Civeo Corp - Annual Report: 2017 (Form 10-K)

PART I

This annual report on Form 10-K 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” below.

In addition, in certain places in this annual report on Form 10-K, 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 on Form 10-K 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, the Company:

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 on Form 10-K. 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). The filings are also available through the Commission at the Commission's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. 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 on Form 10-K.

Redomiciliation to Canada

On July 17, 2015, we changed our place of incorporation from Delaware to British Columbia, Canada, and Civeo Corporation, a British Columbia, Canada limited company formerly named Civeo Canadian Holdings ULC (Civeo Canada), became the publicly traded parent company of the Civeo group of companies (the Redomicile Transaction).

Our Company

We are one of the largest integrated providers of workforce accommodations, logistics and facility management services to the natural resource industry. We operate in some of the world’s most active oil, coal and iron ore producing regions, including Canada, Australia and the U.S. We have established a leadership position in providing a fully integrated service offering to our customers, which include major and independent oil companies, mining companies and oilfield and mining service companies. 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.

Our Develop, Own and Operate model allows our customers to focus their efforts and resources on their core development and production operations.

Using our Develop, Own and Operate business model, we provide accommodations solutions 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 accommodations for a limited number of employees for an uncertain duration of time. Our fleet of temporary 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 temporary accommodation assets, particularly for shorter term projects such as pipeline construction and seasonal drilling programs, or our open camp model or our scalable lodge or village model. As projects grow and headcount needs increase, we are able to scale our facility size to meet our customers’ growing needs. By providing infrastructure early in the project lifecycle, we are well positioned to continue to service our customers throughout the production phase, which typically lasts decades.

The initial component of our Develop, Own and Operate business model is site selection and permitting. We believe there are benefits created by investing early in land in order to gain the strategic, early-mover advantage in an emerging region or resource play. Our business development team actively assesses regions of potential future customer demand and pursues land acquisition and permitting, a process we describe as “land banking.” We believe that having the first available accommodations solution in a new market allows us to win contracts from customers and gives us an early-mover advantage, as competitors may be less willing to invest in undeveloped land in the expectation of future demand without firm customer commitments. The strength of our land banked locations allowed us to secure contract growth in our most recent Canadian lodge locations, McClelland Lake in the Canadian oil sands region and our Sitka Lodge in the British Columbia liquefied natural gas (LNG) market.

Our scalable modular facilities provide workforce accommodations where, in many cases, traditional accommodations and related infrastructure is not accessible, sufficient or cost effective. Our services help facilitate efficient development and production of natural resources found in areas without sufficient housing, infrastructure or local labor. We believe that many of the more recently discovered mineral deposits and hydrocarbon reservoirs are in remote locations. We support the development of these natural resources by providing lodging, catering and food services, housekeeping, recreation facilities, laundry services and facilities management, as well as water and wastewater treatment, power generation, communications and personnel logistics where required. Our accommodations services allow our customers 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 accommodations to leading natural resource companies at our major properties, which we refer to as lodges in Canada and villages in Australia. We have nineteen lodges and villages with an aggregate of more than 24,000 rooms. Additionally, in the U.S. and Canada we have seven smaller open camp properties, as well as 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 November 26, 2017, we entered into a Share Purchase Agreement (the Purchase Agreement) to acquire Noralta.  This acquisition (the Noralta Acquisition), which we expect to close in the second quarter 2018, will increase our capacity in Canada by 11 lodges, with over 5,700 owned rooms and 7,900 total rooms.  Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this annual report for additional information regarding the Noralta Acquisition.

Demand for our accommodations and related services is influenced by four primary factors: commodity prices, available infrastructure, workforce requirements and competition. Current commodity prices, and our customers’ expectations for future commodity prices, influence customers’ spending on current productive assets, maintenance on current assets, 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 accommodations. Also, competing locations and services will influence demand for our assets and services.

In the Canadian oil sands region, demand for our accommodations is influenced by oil prices. Spending on construction and the 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 generally customers 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 fall as well.

Another factor that influences demand for our rooms and 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 accommodations. 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 occupancy. Typically, customers prefer to first utilize their own rooms on location, and if such customer-owned rooms are insufficient, customers prefer to avoid busing their workforces to housing more than 45 kilometers away.

A number of multinational energy companies believe there is a potential to export LNG from Canada to meet the increasing global demand, particularly in Asia, for LNG. Currently, Western Canada does not have any operational LNG export facilities. However, as of December 2017, there were 16 proposed LNG export facilities in British Columbia in various stages of feasibility assessment and project planning, although none have reached a positive final investment decision. 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 accommodations 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, while pipeline construction activity will drive demand for mobile fleet accommodations.

Our Australian villages support similar activities for the natural resources industry. Our customers are typically developing and producing metallurgical (met) coal and other mines which have resource lives that are measured in decades. As such, their spending levels tend to react similarly to commodity prices as those 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. During 2011 through 2013, roughly half of our occupancy was driven by construction or expansion activity, while the other half supported operation activities of resource production. Currently, our occupancy is primarily driven by production, maintenance and operating activities. With the reduction in met coal prices from mid-year 2012 to mid-year 2016, much of the demand for rooms from new construction activity has ceased, and our current and expected occupancy is primarily driven by production, maintenance and operational activity. Workforce requirements and competition in the Australian market are comparable to those in 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 workforce accommodations. The rise in met coal prices in the fourth quarter of 2016 and during 2017 has improved market sentiment; however, this price improvement has yet to materially improve customer capital spending. We expect that customers will look for a period of sustained higher prices before we see any significant impact on customer activity levels and the demand for our accommodations.

Our U.S. operations are primarily tied to activity in the U.S. shale formations in the Bakken, the Rockies and West Texas. Given the shorter investment horizon and decision cycle of our U.S. customers, typically on a well-by-well basis, U.S. customers’ spending activities typically react more quickly to changes in oil and natural gas prices. These spending dynamics were clearly demonstrated over the past four 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. The U.S. rig count grew in 2017 and stabilized by the end of the 2017, finishing the year at 929 rigs. The Permian Basin was the biggest driver, representing 43% of the rigs in the U.S. market. 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.

