks of currency fluctuation where possible by entering into financial instruments to protect against foreign currency exposure. 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.

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 89% of our consolidated revenue in the year ended December 31, 2018. Risks associated with our operations in Canada and Australia include, but are not limited to:

international currency fluctuations;

different taxing regimes;

changing political conditions at the federal, provincial or state level;

changing international and U.S. monetary policies;

regional economic downturns;

expropriation, confiscation or nationalization of assets; and

foreign exchange limitations.


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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.

All but three 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.

All but three of our major Canadian lodges are located on land subject to 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 2020 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. 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. Regulations have recently been proposed in a regional municipality of Alberta which would require us to seek renewal of such permits every two years and also would prohibit the granting of new permits or the renewal of existing permits for lodges within 75 kilometers of Fort McMurray, Alberta. 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.

Due to the significant concentration of our business in the oil sands region of Alberta, Canada and in the Bowen Basin coal region of Queensland, Australia, adverse events in these areas 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 region of Queensland, Australia, two relatively small geographic areas, we have increased exposure to political, regulatory, environmental, labor, climate or natural disaster events or developments that could disproportionately impact our operations and financial results. For example, in 2017, a cyclone impacted areas near 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 companies 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.

Development of permanent infrastructure in the Canadian oil sands region, the west coast of British Columbia, regions of Australia or various U.S. locations where we locate our assets could negatively impact our business.

We specialize in providing hospitality services for work forces 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 depend on several significant customers. The loss of one or more such customers or the inability of one or more such customers to meet their obligations to us could adversely affect our results of operations.

We depend on several significant customers. The majority of our customers operate in the energy or mining industry. For a more detailed explanation of our customers, see “Business” in Item 1 of this annual report. 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 two 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. While we perform ongoing credit evaluations of our customers, we do not require collateral in support of our trade receivables.


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As a result of our customer concentration, risks of nonpayment and nonperformance by our counterparties are a concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. Although we have seen an increase in oil prices in late 2016 and through the third quarter of 2018, oil prices significantly decreased during the fourth quarter of 2018, and commodity prices generally have remained depressed since 2015, and the capital markets and availability of credit have been constrained relative to historical levels. Additionally, many of our customers’ equity values have declined and could decline further. The combination of lower cash flow due to commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of available debt or equity financing may continue to result in a significant reduction in our customers’ liquidity and could impair their ability to pay or otherwise perform on their obligations to us. 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. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

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 Rocky Mountain region and 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 Rocky Mountain region and 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 forest fires, which could interrupt our operations and adversely impact our earnings.

Our customers 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 clients’ operations caused by any one of or all of the following singularly or in combination:

U.S. and international pricing and demand for the natural resource being produced at a given project (or proposed project);

unexpected problems, higher costs and delays during the development, construction and project start-up which may delay the commencement of production;

unforeseen and adverse geological, geotechnical, seismic and mining conditions;

lack of availability of sufficient water or power to maintain their operations;

lack of availability or failure of the required infrastructure 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. Such risks may include 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;

interruptions to the operations of our customers caused by industrial accidents or disputes; and

delays in or failure to commission new infrastructure in timeframes so as not to disrupt customer operations.

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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 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 accelerate the timing of their projects. We cannot be certain that these customer preferences will continue or that customers that have 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.

Increased operating costs and obstacles to cost recovery due to the pricing and cancellation terms of our accommodation services contracts 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 severe weather such as droughts, heavy rains and late freezes. While our long term 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.

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), and the cleanliness of food production facilities and the 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 intoxicated or minor 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 or results of operations.

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Our land banking activities may not be successful.

Our land banking activities are focused on investing early in land in order to gain a strategic, early mover advantage in an emerging region or resource play. However, we cannot assure you that all land that we purchase or lease will be in a region in which our customers require our services in the future. We also cannot assure you that the property acquired by us will be profitably developed. Our land banking activities involve significant risks that could adversely affect our financial condition, results of operations, cash flow and the market price of our securities, which include the following risks:

the regions in which we invest may not develop or sustain adequate customer demand;

we may incur costs to acquire land and/or construct assets without securing a customer contract or prior to finalization of an accommodations contract with a customer and, if the contract is not obtained or delayed, the resulting impact could result in an impairment of the related investment;

during the time between acquisition and use, and depending on adjacent uses of the land, the property may become unusable or require costly remediation efforts due to environmental damage;

we may not be able to obtain financing for development projects on favorable terms or at all;

we may not be able to obtain, or may experience delays in obtaining, all necessary zoning, land-use, building, occupancy and other governmental permits and authorizations, and the issuance of permits is dependent upon a number of factors, including water and waste treatment alternatives available, road traffic volumes and fire conditions in forested areas;

development opportunities that we explore may be abandoned and the related investment impaired;

the properties may perform below anticipated levels, producing cash flow below budgeted amounts;

construction costs, total investment amounts and our share of remaining funding may exceed our estimates and projects may not be completed, delivered or stabilized as planned;

we may experience delays (temporary or permanent) if there is public, government or aboriginal opposition to our activities; and

substantial renovation, new development and redevelopment activities, regardless of their ultimate success, typically require a significant amount of management’s time and attention, diverting their attention from our day-to-day operations.

Our business is contract intensive and may lead to customer disputes or delays in receipt of payments.

Our business is contract intensive and we are party to many contracts with customers. 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 could negatively affect sales and operating results. In the past, our customers have withheld payment due to contract or other disputes, which has delayed our receipt of payments. While we do not believe any reviews, audits, delayed payments or other such matters should result in material adjustments, if a large number of our customer arrangements were modified or payments withheld in response to any such matter, the effect could be materially adverse to our business or results of operations.

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

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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 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 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 operations and financial condition, 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.

Construction risks exist which may adversely affect our results of operations.

There are a number of general risks that might impinge on companies involved in the development, construction and installation of facilities as a prerequisite to the management of those assets in an operational sense. We might be exposed to these risks from time to time by relying on these corporations and/or other third parties which could include any and/or all of the following:

the construction activities of our accommodations are partially dependent on the supply of appropriate construction and development opportunities;

development approvals, slow decision making by counterparties, complex construction specifications, changes to design briefs, legal issues and other documentation changes may give rise to delays in completion, loss of revenue and cost over-runs which may, in turn, result in termination of accommodation supply contracts;

other time delays that may arise in relation to construction and development include supply of labor, scarcity of construction materials, lower than expected productivity levels, inclement weather conditions, land contamination, cultural heritage claims, difficult site access or industrial relations issues;

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 or approvals and/or the overall progress of a project;

where we assume design responsibility, there is a risk that design problems or defects may result in rectification and/or costs or liabilities which we cannot readily recover; and

there is a risk that we may fail to fulfill our statutory and contractual obligations in relation to the quality of our materials and workmanship, including warranties and defect liability obligations.

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

As of December 31, 2018, goodwill represented approximately 11% of our total assets, or $114.2 million, entirely in our Canadian reporting unit. We have recorded goodwill because we paid more for one of our businesses that we acquired than the fair market value of the tangible and separately measurable intangible net assets of those businesses. We evaluate goodwill for impairment annually and when an event occurs or circumstances change to suggest that the carrying amount may not be recoverable. We may recognize impairment losses on our goodwill in the future if, among other factors:

global economic conditions remain depressed or further deteriorate, including a further decrease in the price of or demand for oil, natural gas and minerals;

the outlook for future profits and cash flow for our Canadian reporting unit deteriorates as the result of many possible factors, including, but not limited to, increased or unanticipated competition, technology becoming obsolete, need to satisfy changes in customers’ accommodations requirements, further reductions in customer capital spending plans,

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loss of key personnel, adverse legal or regulatory judgment(s), future operating losses at a reporting unit, 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;

costs of equity or debt capital increase; or

valuations for comparable public companies or comparable acquisition valuations deteriorate.