For the years ended December 31, 2017, 2016 and 2015, we generated $382.3 million, $397.2 million and $518.0 million in revenues and $98.0 million, $95.8 million and $145.0 million in operating loss, respectively. The majority of our operations, assets and income are derived from lodge and village facilities that have historically been contracted by our customers on a take-or-pay basis for periods ranging from several months to several years. These facilities generate more than 75% of our revenue. Important performance metrics include average available rooms, average rentable rooms, revenue related to our major properties, occupancy and average daily rate (in local currency). “Mobile and Open Camp Revenue,” shown below, consists of our revenue related to our open camp facilities and mobile camps, as well as third party sales related to our manufacturing division. The table below summarizes these key statistics for the periods presented in this Annual Report on Form 10-K.

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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. Over the next decade, the business acquired a catering operation and a manufacturing facility, enabling it to provide a more integrated service offering. 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 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.

With an integrated business model, 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 integrated model, our accommodation 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 oil sands region, with our Beaver River Executive Lodge in 2005. Since then, we have continued to innovate our service offering to meet our customers’ growing and evolving needs. From that entrepreneurial beginning, we have developed into Canada’s largest third-party provider of accommodations in the oil sands region.

Today, in addition to providing accommodations services, we endeavor to 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 latest lodge location, Sitka Lodge. Most of the Sitka Lodge’s 436 rooms were under contract through October 2017 to LNG Canada (LNGC), a large LNG export project proposed by a joint venture between Shell Canada Energy, an affiliate of Royal Dutch Shell plc (50 percent), and affiliates of PetroChina (20 percent), Korea Gas Corporation (15 percent) and Mitsubishi Corporation (15 percent). In addition, in May 2016, we were awarded a contract with LNGC to construct a 4,500 person workforce accommodation center (Cedar Valley Lodge) for a proposed liquefaction and export facility in Kitimat, British Columbia. Construction of Cedar Valley Lodge will not commence until LNGC’s joint venture participants have made a positive final investment decision (FID). The FID was originally planned for the end of 2016. However, FID has been delayed. Recent public statements by LNGC and news reports indicate that FID for LNGC is expected in the second half of 2018. Should the project ultimately move forward, LNGC activity 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. However, there can be no assurance that LNGC’s joint venture participants will reach a positive FID or that our contracts with LNGC will be extended. Further, on July 25, 2017, Petronas and its partners announced the cancellation of their Pacific NorthWest (“PNW”) liquefied natural gas project they had planned to build in Port Edward, British Columbia. If the LNGC project, and other potential projects in the area, do not move forward, our future results of operations and our existing long-lived assets in Canada, including our Sitka Lodge, may be negatively affected, and we may be required to record material impairment charges equal to the excess of the carrying values of these assets over their fair values. As of December 31, 2017, the net book value of long-lived assets that are currently supporting, or could be used to support, potential LNG projects in British Columbia was approximately $80 million.

With the acquisition of our Australian business in December 2010, we began to support the Australian natural resources industry through villages located in Queensland, New South Wales and Western Australia. Like Canada, our Australian business has a long-history of accommodating customers in remote regions, beginning with its initial Moranbah Village in 1996, and has grown to become Australia’s largest integrated provider of accommodations 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 continual service improvement to enhance the guest experience and reduce customer remote 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 services for the oil and gas and mining industries. Our scalable modular facilities provide long-term and temporary work force 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 catering and food services, housekeeping, laundry, facility management, water and wastewater treatment, power generation, communications and personnel logistics. 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 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 natural resources production in Australia and oil and gas 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 accommodations are non-core investments for their business.

Civeo is one of the few accommodations providers that service the entire value chain from site identification to long-term facility management. We believe that our existing industry divides accommodations into three primary types: lodges and villages, open camps and mobile assets. Civeo is principally focused on 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 built 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. Open camps are usually smaller in number of rooms and typically serve customers on a spot or short-term basis. They are “open” for any customer who needs lodging services. Finally, 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. Open camps may best serve smaller operations or the needs of customers as they expand in a region. These open camps can also serve as an initial, small foothold in a region until the demand for a full-scale lodge or village is required.

The accommodations market is segmented into competitors that serve components of the overall value chain, but has very few integrated providers. 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 open camp and mobile fleet business. Facility service companies, such as Aramark Corporation (Aramark), Sodexo Inc. (Sodexo) or Compass Group PLC (Compass Group), typically do not invest in and own the accommodations assets, but will manage third-party or customer-owned facilities. We believe the integrated model provides value to our customers by reducing project timing and counterparty risks. In addition, with our holistic approach to accommodations, we are able to identify efficiency opportunities for the customers and execute them. With our focus on large-scale lodges and villages, our business model is most similar to a developer of multi-family properties, such as Camden Property Trust, AvalonBay Communities, Mid-America Apartment Communities, or a developer of lodging properties who is also an owner operator, such as Hyatt Hotels Corporation or Marriott International, Inc.

Canada

Overview

During the year ended December 31, 2017, we generated approximately 64% of our revenue from our Canadian operations.  We are Canada’s largest integrated provider of accommodations services for people working in remote locations.  We provide our accommodation services through lodges, open camps and mobile assets. Our accommodations 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 oil sands accommodations is primarily influenced by the longer-term outlook for crude oil prices rather than current energy prices, given the multi-year production phase of Canadian oil sands projects and the costs associated with development of such large scale projects.  Utilization of our existing Canadian capacity and our future 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 36 million residents, nearly half of the population lives in ten cities, while only approximately 10% of the population lives in Alberta and less than 1% of the population lives within 100 kilometers of the oil sands. 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, 2017, 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, Athabasca, Henday and Beaver River 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 and Anzac lodges, as well as a portion of our mobile fleet of 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 to 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.   All of our oil sands lodge properties are located on land with leases obtained from the province of Alberta with initial terms of ten years. Our leases have expiration dates that range from 2023 to 2027. Currently, none of our Canadian lodge rooms are on land with leases expiring prior to December 31, 2018. In recent years, we have successfully renewed or extended all expiring land leases, with the exception of one lease on private land in 2014, and expect we will be able to in the future.