In addition, we recorded impairments of our long-lived assets, including intangibles, of $28.7 million, $31.6 million and $46.1 million in 2018, 2017 and 2016, respectively. Extended periods of limited or no activity by our customers at our lodges or villages could require us to record further impairment charges equal to the excess of the carrying value of the lodges or villages over fair value or could result in an impairment to our goodwill balance.

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 our handling of petroleum hydrocarbons, because of air emissions and waste water discharges related to our operations, and due to 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.

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

Climate change is receiving increasing attention from scientists and legislators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of any change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions. Significant focus is being made on companies that are active producers of depleting natural resources.

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. 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:

result in increased costs associated with our operations and our customers’ operations;

increase other costs to our business;

reduce the demand for carbon-based fuels; and

reduce the 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 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. See Item 1. “Business-Government Regulation” of this annual report for a more detailed description of our climate-change related risks.

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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.

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, including Noralta, and realize these intended benefits. The success of the Noralta Acquisition depends, in large part, on our ability to realize the anticipated benefits, including operating synergies from combining our businesses, which were previously operated independently. An inability to realize expected strategic advantages as a result of the acquisition would negatively affect the anticipated benefits of the acquisition.

Additional risks we could face in connection with acquisitions include:

retaining and integrating key employees of acquired businesses;

retaining and attracting new customers of acquired businesses;

retaining supply and distribution relationships key to the supply chain;

increased administrative burden;

developing our sales and marketing capabilities;

managing our growth effectively;

potential impairment resulting from the overpayment for an acquisition;

integrating operations;

managing tax and foreign exchange exposure;

potentially operating a new line of business;

increased logistical problems common to large, expansive operations; and

inability to pursue and protect patents covering acquired technology.

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. For example, the size of our business is much larger following the completion of the Noralta Acquisition. 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.

Our Amended Credit Agreement contains operating and financial restrictions that may restrict our business and financing activities

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. The Amended Credit Agreement contains customary affirmative and negative covenants that, among other things, limit or restrict (i) subsidiary indebtedness, liens and

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fundamental changes; (ii) asset sales; (iii) acquisitions of margin stock; (iv) specified acquisitions; (v) certain restrictive agreements; (vi) transactions with affiliates; and (vii) investments and other restricted payments, including dividends and other distributions. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA (as defined in the Amended Credit Agreement) to consolidated interest expense, of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 4.50 to 1.0 (as of December 31, 2018).

The permitted level of the maximum leverage ratio changes over time, as illustrated in the table below.
Period Ended
Maximum Leverage Ratio
December 31, 2018
4.50 : 1.00
March 31, 2019
4.75 : 1.00
June 30, 2019
4.50 : 1.00
September 30, 2019
4.00 : 1.00
December 31, 2019 & thereafter
3.50 : 1.00

Each of the factors considered in the calculations of these ratios are defined in the Amended Credit Agreement. EBITDA and consolidated interest, as defined, exclude goodwill and asset impairments, debt discount amortization and other non-cash charges.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under the Amended Credit Agreement. The restrictions contained in the Amended Credit Agreement could:

limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and

adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.

Additionally, our ability to comply with some of the covenants, ratios or tests contained in the Amended Credit Agreement may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could 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. 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.

We may not be able to reduce our indebtedness to comply with these covenants. A failure to comply with these covenants, ratios or tests could 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 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, 2018, we had approximately $247.9 million outstanding under the term loan portion of the Amended Credit Agreement, $131.3 million outstanding under the revolving portion of the Amended Credit Agreement, $3.4 million of outstanding letters of credit and capacity to borrow an additional $90.3 million under the revolving portion of the Amended Credit Agreement. As of December 31, 2018, $14.5 million of our borrowing capacity under the Amended Credit Agreement could not be utilized in order to maintain compliance with the maximum leverage ratio financial covenant in the Amended Credit Agreement. Borrowings outstanding under the Amended

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Credit Agreement mature in November 2020. If market or other economic conditions remain depressed or further deteriorate, our borrowing capacity may be further reduced.

Our level of indebtedness may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on our indebtedness as such payments become due. Our level of indebtedness may affect our operations in several ways, including the following:

our indebtedness may increase our vulnerability to general adverse economic and industry conditions;

the covenants contained in the Amended Credit Agreement limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;

our debt covenants also affect our flexibility in planning for, and reacting to, changes in the economy and in its industry; and

our indebtedness could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes.

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.

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

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, 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 the following other risks related to our insurance coverage:

we may not be able to continue to obtain insurance on commercially reasonable terms;

the counterparties to our insurance contracts may pose credit risks; and

we may incur losses from interruption of our business that exceed our insurance coverage.

Our operations may suffer due to increased industry-wide capacity of certain types of assets.

The demand for and/or pricing of rooms and accommodation service 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.

In addition, we significantly increased our capacity in the Canadian oil sands region, including as a result of the Noralta Acquisition, and in Australia over the past several years based on our previous expectations for customer demand for accommodations in these areas. However, due to the sustained low commodity prices throughout 2016 and 2017 and into

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2018, customer demand for accommodations in those areas has decreased significantly, and we have experienced a corresponding significant decrease in our occupancy and profitability. Should our customers build their own facilities to meet their accommodations needs or our competitors likewise increase their available accommodations, or activity in the oil sands or natural resources regions declines further, demand and/or pricing for our accommodations could further decrease, negatively impacting our profitability.

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

The workforce accommodation 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 reputation for safety. We compete with international and regional competitors, several of which are significantly larger than us. 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, 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.

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.

Employee and customer labor problems could adversely affect us.

As of December 31, 2018, we were party to collective bargaining agreements covering approximately 1,100 employees in Canada and 140 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 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, financial condition and results of operations. Additional unionization efforts and new collective bargaining agreements also could materially increase our costs, reduce our revenues or limit our flexibility. Collective bargaining agreements in our Canadian operations have individual expiration dates, extending in some cases to 2023.  One enterprise bargaining agreement exists in our Australian operation covering certain employees working at our villages in Queensland and New South Wales.  This agreement was renewed in 2017 through 2019.

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 aboriginal lands. The inability to develop and maintain relationships and to be in compliance with local requirements could have an adverse effect on our business, results of operations or financial condition.

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

Civeo is a British Columbia company and a substantial portion of its 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.

We may increase our debt or issue equity in the future, which could affect our financial condition, may decrease our profitability or could dilute our shareholders.

We may increase our debt or issue equity in the future, subject to restrictions in our debt agreements and our ability to access the capital markets. If our cash flow from operations is less than we anticipate, or if our cash requirements are more than

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we expect, we may require more financing. However, debt or equity financing may not be available to us on terms acceptable to us, if at all. As a result of our failure to timely file an Exchange Act report, we are currently ineligible to use a registration statement on Form S-3 to register the offer and sale of securities, which could increase the expense of accessing the capital markets. Assuming we continue to timely file our required Exchange Act reports, the earliest we would regain the ability to use Form S-3 is June 1, 2019. If we incur additional debt or raise equity through the issuance of our preferred shares, the terms of the debt or our preferred shares issued may give the holders rights, preferences and privileges senior to those of holders of our common shares, particularly in the event of liquidation. The terms of the debt may also impose additional and more stringent restrictions on our operations than we currently have. If we raise funds through the issuance of additional equity, your ownership in us would be diluted. If we are unable to raise additional capital when needed, it could affect our financial health, which could negatively affect your investment in us.

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; 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. In the past, we experienced a data security breach resulting from unauthorized access to our systems, which to date has not had a material impact on our operations; however, there is no assurance that such impacts will not be material in the future. 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 and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data.

Risks Related to Our Structure Following our Redomestication

We are subject to various Canadian and other taxes.

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, the financial performance of our business in various jurisdictions, currency exchange rate fluctuations (especially as 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 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 for Canadian corporations that are controlled by non-Canadian corporations in respect of non-Canadian business activities and investments. These rules would have a negative impact on us to the extent that we became controlled by a non-Canadian resident corporation.

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

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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.

The Internal Revenue Service (IRS) may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes, and no ruling has been sought from the IRS.

For U.S. federal income tax purposes, a corporation generally is considered a tax resident in the jurisdiction of its organization or incorporation. Because we are a British Columbia incorporated entity following the Redomicile Transaction, we generally will be classified as a foreign corporation (and, therefore, a non-U.S. tax resident) under U.S. federal income tax law, and we believe that we are properly classified as a foreign corporation (that is a non-U.S. tax resident) for purposes of U.S. federal income tax law. Even so, the IRS may assert that we should be treated as a U.S. corporation (and, therefore, a U.S. tax resident) for U.S. federal income tax purposes pursuant to Section 7874 of the Internal Revenue Code. If it were determined that we should be taxed as a U.S. corporation for U.S. federal income tax purposes, we could be liable for substantial additional U.S. federal income taxes.

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.

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 other jurisdictions where we operate could change in the future, and such changes could cause a material change in our effective corporate tax rate. As a result, our actual effective tax rate may be materially different from our 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.

Our tax position may be adversely affected by changes in tax law relating to multinational corporations, or increased scrutiny by tax authorities.

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

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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, and any such changes could materially adversely affect us.

Moreover, U.S. and international tax authorities may carefully scrutinize companies that have redomiciled, such as our company, which may lead such authorities to assert that we owe additional taxes.

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (U.S. Tax Reform) was signed into law, making significant changes to the U.S. Internal Revenue Code.  Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, the transition of U.S. international taxation from a worldwide tax system to a quasi-territorial system, and a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017. Although many aspects of this legislation have been clarified since the law was enacted, some aspects of the new legislation remain unclear and may not be clarified for some time. It is possible that the U.S. Tax Reform, or interpretations under it, could have an adverse effect on us, and such effect could be material.

Risks Related to the Spin-Off from Oil States

Our tax sharing agreement with Oil States may require us to indemnify Oil States for significant tax liabilities.

In connection with the Spin-Off, we entered into a tax sharing agreement. Under the tax sharing agreement, we are required to indemnify Oil States against certain tax-related liabilities incurred by Oil States (including any of its subsidiaries) relating to the Spin-Off, to the extent caused by our breach of any representations or covenants made in the tax sharing agreement or the separation and distribution agreement, or made in connection with the private letter ruling or the tax opinion obtained with respect to the Spin-Off. These liabilities include the substantial tax-related liability (calculated without regard to any net operating loss or other tax attribute of Oil States) that would result if the Spin-Off of our stock to Oil States stockholders failed to qualify as a tax-free transaction. In addition, we have agreed to pay 50% of any taxes arising from the Spin-Off to the extent that the tax is not attributable to the fault of either party.

We could have significant tax liabilities for periods during which our subsidiaries and operations were those of Oil States.

For any tax periods (or portion thereof) in which Oil States owned at least 80% of the total voting power and value of Civeo US’s common stock, our U.S. subsidiaries will be included in Oil States’ consolidated group for U.S. federal income tax purposes. In addition, one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of Oil States or one or more of its subsidiaries for U.S. state or local income tax purposes. In addition, by virtue of Oil States’ controlling ownership and the tax sharing agreement, Oil States will effectively control all of our U.S. tax decisions in connection with any consolidated, combined or unitary income tax returns in which any of our subsidiaries are included. The tax sharing agreement provides that Oil States will have sole authority to respond to and conduct all tax proceedings (including tax audits) relating to us, to prepare and file all consolidated, combined or unitary income tax returns in which we are included on our behalf (including the making of any tax elections), and to determine the reimbursement amounts in connection with any pro forma tax returns. This arrangement may result in conflicts of interest between Oil States and us. For example, under the tax sharing agreement, Oil States will be able to choose to contest, compromise or settle any adjustment or deficiency proposed by the relevant taxing authority in a manner that may be beneficial to Oil States and detrimental to us; provided, however, that Oil States may not make any settlement that would materially increase our tax liability without our consent.

Moreover, notwithstanding the tax sharing agreement, U.S. federal law provides that each member of a consolidated group is liable for the group’s entire tax obligation. Thus, to the extent Oil States or other members of Oil States’ consolidated group fail to make any U.S. federal income tax payments required by law, one or more of our U.S. subsidiaries could be liable for the shortfall with respect to periods in which such subsidiary was a member of Oil States’ consolidated group. Similar principles may apply for foreign, state or local income tax purposes where we file combined, consolidated or unitary returns with Oil States or its subsidiaries for federal, foreign, state or local income tax purposes.

If there is a determination that the Spin-Off is taxable for U.S. federal income tax purposes because the facts, assumptions, representations, or undertakings underlying the tax opinion are incorrect or for any other reason, then Oil States and its stockholders could incur significant income tax liabilities, and we could incur significant liabilities.

Oil States received a private letter ruling from the IRS and an opinion of its outside counsel regarding certain aspects of the Spin-Off transaction. The private letter ruling and the opinion rely on certain facts, assumptions, representations and undertakings from Oil States and us regarding the past and future conduct of the companies’ respective businesses and other matters. If any of these facts, assumptions, representations, or undertakings are, or become, incorrect or not otherwise satisfied,

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Oil States and its stockholders may not be able to rely on the private letter ruling or the opinion of its tax advisor and could be subject to significant tax liabilities. In addition, an opinion of counsel is not binding upon the IRS, so, notwithstanding the opinion of Oil States’ tax advisor, the IRS could conclude upon audit that the Spin-Off is taxable in full or in part if it disagrees with the conclusions in the opinion, or for other reasons, including as a result of certain significant changes in the stock ownership of Oil States or us. If the Spin-Off is determined to be taxable for U.S. federal income tax purposes for any reason, Oil States and/or its stockholders could incur significant income tax liabilities, and we could incur significant liabilities.

Third parties may seek to hold us responsible for liabilities of Oil States that we did not assume in our agreements.

Third parties may seek to hold us responsible for retained liabilities of Oil States. Under our agreements with Oil States, Oil States agreed to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from Oil States.

The Spin-Off may have exposed us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements.