We provide a full service hospitality function at our lodges, including reservation management, check in and check out, catering, housekeeping and facilities management. Our lodge guests receive the amenity level of a full-service hotel plus three meals a day.  During 2017, no further rooms were added (net of retirements) to our major oil sands lodges.  Our Wapasu Creek Lodge is equivalent in size to the largest hotels in North America.

During the year ended December 31, 2017, over 85% of our Canadian revenue was generated by our eight major lodges. We provide our lodge services 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 LNG Lodge

During the fourth quarter of 2015, in Kitimat, British Columbia, we built 436 rooms during the initial development of our Sitka Lodge. Most of these rooms were under contract through October 2017 to LNG Canada, a large LNG export project proposed by a joint venture between Shell Canada Energy, an affiliate of Royal Dutch Shell plc (50 percent), and affiliates of PetroChina (20 percent), Korea Gas Corporation (15 percent) and Mitsubishi Corporation (15 percent). The initial phase of this location features catering services and recreational facilities and the ability to expand should demand for rooms in the region warrant.

In addition, we were awarded a contract with LNGC to construct a 4,500 person workforce accommodation center (Cedar Valley Lodge) for a proposed liquefaction and export facility in Kitimat, British Columbia. Construction of Cedar Valley Lodge will not commence until LNGC’s joint venture participants have made a positive FID. The FID was originally planned for the end of 2016. However, FID has been delayed. Recent public statements by LNGC and news reports indicate that FID for LNGC is expected in the second half of 2018. There can be no assurance that LNGC’s joint venture participants will reach a positive FID or that our contracts with LNGC will be extended.

Canadian Lodge Locations

Rooms in our Canadian Lodges

Open Camps

In addition to our lodges, we have five open camps in Alberta, British Columbia, Saskatchewan and Manitoba. The major differentiator between lodges and open camps is the size of the facility. Open camps are generally smaller facilities that provide a level of amenity similar to that of one of our larger lodges, including quality accommodation and food services, satellite television, fitness facilities and on-site laundry. We own the land where all of our open camp assets are located, with the exception of Geetla Lodge, which is on leased land. In the fourth quarter of 2017, we demobilized our Pebble Beach open camp for a mobile camp opportunity servicing a pipeline construction project. These assets will be included in our mobile camp assets going forward. Open camps are typically utilized for exploratory, seasonal or short-term projects. Therefore, customer commitments for open camps tend to be shorter in initial duration (six to 18 months). Open camps may be operational for 12 months or several years or transition into lodges depending on customer demand. Over time, room counts may fluctuate up or down depending on demand in the region. If the demand in a region decreases, open camp assets can be relocated to areas of greater activity. We provide accommodation services at our open camps on a day rate basis. Open camp revenue comprises a portion of “Other Revenue” in our Canadian segment.

Our Alberta open camps service the Athabasca and Peace River oil sands, as well as conventional and shale play oil and gas developments and infrastructure expansions. Geetla Lodge services the Horn River Basin in British Columbia.

Rooms in our Canadian Open Camps

Catering and Facilities Management

We have experience in the management of third-party facilities. Historically, this has been primarily focused around resource production related housing facilities that are owned by producers. Currently, we operate camp facilities for third-party customers. The facilities we manage range anywhere from 200 to 3,000 rooms. We are able to customize our service offering depending on our client’s needs. Facilities management services can be performed on an end-to-end basis with catering, maintenance and utility services included or in segments such as catering only.

Recently, we have engaged in developing a non-energy related catering brand. This diversification initiative targets catering and facility management opportunities outside of the energy sector, including educational, entertainment, healthcare and traditional catering events. Currently, we operate three non-energy facilities, and we are constructing a food production facility, which will begin operations in early 2018.

Canadian Mobile Camps

Our mobile camps consists 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 catering 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.

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 catering 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 ancillary service contracts has allowed us to successfully pursue catering 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. Mobile camp revenue comprises a portion of “Other Revenue” in our Canadian segment.

Australia

Overview

During the year ended December 31, 2017, we generated 29% of our revenue from our Australian operations.  As of December 31, 2017, we had 9,346 rooms across ten villages, of which 7,392 rooms service the Bowen Basin region of Queensland, one of the premier metallurgical (met) coal basins in the world. We provide accommodation services on a day rate basis to mining and related service companies (including construction contractors), typically under medium-term contracts (three to five years) with minimum nightly room commitments. During 2017, 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 sector 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. Approximately 60% of the Australian population is located in five cities, which are all located on the coast of Australia, and over 90% of the population lives in the southern half of the country. Sufficient local labor is lacking near the major natural resources developments, which are primarily inland and in the central and northern parts 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 to support resource production in the country. Workforce accommodations have historically been built by the resource developer/owner, typical of an insourcing business model.

Since 1996, our Australian business has sought to change the insourcing business model through its integrated service offering, allowing customers to outsource their accommodations needs and focus their investments on resource production operations. Our Australian accommodations villages are strategically located in proximity to long-lived, low-cost mines operated by investment-grade, international mining companies.  The current activities of our Australian segment are primarily related to supplying accommodations in support of met coal mining in the Bowen Basin region of Queensland.

During the year ended December 31, 2017, 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, has slowed significantly, negatively impacting demand for the commodity. However, during 2017 demand from China for steel increased leading to improved pricing for met coal. 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 emerging markets with four additional villages. At the end of 2017, we had two villages with over 1,000 combined rooms in the Gunnedah Basin, an emerging thermal and met coal as well as coal seam gas region of New South Wales. In Western Australia, we serve workforces related to LNG facilities operations on the Northwest Shelf through our Karratha village.