The Spin-Off is subject to review under various state and federal fraudulent conveyance laws. Under these laws, if a court in a lawsuit by an unpaid creditor or an entity vested with the power of such creditor (including without limitation a trustee or debtor-in-possession in a bankruptcy by us or Oil States or any of our respective subsidiaries) were to determine that Oil States or any of its subsidiaries did not receive fair consideration or reasonably equivalent value for distributing shares of our common stock or taking other action as part of the Spin-Off, or that we or any of our subsidiaries did not receive fair consideration or reasonably equivalent value for incurring indebtedness, including the debt incurred by us in connection with the Spin-Off, transferring assets or taking other action as part of the Spin-Off and, at the time of such action, we, Oil States or any of our respective subsidiaries (i) was insolvent or would be rendered insolvent, (ii) had reasonably small capital with which to carry on its business and all business in which it intended to engage or (iii) intended to incur, or believed it would incur, debts beyond its ability to repay such debts as they would mature, then such court could void the Spin-Off as a constructive fraudulent transfer. If such court made this determination, the court could impose a number of different remedies, including without limitation, voiding our liens and claims against Oil States, or providing Oil States with a claim for money damages against us in an amount equal to the difference between the consideration received by Oil States and the fair market value of our company at the time of the Spin-Off.

The measure of insolvency for purposes of the fraudulent conveyance laws will vary depending on which jurisdiction’s law is applied. Generally, however, an entity would be considered insolvent if the present fair saleable value of its assets is less than (i) the amount of its liabilities (including contingent liabilities) or (ii) the amount that will be required to pay its probable liabilities on its existing debts as they become absolute and mature. No assurance can be given as to what standard a court would apply to determine insolvency or that a court would determine that we, Oil States or any of our respective subsidiaries were solvent at the time of or after giving effect to the Spin-Off, including the distribution of shares of our common stock.

Under the separation and distribution agreement, Oil States is and we are responsible for the debts, liabilities and other obligations related to the business or businesses which Oil States and we, respectively, own and operate following the Spin-Off. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to Oil States, particularly if Oil States were to refuse or were unable to pay or perform the subject allocated obligations.

Risks Related to Our Common Shares

If we cannot meet the NYSE continued listing requirements, the NYSE may delist our common shares.

Our common shares are currently listed on the NYSE, and the continued listing of our common shares is subject to our compliance with a number of listing standards. If we fail to maintain compliance with these continued listing standards, our common shares may be delisted. A delisting of our common shares could negatively impact us by, among other things:

reducing the liquidity and market price of our common shares;

reducing the number of investors, including institutional investors, willing to hold or acquire our common shares, which could negatively impact our ability to raise equity;


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decreasing the amount of news and analyst coverage of us;

limiting our ability to issue additional securities, obtain additional financing or pursue strategic restructuring, refinancing or other transactions; and

impacting our reputation and, as a consequence, our ability to attract new business.

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

The market price of our common shares has historically experienced and may continue to experience volatility. For example, during 2017, the market price of our common shares ranged from a low of $1.57 per share to a high of $3.73 per share, and during 2018, the market price of our common shares ranged from a low of $1.12 per share to a high of $4.64 per share. From January 1, 2019 to February 22, 2019, the market price of our common shares has ranged between a low of $1.39 per share to a high of $2.72 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 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.

Our financial position, cash flows, results of operations and share price could be materially adversely affected if commodity prices do not improve or decline further. 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. 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.

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. These rights include, among others:
the right to receive a liquidation preference prior to any distribution of our assets to the holders of our common shares;
the right to receive a 2% annual dividend, paid quarterly in cash or, at our option, by increasing the shares’ liquidation preference, or any combination thereof; and

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the right to convert the preferred shares into common shares after two years from the closing of the Noralta Acquisition at an initial conversion price of US$3.30 per common share, which may not be the fair market value of such shares at the time of conversion.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common shares or if our operating results do not meet their expectations, our share price could decline.

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 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.

We cannot assure you that we will pay dividends in the future, and our indebtedness could limit our ability to pay dividends on our common shares.

We currently do not pay dividends. 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. In addition, our ability to pay dividends on our common shares is limited by covenants in the Amended Credit Agreement. Future agreements may also limit our ability to pay dividends. If we elect to pay dividends in the future, the amount per share of our dividend payments may be changed, or dividends may again be suspended, without advance notice. The likelihood that dividends will be reduced or suspended is increased during periods of market weakness. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report. There can be no assurance that we will pay a dividend in the future.

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.

Our business could be negatively affected as a result of the actions of activist shareholders.

Publicly traded companies have increasingly become subject to campaigns by investors seeking to increase shareholder value by advocating corporate actions such as financial restructuring, increased borrowing, special dividends, share repurchases or even sales of assets or the entire company. It is possible activist shareholders may attempt to effect such changes or acquire control over us. Responding to proxy contests and other actions by such activist shareholders or others in the future would be costly and time-consuming, disrupt our operations and divert the attention of our board of directors and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of shareholder activism or changes to the composition of the board of directors may lead to the perception of a change in the direction of the business, instability or lack of continuity

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which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our revenue, earnings and operating cash flows could be adversely affected.

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.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties
 
The following table presents information about our principal properties and facilities as of December 31, 2018. Except as indicated below, we own all of the properties or facilities listed below. Each of the properties is encumbered by our secured credit facilities. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 12 – 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, please see Item 1, “Business” of this annual report.

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Location
Approximate 
Square
Footage/Acreage
 
Description
Canada:
 
 
 
Fort McMurray, Alberta (leased land)
240 acres
 
Wapasu Creek and Henday Lodges
Fort McMurray, Alberta (leased land)
138 acres
 
Fort McMurray Village
Fort McMurray, Alberta (leased land)
135 acres
 
Conklin Lodge
Fort McMurray, Alberta (leased land)
128 acres
 
Beaver River and Athabasca Lodges
Fort McMurray, Alberta (leased land)
78 acres
 
McClelland Lake Lodge
Fort McMurray, Alberta (leased land and lodges)
58 acres
 
Hudson and Borealis Lodges
Fort McMurray, Alberta (leased land)
51 acres
 
Greywolf Lodge
Kitimat, British Columbia
48 acres
 
Sitka Lodge
Fort McMurray, Alberta (leased land)
43 acres
 
Mariana Lake Lodge
Acheson, Alberta (lease)
40 acres
 
Office and warehouse
Edmonton, Alberta
33 acres
 
Manufacturing facility
Grimshaw, Alberta (lease)
20 acres
 
Equipment yard
Fort McMurray, Alberta (leased land)
18 acres
 
Anzac Lodge
Edmonton, Alberta (lease)
86,376 sq. feet
 
Office and warehouse
Calgary, Alberta (lease)
7,000 sq. feet
 
Office
Australia:
 
 
 
Coppabella, Queensland, Australia
192 acres
 
Coppabella Village
Calliope, Queensland, Australia
124 acres
 
Calliope Village
Narrabri, New South Wales, Australia
82 acres
 
Narrabri Village
Boggabri, New South Wales, Australia
52 acres
 
Boggabri Village
Dysart, Queensland, Australia
50 acres
 
Dysart Village
Middlemount, Queensland, Australia
37 acres
 
Middlemount Village
Karratha, Western Australia, Australia (own and lease)
34 acres
 