Australian Village Locations

 

Rooms in our Australian Villages

(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. Please see Note 3 - 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, 2017 and has a significant development portfolio in Australia.  Our Australian business provides accommodation services to mining and related service companies under short- and medium-term contracts.  Our Australian accommodations villages are strategically located near long-lived, low-cost mines operated by large mining companies.   Our growth plan for this part of our business continues to include the expansion of these properties where we believe there is durable long-term demand.

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 accommodation 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.

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, 2017, our U.S. business generated 7% of our revenue. Our U.S. business has operational exposure to the Rocky Mountain corridor, the Bakken Shale region, the Permian Basin region of Texas and offshore locations in the Gulf of Mexico. The business provides open camp facilities 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.

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 has developed in the U.S. over the past several years. Demand for accommodations in the U.S. has historically been tied to the level of oil and natural gas exploration and production activity, which is primarily driven by oil and natural gas prices. Activity levels have been, and we expect will continue to be, highly correlated with hydrocarbon commodity prices.

U.S. Locations

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 Permian Basin region of Texas, and in the Gulf of Mexico. We provide a variety of sizes and configurations to meet the needs of drilling contractors, completion companies, infrastructure construction projects and offshore drilling and completion activity. We provide quality catering and housekeeping services as well.

Our mobile fleet is rented on a per unit basis based on the number of days that a customer utilizes the asset. In cases where we provide catering 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.

Open Camps

We had two open camps in the U.S. comprised of 561 rooms as of December 31, 2017. We sold our Three Rivers location in January 2016 and closed the Stanley House location in March 2016. Our Killdeer Lodge, which we opened in October 2013, provides accommodations support to the Bakken Shale region in North Dakota. Our West Permian Lodge supports the Permian Basin in West Texas.

Modular Construction and Manufacturing

Our Canadian segment includes the design, engineering, production, transportation and installation of a variety of modular buildings, predominately for our own use. As of December 31, 2017, 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.

While we traditionally focused our manufacturing efforts on our internal needs, from time to time we have sold units to third parties. Revenues from the sale of accommodation units to third parties has been a small portion of our revenue and is included in “Other Revenue” in our Canadian and U.S. segments. We have not historically sold units to third parties in Australia.

Community Relations

With a focus on long-term indigenous community participation, our Canadian operations continue to work closely with local indigenous communities to develop mutually beneficial and long-term partnerships focused on employment, training, business development and community investments.  For over a decade, our Canadian operations have supported Buffalo Metis Catering, a partnership with three Metis communities in the Regional Municipality of Wood Buffalo, to provide catering and housekeeping at three of our lodges.  Our Canadian operations continue to utilize local indigenous subcontractors to provide other services such as water hauling, snow removal and security. Our indigenous strategic initiatives were recognized in 2011 and 2012 from the Alberta Chamber of Commerce industry awards in recognition for excellence in indigenous relations business practices.  In addition, we were awarded a silver level PAR Certification by the Canada Council for Aboriginal Business in 2016. During 2017, Civeo entered into three new indigenous partnerships in the oil sands region, as well as pipeline expansion projects as it related to our priority growth strategy. During the same period, we continued to work with two other indigenous communities as it relates to LNGC on the west coast of British Columbia and the north Montney region in north east British Columbia. Beyond revenue sharing, these new arrangements provide employment, training and ancillary business opportunities for indigenous owned businesses. In addition, Civeo was recognized in 2017 by Indigenous Works (formerly known as the Aboriginal Human Resource Council), as an industry leader that is focused on strengthening the company's performance and results in indigenous employment, workplace engagement and inclusion.

In Australia, our community relations program also aims to build and maintain a positive social license to operate in regional communities by delivering consultation and engagement 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 2017 were Imperial Oil Limited (a company controlled by ExxonMobil Corporation) and Fort Hills Energy LP (a partnership between Suncor Energy Inc., Total E&P Canada Ltd and Teck Resources Limited), who each accounted for more than 10% of our 2017 revenues.

Our primary competitors in Canada in the open and mobile camp accommodations include ATCO, Black Diamond, Horizon North, Noralta 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 facility management services.

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

In the U.S., we primarily offer our open camp and mobile camps accommodations and compete against Stallion Oilfield Holdings, Inc., Target Logistics Management LLC (a subsidiary of Algeco Scotsman Global S.a.r.l.), 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, 2017, revenues from our lodges and villages represented over 85% of our consolidated revenues. Our customers typically contract for accommodations services under take-or-pay 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 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 the contract, the customer commits to a minimum number of rooms over a determined period. 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, 2017, we had commitments for 30% of our rentable rooms for 2018 and 15% of our rentable rooms for 2019.

As of December 31, 2017, we had 7,034 rooms under contract, or 41% of our rentable rooms. The table below details the expiration of those contracts:

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. 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, 2017, we had approximately 1,700 full-time employees on a consolidated basis, 72% of whom are located in Canada, 20% of whom are located in Australia and 8% of whom are located in the U.S.  We were party to collective bargaining agreements covering approximately 850 employees located in Canada and 130 employees located in Australia as of December 31, 2017.

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:

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

Our operations and the operations of our customers are subject to numerous stringent and comprehensive foreign, federal, provincial, state and local environmental laws and regulations governing the release or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly yet critical. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, modification or cessation of operations, assessment of administrative and civil penalties, and even criminal prosecution. 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 2017 that may affect us or our customers.

Federal Regulatory Reforms

In 2017 the Government of Canada initiated a series of reviews to consider significant changes to Canada's federal environmental assessment regime, the federal Fisheries Act, the protection of navigable waters, and the legislation governing the approval, construction and operation of interprovincial pipelines. The four parallel review processes culminated in reports from four separate review panels which resulted in the Government of Canada publishing a discussion paper summarizing proposed changes to the relevant legislative frameworks. The Government of Canada has been engaging with potentially affected stakeholders since July 2017 and new legislation implementing changes to the relevant legislation is expected in 2018. If implemented, the direct and indirect costs of these proposed regulatory changes may adversely affect our operations and financial results as well as those of our customers.