Karratha Village
Kambalda, Western Australia, Australia
27 acres
 
Kambalda Village
Nebo, Queensland, Australia
26 acres
 
Nebo Village
Moranbah, Queensland, Australia
17 acres
 
Moranbah Village
Sydney, New South Wales, Australia (lease)
11,518 sq. feet
 
Office
Brisbane, Queensland, Australia (lease)
5,543 sq. feet
 
Office
United States:
 
 
 
Houston, Texas (lease)
8,900 sq. feet
 
Principal executive offices
Sulphur, Louisiana
44 acres
 
Acadian Acres Lodge and yard
Killdeer, North Dakota
39 acres
 
Killdeer Lodge
Pecos, Texas (lease)
35 acres
 
West Permian Lodge
Dickinson, North Dakota (lease)
26 acres
 
Mobile asset facility and yard
Vernal, Utah (lease)
21 acres
 
Mobile asset facility and yard
Casper, Wyoming (lease)
14 acres
 
Accommodations facility and yard
Yukon, Oklahoma (lease)
12 acres
 
Mobile asset facility and yard
Belle Chasse, Louisiana
10 acres
 
Manufacturing facility and yard
Big Piney, Wyoming (lease)
7 acres
 
Mobile asset facility and yard
LaSalle, Colorado (lease)
6 acres
 
Mobile asset facility and yard
Pecos, Texas (lease)
5 acres
 
Mobile asset facility and yard
Wright, Wyoming (lease)
5 acres
 
Mobile asset facility and yard
Longmont, Colorado (lease)
4,377 sq. feet
 
Office

We own various undeveloped properties in British Columbia. We also have various offices supporting our business segments which are both owned and leased. 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 provincial government in Australia. Generally, our leases have an initial term of ten years and are scheduled to expire between 2020 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, 2019, there were 21 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), subject to increase to up to 3% in certain circumstances, paid quarterly in cash or, at our option, by increasing the preferred shares’ liquidation preference, or any combination thereof. Quarterly dividends were paid in-kind on June 30, September 30, and December 31, 2018, thereby increasing the liquidation preference to $10,150 per share as of December 31, 2018. 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 12 – 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 current and prior peer groups, for the period from June 2, 2014 to December 31, 2018. The graph and chart show the value, at the dates indicated, of $100 invested at June 2, 2014 and assume the reinvestment of all dividends, as applicable.

In 2018, we revised our peer group to ensure the companies continue to provide appropriate comparability to us. Prior to the revision, our peer group consisted of Basic Energy Services, Inc., Black Diamond Group Limited, Carbo Ceramics, Inc., Choice Hotels International, Inc., Extended Stay America, Inc., Forum Energy Technologies, Inc., Horizon North Logistics Inc., Matrix Service Company, Newpark Resources, Inc., Oil States International, Inc., Precision Drilling Corporation and Tetra Tech, Inc. Our current peer group consists of Basic Energy Services, Inc., Black Diamond Group Limited, Exterran Corporation, Forum Energy Technologies, Inc., Horizon North Logistics Inc., Matrix Service Company, Newpark Resources, Inc., Oil States International, Inc., Parker Drilling Company, Pioneer Energy Service Corporation, Precision Drilling Corporation, Source Energy Services Ltd., Step Energy Services Ltd., Tetra Tech, Inc. and Unit Corporation.

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https://cdn.kscope.io/78d13cca772c3e354a667969a71dfa48-item5performancegraph.jpg 

  
 
 
6/2/14

 
12/31/14

 
12/31/15

 
12/31/16

 
12/31/17

 
12/31/18

Civeo Corporation
 
$
100.00

 
$
17.99

 
$
6.21

 
$
9.63

 
$
11.95

 
$
6.26

S&P 500
 
$
100.00

 
$
108.31

 
$
109.81

 
$
122.94

 
$
149.78

 
$
143.21

PHLX Oil Service Sector
 
$
100.00

 
$
74.32

 
$
57.56

 
$
72.45

 
$
61.86

 
$
34.99

Prior Peer Group (1)
 
$
100.00

 
$
69.12

 
$
51.49

 
$
64.91

 
$
64.87

 
$
50.48

Current Peer Group (2)
 
$
100.00

 
$
59.23

 
$
36.83

 
$
56.46

 
$
46.27

 
$
29.47

 
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.


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Repurchases of Equity Securities by Registrant or its Affiliates in the Fourth Quarter
 
The following table provides information about purchases of our common shares during the three months ended December 31, 2018.

Period
Total Number of Shares Purchased
 
Average Price Paid per Share
 
Total number of shares purchased as part of publicly announced plans or programs (3)
Maximum number of shares that may yet be purchased under the plans or programs (3)
October 1, 2018 - October 31, 2018

 

 


November 1, 2018 - November 30, 2018
102,919

(1)
$1.94
(2)


December 1, 2018 - December 31, 2018

 

 


Total
102,919

 
$1.94
 


                          
(1)
Consists of shares surrendered to us by participants in our 2014 Equity Participation Plan to settle the participants' personal tax liabilities that resulted from the lapsing of restriction on shares awarded to the participants under the plan.
(2)
The price paid per share was based on the closing price of our common shares on November 28, 2018, the dates the restrictions lapsed on such shares.
(3)
We did not have at any time during the quarter ended December 31, 2018, and currently do not have, a share repurchase program in place.

ITEM 6. Selected Financial Data
 
The following tables present the selected historical consolidated financial information of Civeo and combined financial information of the accommodations business. The term “accommodations business” refers to Oil States International Inc.’s (Oil States) historical accommodations segment reflected in its historical combined financial statements discussed herein. The accommodations business was spun off from Oil States on May 30, 2014. All financial information presented after our spin-off from Oil States represents the consolidated results of operation and financial position of Civeo. Accordingly,

Our consolidated statement of operations data for the years ended December 31, 2018, 2017, 2016 and 2015 consists entirely of the consolidated results of Civeo. Our consolidated statement of operations data for the year ended December 31, 2014 consists of (i) the combined results of the Oil States accommodations business for the five months ended May 30, 2014 and (ii) the consolidated results of Civeo for the seven months ended December 31, 2014.

Our consolidated balance sheet data at December 31, 2018, 2017, 2016, 2015 and 2014 consists entirely of the consolidated balances of Civeo.
 
The balance sheet data as of December 31, 2018 and 2017 and the statement of operations data for each of the years ended December 31, 2018, 2017 and 2016 are derived from our audited financial statements included in Item 8 of this annual report. The balance sheet data as of December 31, 2016, 2015 and 2014 and statement of operations data for the years ended December 31, 2015 and 2014 are derived from our audited financial statements not included in this annual report.
 
The historical financial information presented below should be read in conjunction with our consolidated financial statements and accompanying notes in Item 8 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this annual report. The financial information may not be indicative of our future performance and, for periods prior to December 31, 2014, does not necessarily reflect what the financial position and results of operations would have been had we operated as a separate, stand-alone entity during those periods, including changes that occurred in our operations as a result of our spin-off from Oil States.
 