Federal Climate Change Regulation

Scientific studies have suggested that emissions of greenhouse gases (GHG), including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In December 2015, 195 nations, including Canada, Australia, and the U.S., adopted the Paris Agreement at the 21st “Conference of the Parties” (COP 21). The Paris Agreement does not set legally binding emission reduction targets but does set a goal of limiting global temperature increases to less than 2° Celsius. Canada announced that it is in favor of the decision of the COP 21 to endeavor to take action to further limit global temperature increases to less than 1.5° Celsius. The Paris Agreement also requires parties to submit Intended Nationally Determined Contributions (INDCs) which set out their emission reduction targets and to renew these INDCs, with the goal of increasing the reductions, every five years. Canada's INDC was to reduce economy-wide GHG emissions by 30% below 2005 levels by 2030. 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 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 and stated that draft regulations to implement that commitment would be published in early 2017. In May 2017, Canada released the proposed Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (Proposed Regulations). The Proposed Regulations would apply to facilities that have the potential to emit hydrocarbons above a 60,000 m³ per year threshold and to certain other covered facilities. The Proposed Regulations would require those facilities to conserve or destroy (e.g. through flaring) methane and to implement leak detection and repair programs by 2020. If implemented, the new regulatory requirements would be phased in between 2020 and 2023 and may result in additional costs or liabilities for our customers' operations.

In March 2016, as a further effort to meet Canada’s INDCs, representatives of the federal and 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. The federally established carbon price will serve as a "backstop" in any province that does not establish an equivalent framework by 2018. Federal regulations implementing the carbon price are expected to be released in 2018. If the federal carbon pricing framework is implemented as planned, these regulatory changes may increase costs to us and our customers.

To ensure that it meets its INDC commitments under the Paris Agreement, the Canadian federal government may elect to impose further regulation on GHG emissions and may wish to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs. This may result in increased costs to us and our customers.

Provincial Climate Change Regulation

Climate change regulation can also take place at the provincial level. For example, in 2015 Alberta announced a new Climate Leadership Plan (CLP). The policies set out in the CLP contemplate changes to the regulation of GHG emissions both from large industrial emitters and consumer use of fossil fuels. To implement the CLP, Alberta published the Carbon Competitiveness Incentive Regulation in 2017, which replaces the Specified Gas Emitters Regulation under the Climate Change and Emissions Management Act. The Carbon Competitiveness Incentive Regulation provides a framework for managing GHG emissions from facilities that emit over 100,000 tonnes of carbon dioxide equivalent (CO2e) per year as well as other facilities which opt in to the regulation by establishing industry-specific output-based emissions allocations and requiring that those facilities ensure their net emissions do not exceed the established output based allocation. Companies can reduce their net emissions either through outperforming their output based allocation in a given reporting period, through the purchase of "fund credits" from the  Climate Change and Emissions Management Fund, or other approved credits. Each fund credit reduces a facility's net emissions by one tonne of CO2e. The price of a "fund credit" effectively sets the price of GHG emissions for heavy industrial emitters in Alberta. Effective January 1, 2018, the price of a fund credit is $30. These changes to the regulation of GHG emissions may significantly increase the cost of compliance for some of our customers.

The 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. Alberta's carbon levy was set at $20 per tonne in 2017 and increased to $30 per tonne effective January 1, 2018. The increase in the carbon levy will add to the cost of most fossil-based fuels and may result in additional costs for us and for our customers.

The CLP also targets a 45 percent reduction in methane emissions from oil and gas operations by 2025. The Alberta Energy Regulator (AER) has been tasked with developing a multifaceted approach to reducing methane emissions from the upstream oil and gas sector that is expected to include enhancements to its existing AER directives, new measurement and reporting requirements, and other regulations for both new and existing facilities. To that end, the AER has established a Methane Reduction Oversight Committee, consisting of representatives from government, environmental organizations, industry and technology groups. Draft Alberta methane reduction regulations are expected in 2018 and are intended to be equivalent to the federal Proposed Regulations described above. If equivalent, the Alberta methane reduction regulations would apply in lieu of the federal Proposed Regulations. Further, as contemplated in the CLP, Alberta passed the Oil Sands Emissions Limit Act in 2016 which caps oil sands GHG 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 announced 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.

The Government of British Columbia implemented a broad-based carbon tax on the purchase and use of most fuels in 2008. British Columbia's carbon tax is currently set at $30 per tonne of CO2e, but will increase by $5 per tonne of CO2e effective April 1, 2018, followed by annual increases of $5 per tonne of CO2e until reaching $50 per tonne of CO2e in 2021. The direct and indirect costs of these carbon price increases may adversely affect our operations and financial results as well as those of our customers.

The Government of Manitoba recently announced its intention to implement a carbon tax as a result of the agreement reached by federal and provincial governments in 2016. The Government of Manitoba is currently consulting on a draft plan for implementing its carbon tax, with draft legislation expected in 2018. To date, the Government of Saskatchewan has indicated that it will not develop a carbon tax, leaving open the possibility that the federal "backstop" carbon pricing framework will apply to the consumption of fossil fuels and to GHG emissions from industrial facilities in Saskatchewan.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as higher sea levels, increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our operations and financial results as well as those of our customers.

Alberta’s Electricity Market

On November 3, 2016, Alberta released the details of its Renewable Electricity Program (REP) which includes a procurement process for renewable generation as part of Alberta’s CLP, which in addition to phasing out coal, includes a commitment to achieve 30 percent renewable generation by 2030. A total of approximately 5,000 megawatts (MW) of renewable generation is expected to be procured. The first procurement process concluded in December 2017. Alberta procured almost 600 MW of wind generation capacity, achieving the lowest price in Canada. Details regarding the next procurement process have not yet been released.

Alberta also announced on November 23, 2016 that it would restructure its electricity market to include a parallel capacity market by 2021. The capacity market is still in the design phase, with the first procurement process set to begin in 2019 and the first contracts to be awarded in 2020/2021.