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For the year ended December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(In thousands, except per share data)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues
$
466,692

 
$
382,276

 
$
397,230

 
$
517,963

 
$
942,891

Operating loss
(88,055
)
 
(97,971
)
 
(95,760
)
 
(145,003
)
 
(142,891
)
Net loss attributable to Civeo or the Accommodations Business of Oil States International, Inc., as applicable
(131,832
)
 
(105,713
)
 
(96,388
)
 
(131,759
)
 
(189,043
)
Diluted loss per share attributable to Civeo or the Accommodations Business of Oil States International, Inc., as applicable (1)
$
(0.84
)
 
$
(0.82
)
 
$
(0.90
)
 
$
(1.24
)
 
$
(1.77
)

 
As of December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(In thousands, except per share data)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Total assets
$
1,001,677

 
$
853,912

 
$
910,446

 
$
1,066,529

 
$
1,829,161

Long-term debt
342,908

 
277,990

 
337,800

 
379,416

 
755,625

Total Civeo shareholders’ equity
535,424

 
476,250

 
475,467

 
563,245

 
858,001

Cash dividends per share

 

 

 

 
0.26

                           
(1)
On May 30, 2014, 106,538,044 shares of our common stock were distributed to Oil States stockholders in connection with the spin-off. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding in our diluted net income (loss) per share calculation, we have assumed these shares were outstanding as of the beginning of 2014 in the calculation of weighted-average shares. In addition, we have assumed the dilutive securities outstanding at May 30, 2014 were outstanding for the period from January 1, 2014 through May 30, 2014.


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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.
 
Description of the Business
 
We are a hospitality company servicing 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 group 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 operate in some of the world’s most active oil, coal and iron ore producing regions, and our customers include major and independent oil companies, mining companies and oilfield and mining service companies. We operate in three principal reportable business segments – Canada, Australia and U.S.
 
Noralta Acquisition
 
On April 2, 2018, we completed our previously announced acquisition of Noralta Lodge Ltd. (Noralta), which we refer to herein as the Noralta Acquisition. The consideration for the acquisition totaled (i) C$207.7 million (or approximately US$161.1 million) in cash, subject to customary post-closing adjustments for working capital, indebtedness and transaction expenses; (ii) 32.8 million of our common shares, and (iii) 9,679 shares of our Class A Series 1 Preferred Shares with an initial liquidation preference of US$96.79 million and initially convertible into 29.3 million of our common shares. We funded the cash consideration with cash on hand and borrowings under the Amended Credit Agreement. Please see Note 7 – Acquisitions to the notes to the consolidated financial statements included in Item 8 of this annual report for further information.

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 report to “dollars” or “$” are to U.S. dollars.
 
Macroeconomic Environment
 
We provide hospitality services to the natural resources industry in Canada, Australia and the U.S. 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 oil sands and coal mines and associated infrastructure, as well as the exploration for oil and natural gas. Long-term demand for our services has been driven by continued development and expansion of natural resource production and operation of oil sands and mining facilities. 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 crude oil and met coal.
 
In Canada, WCS crude is the benchmark price for our oil sands customers. Pricing for WCS is driven by several factors, including the underlying price for WTI crude, the availability of transportation infrastructure and recent actions by the Alberta provincial government to limit production in the oil sands. Historically, WCS has traded at a discount to WTI, creating a “WCS Differential,” due to transportation costs and limited capacity 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.

During the first quarter of 2016, global oil prices dropped to their lowest levels in over ten years due to concerns over global oil demand, global crude inventory levels, worldwide economic growth and price cutting by major oil producing

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countries, such as Saudi Arabia. Increasing global supply, including increased U.S. shale oil production, also negatively impacted pricing. Although prices began to increase in 2016 and continued to increase through the third quarter of 2018, oil prices decreased again during the fourth quarter of 2018.

With falling WTI oil prices, WCS also fell. WCS prices in the fourth quarter of 2018 averaged $25.66 per barrel compared to a low of $20.26 in the first quarter of 2016 and a high of $49.93 in the second quarter of 2018. The WCS Differential increased from $26.00 per barrel at the end of the fourth quarter of 2017 to $34.90 at the end of the third quarter 2018. The increase during the first three quarters of 2018 was due to lack of infrastructure, including pipeline and crude-to-rail capacity, to transport oil away from the Canadian oil sands. These bottlenecks caused a significant build up in Canadian oil inventories, which reached record highs in August 2018. On December 2, 2018, the Government of Alberta announced it would mandate temporary curtailments of the Province’s oil production. This curtailment resulted in a narrowing WCS Differential in December 2018, which ended the year at $15.75 per barrel, that has continued into the first quarter of 2019. As of February 22, 2019, the WTI price was $57.11 and the WCS price was $44.26, resulting in a WCS Differential of $12.85.
 
There remains a risk that prices for Canadian oil sands crude oil related products could deteriorate for an extended period of time, and the discount between WCS crude prices and WTI crude prices could continue to widen. The depressed price levels through the first quarter of 2016 negatively impacted exploration, development, maintenance and production spending and activity by Canadian operators and, therefore, demand for our hospitality services. Although we have seen an increase in oil prices since late 2016 and throughout 2017 and 2018, we are not expecting significant improvement in customer activity in the near-term, partially due to the volatility in the WCS Differential discussed above. The current outlook for expansionary projects in Canada is primarily related to proposed pipeline and in-situ oil sands projects. However, continued uncertainty and commodity price volatility and regulatory complications could cause our Canadian oil sands and pipeline customers to delay expansionary and maintenance spending and defer additional investments in their oil sands assets. Additionally, if oil prices continue to decline, the resulting impact could negatively affect the value of our long-lived assets, including goodwill.

Our Sitka Lodge, within our Canadian business, supports the British Columbia LNG market and related pipeline projects. From a macroeconomic standpoint, global LNG imports set a record in 2018, reaching 308 million tonnes per annum, up from 284 million tonnes per annum in 2017, 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. However, on October 1, 2018, LNG Canada (LNGC), a large LNG export project proposed by a joint venture between 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), Korea Gas Corporation (5 percent) and Mitsubishi Corporation (15 percent), announced that a positive final investment decision (FID) had been reached on the proposed Kitimat liquefaction and export facility in Kitimat, British Columbia (Kitimat LNG Facility). With the project moving forward, British Columbia LNG activity and related pipeline projects could become a material driver of future activity for our Sitka Lodge, as well as for our mobile fleet assets, which are well suited for the related pipeline construction activity.

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 West Texas, the Bakken, the mid Continent, and the Rockies.  With the recovery in oil prices through the third quarter of 2018, coupled with ample capital availability for U.S. E&P companies, oil shale drilling and completion activity in the U.S. has significantly increased over the past year.  The U.S. oil rig count has increased from its low of 316 rigs in May 2016 to 1,083 oil and gas rigs active at the end of 2018.  Further, this activity in the U.S. increased oil production from an average of 9.3 million barrels per day in 2017 to an average of 10.8 million barrels per day in 2018. While WTI oil prices fell in the fourth quarter of 2018, there has not been a reduction in the U.S. rig count. As of February 22, 2019, there were 853 active oil rigs in the U.S. (as measured by Bakerhughes.com).  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 Australia, approximately 80% of our rooms are located in the Bowen Basin 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 increased by 4.5% during 2018 compared to 2017.  As of February 22, 2019, met coal spot prices were $210.05 per metric tonne. Current met coal pricing levels have not led our customers to approve many significant new projects.  We expect that customers will look for a period of sustained higher prices before the volume of new projects being approved increases.  Long-term demand for steel is expected to be driven by increased steel consumption per capita in developing

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economies, such as China and India, whose current consumption per capita is a fraction of developed countries. Our customers continue to actively implement cost, productivity and efficiency measures to further drive down their cost base.