There is still uncertainty regarding implementing the REP, notwithstanding the low prices achieved in the first auction, and Alberta’s new capacity market, which may increase costs to us and our customers.

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 this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals pending a substantive decision on the merits.  In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate courts.  In January 2018, the Supreme Court ruled that distinct courts have jurisdiction over challenges to the rule.  Litigation surrounding this rule is ongoing, and the EPA has instituted rulemakings to both delay the effective date of the rule and repeal the rule. Many of our U.S. properties and operations require permits for discharges of wastewater and/or storm water, and we have developed a system for securing and maintaining these permits. 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 November 2016, the Bureau of Land Management (BLM) issued new regulations to reduce “waste” of natural gas—of which methane is a primary constituent—from venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian lands. In December 2017, implementation of this rule was delayed until January 2019. 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. 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 by means of 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.  Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service is required to make a determination on listings of more than 250 species as endangered or threatened under the ESA before the end of the agency’s 2017 fiscal year.

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 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. However, 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. While that decision was on appeal, BLM rescinded this rule in December 2017. 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.

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 have seen an increase in oil prices in late 2016 and through 2017, we are not expecting significant improvement in 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 depressed 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. With falling West Texas Intermediate (WTI) oil prices, Western Canadian Select (WCS) also fell. Oil prices and WCS have rebounded in recent periods. WCS prices in the fourth quarter of 2017 averaged $38.65 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.  As of February 16, 2018, the WTI price was $61.68, and the WCS price was $35.05. 

In addition, met coal prices have fluctuated from approximately $119/metric tonne as of December 31, 2014 to approximately $92.50/metric tonne as of September 30, 2016, due to a declining demand for steel and the impact of a stronger U.S. dollar.  Steel demand rebounding in 2017 and the weakening of the U.S. dollar has led to higher met coal pricing.  As of February 19, 2018, spot prices for met coal were $229.25/metric tonne and benchmark contract prices for the first quarter of 2018 paid to Australian metallurgical coal producers by Japanese steel producers had not settled.  The increase in met coal pricing in 2017 and early 2018 have not led our customers to approve any significant new projects. The low commodity price environment has significantly 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:

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 depressed 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 weakness 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 depressed 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.

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 $31.6 million and $46.1 million in 2017 and 2016, respectively. We also recorded goodwill impairments of $43.2 million in 2015. 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, 2017, 93% 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 93% of our consolidated revenue in the year ended December 31, 2017. Risks associated with our operations in Canada and Australia include, but are not limited to:

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 one of our major Canadian lodges are located on land subject to leases. If we are unable to renew a lease, we could be materially and adversely affected.

All but one 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, 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. Generally, our leases have an initial term of ten years and will expire between 2023 and 2027 unless extended. We can provide no assurances that we will be able to renew our leases upon expiration on similar terms, or at all. If we are unable to renew leases 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 housing and personnel logistics 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 accommodations 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.

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 2017, commodity prices 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:

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 cannot assure you 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.

Our land banking strategy may not be successful.

Our land banking strategy is 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 strategy involves 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:

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 an adverse effect on our business or demand for our services. See “Business - Government Regulation” in Item 1 of this annual report for a more detailed description of our risks associated with environmental laws and regulations.

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:

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

We recorded impairments of our long-lived assets, including intangibles, of $31.6 million, $46.1 million and $79.7 million in 2017, 2016 and 2015, respectively. We also recorded goodwill impairments of $43.2 million in 2015.

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. We may recognize additional impairment losses on our long-lived assets in the future if, among other factors:

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.

There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of Canadian, Australian, 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:

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

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 and realize these intended benefits. 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:

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. If we fail to manage any of these risks successfully, our business could be harmed. Our capitalization and results of operations may change significantly following an acquisition, and our shareholders may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

We may not have adequate insurance for potential liabilities and insurance may not cover certain liabilities, 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 Oil States’ insurance policies for occurrences prior to the completion of 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:

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 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 decline in commodity prices throughout 2015 and 2016 and into 2017, 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, logistics and facility management industry in which we operate is highly competitive. To be successful, we must provide 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, 2017, we were party to collective bargaining agreements covering approximately 850 employees in Canada and 130 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 2020.  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.

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. If our cash flow from operations is less than we anticipate, or if our cash requirements are more than 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. If we incur additional debt or raise equity through the issuance of our preferred shares, including the issuance of preferred shares in connection with the Noralta Acquisition, 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 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 fundamental changes, (ii) asset sales, (iii) 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 5.85 to 1.0 (as of December 31, 2017).

The permitted level of the maximum leverage ratio changes over time, as illustrated in the table below.

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:

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, 2017, we had approximately $297.6 million outstanding under the term loan portion of the Amended Credit Agreement, no borrowings outstanding under the revolving portion of the Amended Credit Agreement, $1.8 million of outstanding letters of credit and capacity to borrow an additional $107.4 million under the revolving portion of the Amended Credit Agreement. Borrowings outstanding under the Amended Credit Agreement mature in May 2019. As of December 31, 2017, our borrowing capacity under the revolving portion of the Amended Credit Agreement was reduced by approximately $165.8 million due to the negative covenants. 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 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.

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. 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 the Noralta Acquisition

There can be no assurance when or even if the Noralta Acquisition will be completed. Failure to obtain required approvals necessary to satisfy closing conditions may delay or prevent completion of the Noralta Acquisition.

The completion of the Noralta Acquisition is subject to a number of closing conditions, some of which are out of our control, including the following:   

We cannot be certain that our shareholders will approve the share issuance proposal. We have received notice from the Competition Bureau that it does not intend to challenge the acquisition under the Competition Act (Canada), and we have been granted approval under the Investment Canada Act for the acquisition. However, we cannot be certain when we and Noralta will be able to satisfy the other closing conditions or whether those closing conditions will be satisfied. If any of these conditions are not satisfied or waived prior to May 31, 2018, it is possible that the Purchase Agreement may be terminated. Although we and Noralta have agreed in the Purchase Agreement to use commercially reasonable efforts, subject to certain limitations, to complete the Noralta Acquisition as promptly as possible, these and other conditions to the completion of the Noralta Acquisition may fail to be satisfied.