Recent WTI crude, WCS crude and met coal pricing trends are as follows:
 
 
 
Average Price (1)
 
 
WTI
 
WCS
 
Hard 
Quarter
 
Crude
 
Crude
 
Coking Coal (Met Coal)
ended
 
(per bbl)
 
(per bbl)
 
(per tonne)
First Quarter through 2/22/2019
 
$
52.81

 
$
42.52

 
221.00

12/31/2018
 
59.32

 
25.66

 
187.00

9/30/2018
 
69.61

 
41.58

 
196.00

6/30/2018
 
67.97

 
49.93

 
196.00

3/31/2018
 
62.89

 
37.09

 
235.00

12/31/2017
 
55.28

 
38.65

 
192.00

9/30/2017
 
48.16

 
37.72

 
170.00

6/30/2017
 
48.11

 
38.20

 
193.50

3/31/2017
 
51.70

 
38.09

 
285.00

12/31/2016
 
49.16

 
34.34

 
200.00

9/30/2016
 
44.88

 
30.67

 
92.50

6/30/2016
 
45.53

 
32.84

 
84.00

3/31/2016
 
33.41

 
20.26

 
81.00

12/31/2015
 
42.02

 
27.82

 
89.00

_________
(1)
Source: WTI crude prices are from U.S. Energy Information Administration (EIA), and WCS crude prices and Seaborne hard coking coal contract prices are from Bloomberg.

Overview
 
As noted above, demand for our hospitality services is primarily tied to the outlook for crude oil and met coal prices. 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.
 
Our business is predominantly located in northern Alberta, Canada and Queensland, Australia, and we derive most of our business from natural resource companies who are developing and producing oil sands and met coal resources and, to a lesser extent, other hydrocarbon and mineral resources. More than 80% of our revenue is generated by our lodges and villages. 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-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 customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives ranging from ten years to in excess of 30 years. Consequently, these investments are dependent on those customers’ long-term views of commodity demand and prices.
 
During the period of low crude oil prices that extended through the first quarter of 2016, many of our customers in Canada curtailed their operations and spending, and most major oil sands mining operators began reducing their costs and limiting capital spending, thereby limiting the demand for hospitality services of the kind we provide.
 
In the last several years, however, several catalysts have emerged that we believe could have favorable intermediate to long-term implications for our core end markets. Since the announcement by OPEC in late November 2016 to cut production quotas and the subsequent rise in spot oil prices and future oil price expectations, certain operators with steam-assisted gravity drainage operations in the Canadian oil sands increased capital spending in 2017. Despite construction at the Fort Hill Energy LP project ending in early 2018, Canadian oil sands capital spending in 2018 has been relatively flat, in the aggregate. OPEC announced additional production cuts in late 2018 in an effort to further support global oil prices. Also on December 2, 2018, the Government of Alberta announced it would mandate temporary curtailments of the province’s oil production, which has

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helped increase WCS prices. Recent regulatory approvals of several major pipeline projects have the potential to both drive incremental demand for mobile accommodations assets and to improve take-away capacity for Canadian oil sands producers over the longer term. However, these projects have been 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 recently acquired Kinder Morgan’s Trans Mountain Pipeline, emphasizing their support for this particular project. Additionally, we believe that the Keystone XL pipeline in the U.S., if constructed, would be a positive catalyst for Canadian oil sands producers, as it would bolster confidence in future take-away capacity from the region to U.S. Gulf Coast refineries.

In Australia, approximately 80% of our rooms are located in the Bowen Basin and primarily serve met coal mines in that region, where our customers continue to implement operational efficiency measures, in order to drive down their cost base. 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.

While we believe that these macroeconomic developments are positive for our customers and for the underlying demand for our hospitality services, we do not expect an immediate improvement in our 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 and integrating the recently acquired Noralta assets into our business.
 
We began the expansion of our room count in Kitimat, British Columbia during the second half of 2015 to support potential LNG projects on the west coast of British Columbia. We were awarded a contract with LNGC for the provision of open lodge rooms and associated services that ran through October 2017. To support this contract, we developed a new accommodations facility, Sitka Lodge, which includes private washrooms, recreational facilities and other amenities. This lodge currently has 646 rooms, with the potential to expand to serve future accommodations demand in the region.
 
As previously discussed, on October 1, 2018, LNGC's participants announced a positive FID on the Kitimat LNG Facility. With the project moving forward, British Columbia LNG activity and related pipeline projects could become a material driver of future activity for our Sitka Lodge, as well as for our mobile camp assets, which are well suited for the related pipeline construction activity. We previously announced contract awards totaling C$100 million in revenues to supply mobile accommodations for four locations along the CGL pipeline project in British Columbia, Canada. This pipeline would provide the natural gas for the Kitimat LNG Facility. We expect to deploy approximately C$10 million in capital, primarily in 2019, across all four locations. We expect to begin recognizing revenue from these contracts beginning in 2019. In addition, in the fourth quarter of 2018, we were awarded room commitments from LNGC, CGL and LNGC’s engineering, procurement and construction firm to provide rooms and services from Sitka Lodge. The award covers expected room needs over an initial 18 month time period with a minimum room commitment and options for extension of up to 36 months. We began recognizing revenue from this award beginning in November 2018. Expected revenues for the room commitments are estimated to be approximately C$70 million over the initial 18 months. 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. We expect to spend approximately C$15 million in capital to expand the Sitka Lodge to 1,100 rooms.

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 in Canada and Australia. These revenues and profits 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,
 
2018
 
2017
 
Change
 
Percentage
Average Canadian dollar to U.S. dollar
$0.77
 
$0.77
 
 
0.1%
Average Australian dollar to U.S. dollar
$0.75
 
$0.77
 
(0.02)
 
(2.5)%

 
As of December 31,
 
2018
 
2017
 
Change
 
Percentage
Canadian dollar to U.S. dollar
$0.73
 
$0.80
 
(0.07)
 
(8.8)%
Australian dollar to U.S. dollar
$0.70
 
$0.78
 
(0.08)
 
(10.3)%
 
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.

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We continue to monitor the global economy, the demand for crude oil and met coal and the resultant impact on the capital spending plans of our customers in order to plan our business activities. We currently expect that our 2019 capital expenditures, exclusive of any business acquisitions, will total approximately $40.0 million to $45.0 million, compared to 2018 capital expenditures of $17.1 million. Please see “Liquidity and Capital Resources below for further discussion of 2019 and 2018 capital expenditures.

Results of Operations
 
Unless otherwise indicated, discussion of results for the years ended December 31, 2018 and 2017 is based on a comparison with the corresponding period of 2017 and 2016, respectively.
 