The pendency of the Noralta Acquisition could have an adverse effect on the trading price of our common shares and our business, financial condition, results of operations or business prospects.

The pendency of the Noralta Acquisition could disrupt our business in the following ways, including:   

Should they occur, any of these matters could adversely affect the trading price of our common shares or harm our financial condition, results of operations or business prospects.

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

The holders of the preferred shares issued in the Noralta Acquisition will have rights and preferences superior to those of the holders of our common shares. These rights include, among others:     

The Noralta Acquisition may be completed even though material adverse changes subsequent to the announcement of the Noralta Acquisition, such as industry-wide changes or other events, may occur.

In general, either party can refuse to complete the Noralta Acquisition if there is a material adverse change affecting the other party. However, some types of changes do not permit either party to refuse to complete the Noralta Acquisition, even if such changes would have a material adverse effect on either of the parties. For example, a worsening of Noralta’s or our financial condition or results of operations due to a decrease in commodity prices or general economic conditions would not give the other party the right to refuse to complete the Noralta Acquisition. If adverse changes occur that affect either party but the parties are still required to complete the Noralta Acquisition, our share price, business and financial results after the Noralta Acquisition may suffer.

Failure to complete the Noralta Acquisition could negatively impact our share price and future business and financial results.

If the Noralta Acquisition is not completed, our ongoing business may be adversely affected, and we may be subject to several risks, including the following:

We have incurred and will continue to incur significant transaction costs in connection with the Noralta Acquisition.

We expect to incur a number of non-recurring transaction-related costs associated with completing the Noralta Acquisition, combining the operations of the two organizations and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to financial, legal and accounting advisors, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of our businesses. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time.

The failure to integrate our business successfully with Noralta in the expected timeframe would adversely affect our future results following the completion of the Noralta Acquisition.

The success of the Noralta Acquisition will depend, in large part, on our ability following the completion of the Noralta Acquisition to realize the anticipated benefits, including operating synergies, from combining our businesses, which have previously been operated independently. To realize these anticipated benefits, we must successfully integrate Noralta into our business. This integration will be complex and time-consuming, and we and Noralta will only be able to conduct limited planning regarding the integration of the two companies prior to completion of the Noralta Acquisition. Significant management attention and resources will be required to integrate the two companies. Delays in this process could adversely affect our business, financial results, financial condition and share price following the Noralta Acquisition.

Potential difficulties that may be encountered in the integration process include the following:

Even if we were able to integrate the business operations successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies and operational efficiencies that may be possible from this integration and that these benefits will be achieved within a reasonable period of time.

The trading price of our common shares after the Noralta Acquisition may be affected by factors different from those affecting the price of our common shares before the Noralta Acquisition.

Our results of operations, as well as the trading price of our common shares, after the Noralta Acquisition may be affected by factors different from those currently affecting our results of operations and the trading price of our common shares. These factors include:

Accordingly, the historical trading prices and our financial results may not be indicative of future trading prices of the common shares after the Noralta Acquisition.

Our future results will suffer if we do not effectively manage our expanded operations following the Noralta Acquisition.

Following the Noralta Acquisition, the size of our business will be larger than its current business. 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. We can offer no assurance that we will be successful or will realize the benefits currently anticipated to result from the Noralta Acquisition.

The loss of key personnel could have a material adverse effect on our business, financial condition or results of operations.

The success of the Noralta Acquisition will depend in part on our ability to retain key Civeo and Noralta employees who continue employment with us after the Noralta Acquisition is completed. It is possible that these employees might decide not to remain with us after the Noralta Acquisition.

If these key employees terminate their employment, our activities might be adversely affected, management’s attention might be diverted from successfully integrating Noralta’s operations to recruiting suitable replacements and our business, financial condition or results of operations could be adversely affected. In addition, we might not be able to locate suitable replacements for any such key employees who leave the company or offer employment to potential replacements on reasonable terms.

Our success will also depend on pre-existing relationships with third parties, which relationships may be affected by the Noralta Acquisition. Any adverse changes in these relationships could adversely affect our business, financial condition or results of operations.

Our success will be dependent on the ability to maintain and renew relationships with pre-existing third parties, including local Aboriginal groups. For example, Noralta currently has two significant contracts for the provision of accommodation services. One of such contracts extends through April 2022, and the second contract has a primary term through 2027, with early termination by the customer permitted starting in 2021. Following the Noralta Acquisition, we will be subject to the risks, among others, of early termination of the contracts, failure to extend the contracts beyond their primary term and a decrease in demand under the contracts below our expectations. In addition, the revenue we will derive under the contracts following the Noralta Acquisition will be variable and depend on the utilization by the customers of our services under the contracts and other factors that are beyond our control. There can be no assurance that our business will be able to maintain these contracts or other pre-existing business and other relationships, including with local Aboriginal groups, or enter into or maintain other new business relationships, on acceptable terms, if at all. The failure to maintain these contracts and other important pre-existing third party relationships could have a material adverse effect on our business, financial condition or results of operations after the Noralta Acquisition.

Risks Related to the Redomicile Transaction

We are subject to various Canadian and other taxes as a result of the Redomicile Transaction.

While we expect the Redomicile Transaction will enable us to take advantage of lower Canadian tax rates in the years after the year of implementation to a greater extent than would likely have been available if the Redomicile Transaction was not completed, these benefits may not be achieved. In particular, tax authorities may challenge our application and/or interpretation of relevant tax laws, regulations or treaties, valuations and methodologies or other supporting documentation, and, if they are successful in doing so, we may not experience the level of benefits we anticipate or we may be subject to adverse tax consequences. Even if we are successful in maintaining our tax positions, we may incur significant expense in contesting these positions or other claims made by tax authorities. In addition, changes in tax laws or increased rates of tax could have the effect of negatively impacting our anticipated effective tax rates. Our effective tax rates and the benefits described herein are also subject to a variety of other 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.