Results of Operations – Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
 
 
Year Ended
December 31,
 
2018
 
2017
 
Change
 
 
 
 
 
 
 
($ in thousands)
Revenues
 
 
 
 
 
Canada
$
296,012

 
$
245,595

 
$
50,417

Australia
119,238

 
111,221

 
8,017

United States
51,442

 
25,460

 
25,982

Total revenues
466,692

 
382,276

 
84,416

Costs and expenses
 
 
 
 
 
Cost of sales and services
 

 
 

 
 

Canada
225,225

 
171,677

 
53,548

Australia
61,068

 
55,722

 
5,346

United States
44,089

 
29,859

 
14,230

Total cost of sales and services
330,382

 
257,258

 
73,124

Selling, general and administrative expenses
69,068

 
63,431

 
5,637

Depreciation and amortization expense
125,846

 
126,443

 
(597
)
Impairment expense
28,661

 
31,604

 
(2,943
)
Other operating expense
790

 
1,511

 
(721
)
Total costs and expenses
554,747

 
480,247

 
74,500

Operating loss
(88,055
)
 
(97,971
)
 
9,916

 
 
 
 
 
 
Interest expense and income, net
(26,780
)
 
(22,081
)
 
(4,699
)
Other income
1,623

 
1,308

 
315

Loss before income taxes
(113,212
)
 
(118,744
)
 
5,532

Income tax benefit
31,365

 
13,490

 
17,875

Net loss
(81,847
)
 
(105,254
)
 
23,407

Less: Net income attributable to noncontrolling interest
396

 
459

 
(63
)
Net loss attributable to Civeo Corporation
(82,243
)
 
(105,713
)
 
23,470

Dividends attributable to preferred shares
49,589

 

 
49,589

Net loss attributable to Civeo common shareholders
$
(131,832
)
 
$
(105,713
)
 
$
(26,119
)
 
We reported net loss attributable to Civeo for the year ended December 31, 2018 of $131.8 million, or $0.84 per diluted share. As further discussed below, net loss included (i) a $28.7 million pre-tax loss ($20.9 million after-tax, or $0.13 per diluted share) resulting from the impairment of fixed assets included in Impairment expense, (ii) costs totaling $9.1 million ($8.0 million after-tax, or $0.05 per diluted share) incurred in connection with the Noralta Acquisition, and are included in Costs of sales and services ($1.0 million), Selling, general and administrative (SG&A) expense ($7.2 million) and Other income ($0.9 million) below, and (iii) $49.6 million of dividends attributable to the preferred shares issued in the Noralta Acquisition.

We reported net loss attributable to Civeo for the year ended December 31, 2017 of $105.7 million, or $0.82 per diluted share. As further discussed below, net loss included (i) a $31.6 million pre-tax loss ($23.1 million after-tax, or $0.18 per diluted share) resulting from the impairment of fixed assets included in Impairment expense below; and (ii) a $2.3 million pre-tax loss ($2.2 million after-tax, or $0.02 per diluted share) from costs incurred in connection with the Noralta Acquisition, included in SG&A expense below.

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Revenues. Consolidated revenues increased $84.4 million, or 22%, in 2018 compared to 2017. This increase was largely driven by increases in Canada due to the Noralta Acquisition in the second quarter of 2018 and increased mobile facility rental revenue in 2018 compared to 2017. Additionally, higher activity levels in certain markets in Australia and the U.S. contributed to increased revenues, partially offset by a weaker Australian dollar relative to the U.S. dollar in 2018 compared to 2017. Please see the discussion of segment results of operations below for further information.
 
Cost of Sales and Services. Our consolidated cost of sales increased $73.1 million, or 28%, in 2018 compared to 2017, primarily due to increases in Canada due to the Noralta Acquisition in the second quarter of 2018 and increased mobile facility rental activity; in Australia due to higher occupancy levels in certain markets; and the U.S. due to higher activity levels. Additionally, a weaker Australian dollar relative to the U.S. dollar in 2018 compared to 2017 contributed to decreased cost of sales and services. Please see the discussion of segment results of operations below for further information.
 
Selling, General and Administrative Expenses. SG&A expense increased $5.6 million, or 9%, in 2018 compared to 2017. This increase was primarily due to costs incurred in connection with the Noralta Acquisition and higher personnel costs primarily associated with increased compensation. These items were partially offset by lower incentive compensation costs.
 
Depreciation and Amortization Expense. Depreciation and amortization expense decreased $0.6 million, or 0%, in 2018 compared to 2017 primarily due to reduced depreciation expense resulting from impairments recorded in 2017 and certain assets becoming fully depreciated during 2017, partially offset by additional property, plant and equipment acquired through recent acquisitions as well as incremental intangible amortization expense related to our acquisitions.
 
Impairment Expense. We recorded pre-tax impairment expense of $28.7 million in 2018 associated with long-lived assets in our Canadian segment.

Impairment expense of $31.6 million in 2017 consisted of:

Pre-tax impairment losses of $27.2 million related to certain lodge assets in the southern oil sands in our Canadian segment; and
Pre-tax impairment losses of $4.4 million related to leasehold improvements and undeveloped land positions in our Canadian segment. 
Please 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. Consolidated operating loss decreased $9.9 million, or 10%, in 2018 compared to 2017 primarily due to increased activity levels in certain Australian and U.S. markets, partially offset by higher SG&A expense and lower margins in Canada in the 2018 period.

Interest Expense and Interest Income, net. Net interest expense increased by $4.7 million, or 21% in 2018 compared to 2017 primarily related to higher revolving credit facility borrowings to fund the Noralta Acquisition.
 
Income Tax Benefit.  Our income tax benefit for the year ended December 31, 2018 totaled $31.4 million, or 27.7% of pretax loss, compared to a benefit of $13.5 million, or 11.4% of pretax loss, for the year ended December 31, 2017.  Our effective tax rate for the year ended December 31, 2018 was higher than the Canadian statutory rate of 27%, primarily due to the release of a valuation allowance of $4.9 million against the net deferred tax assets in Canada due to Canada no longer being considered a loss jurisdiction. 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 $4.6 million was established against net deferred tax assets in the U.S. and Australia.

Our effective tax rate for the year ended December 31, 2017 was lower than the Canadian statutory rate of 27%, primarily due to losses in the U.S. and Australia for which no tax benefit was recorded. As a result, a valuation allowance of $13.2 million was established against net deferred tax assets in the U.S. and Australia. In addition, a valuation allowance of $5.9 million was established against the net deferred tax assets in Canada.

Dividends Attributable to Preferred Shares.  We recorded dividends attributable to preferred shares of $49.6 million in the year ended December 31, 2018 primarily resulting from a beneficial conversion factor associated with the preferred shares

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issued as part of the Noralta Acquisition. Please see Note 13 – Preferred Shares to the notes to the consolidated financial statements included in Item 8 of this annual report for further discussion.
 
Other Comprehensive Income (Loss). Other comprehensive loss increased $78.1 million in 2018 compared to 2017 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 decreased 9% in 2018 compared to a 7% increase in 2017. The Australian dollar exchange rate compared to the U.S. dollar decreased 10% in 2018 compared to an 8% increase in 2017.

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Segment Results of Operations – Canadian Segment
 
 
Year Ended
December 31,
 
2018
 
2017
 
Change
Revenues ($ in thousands)
 
 
 
 
 
Accommodation revenue (1)
$
266,899

 
$
228,062

 
$
38,837

Mobile facility rental revenue (2)
9,316

 
3,935

 
5,381

Food service and other services revenue (3)
15,601

 
11,891

 
3,710

Manufacturing revenue (4)
4,196

 
1,707

 
2,489

Total revenues
$
296,012

 
$
245,595

 
$
50,417

 
 
 
 
 
 
Cost of sales and services ($ in thousands)
 
 
 
 
 
Accommodation cost
$
180,355

 
$
141,901

 
$
38,454

Mobile facility rental cost
9,985

 
4,200

 
5,785

Food service and other services cost
14,756

 
9,229

 
5,527

Manufacturing cost
4,995

 
4,478

 
517

Indirect other cost
15,134

 
11,869

 
3,265

Total cost of sales and services
$
225,225

 
$
171,677

 
$