More specifically, 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 the Redomicile Transaction.

Based on the current provisions of the Canadian Tax Act, we expect that the Redomicile Transaction will not result in any material Canadian federal income tax liability to us. However, if the CRA disagrees with this view, it may take the position that material Canadian federal income tax liabilities or amounts on account thereof are payable by us as a result of the Redomicile Transaction, in which case, we expect that we would contest such assessment. To contest such assessment, we would be required to remit cash equal to half of the amount in dispute, or provide security acceptable to the CRA, to prevent the CRA from seeking enforcement actions pending the dispute of such assessment. If we were unsuccessful in disputing the assessment, the implications could be materially adverse to us. The CRA has not provided (and we have not requested) a ruling on the Canadian tax aspects of the Redomicile Transaction. There can be no assurance that the CRA will agree with our interpretation of the tax aspects of the Redomicile Transaction or any related matters associated therewith.

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, we generally will be classified as a foreign corporation (and, therefore, a non-U.S. tax resident) under 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.

Under Section 7874 of the Internal Revenue Code, if the former stockholders of Civeo US hold 80% or more of the vote or value of our common shares by reason of holding stock in Civeo US (the ownership test), and our expanded affiliated group after the Redomicile Transaction does not have substantial business activities in Canada relative to its worldwide activities (the substantial business activities test), we would be treated as a U.S. corporation. For this purpose, “substantial business activities” generally requires at least 25% of the employees (by number and compensation), assets and gross income of our expanded affiliated group to be based, located and derived, respectively, in Canada (25% test).

We believe that we have satisfied this 25% test because Civeo US had significant operations in Canada prior to the Redomicile Transaction (with its remaining operations occurring in Australia and the United States), and we have continued these operations following the Redomicile Transaction. Therefore, under current U.S. federal income tax law, we believe that we will not be treated as a U.S. corporation for U.S. federal income tax purposes. If it were determined, however, 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.

Under current U.S. federal income tax law, Civeo is generally 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 and other factors that may not allow us to achieve a lower effective corporate tax rate.

While we believe that the Redomicile Transaction should allow for a lower effective corporate tax rate, we cannot give any assurance as to what our effective tax rate will be after the Redomicile Transaction because of, among other things, the tax policies of the jurisdictions where we operate, primarily Canada and Australia. Also, the tax laws of Canada, Australia and other jurisdictions 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.

Recent legislative proposals have aimed to expand the scope of U.S. corporate tax residence, to limit the ability of foreign-owned corporations to deduct interest expense, and to make other changes in the taxation of multinational corporations.

Additionally, the U.S. Congress, government agencies in non-U.S. jurisdictions where we and our affiliates do business, and the Organization for Economic Co-operation and Development have recently focused on issues related to the taxation of multinational corporations. One example is found in the area of “base erosion and profit shifting”, where profits are claimed to be earned for tax purposes in low-tax jurisdictions, or payments are made between affiliates from a jurisdiction with high tax rates to a jurisdiction with lower tax rates. As a result, the tax laws in the U.S. and other countries in which we and our affiliates do business could change on a prospective or retroactive basis, 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 territorial system, and a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017.  Many aspects of the new legislation are unclear and may not be clarified for some time.  As a result, we have made an estimate of the impact of the new laws on our business, operating results and financial condition.  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.

We may be subject to additional Canadian and British Columbia laws and regulations as a result of the Redomicile Transaction.

Now that we are a British Columbia company, we may be subject to additional Canadian and British Columbia laws and regulations, which can increase compliance costs for us and result in delays in future transactions we propose to complete.

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 our spin-off from Oil States International, Inc. (Oil States) in May 2014 (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. Under the tax sharing agreement, for each period in which we or any of our subsidiaries are consolidated or combined with Oil States for purposes of any tax return, and with respect to which such tax return has not yet been filed, Oil States will prepare a pro forma tax return for us as if we filed our own consolidated, combined or unitary return, except that such pro forma tax return will generally include current income, deductions, credits and losses from us (with certain exceptions), will not include any carryovers or carrybacks of losses or credits and will be calculated without regard to the federal Alternative Minimum Tax. We will reimburse Oil States for any taxes shown on the pro forma tax returns, and Oil States will reimburse us for any current losses or credits we recognize based on the pro forma tax returns. 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, 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:

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 2016, the market price of our common shares ranged from a low of $0.75 per share to a high of $2.81 per share, and 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.  From January 1, 2018 to February 19, 2018, the market price of our common shares has ranged between a low of $2.74 per share to a high of $3.81 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:

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.

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 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, 2017. 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 10 – 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.

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.

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 2023 and 2027.

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.

On January 26, 2018, a putative class action captioned Philip Suhr v. Civeo Corporation et al. was filed in the U.S. District Court for the Southern District of Texas against us and members of our board of directors regarding our proposed acquisition of Noralta.  The complaint alleges that we filed a materially incomplete and misleading proxy statement in connection with the Noralta Acquisition, in violation of Sections 14(a) and 20(a) of the Exchange Act and Rule 14a-9 of the Commission.   The complaint seeks injunctive relief, including to enjoin the shareholder vote on the Noralta Acquisition as well as the transaction itself, damages and an award of attorneys' fees, in addition to other relief.  Additional lawsuits arising out of the Noralta Acquisition may be filed in the future. There can be no assurance that we will be successful in the outcome of the pending or any potential future lawsuits.  A preliminary injunction could delay or jeopardize the completion of the Noralta Acquisition, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin the completion of the Noralta Acquisition. We believe that the pending lawsuit is without merit and intend to defend vigorously against the lawsuit and any other future lawsuits challenging the Noralta Acquisition.

ITEM 4. Mine Safety Disclosures

Not applicable.

PART II

Market for Our Common Shares

Our common shares trade on the NYSE under the trading symbol “CVEO.” Set forth in the table below for the periods presented are the high and low sale prices for our common shares. 

Holders of Record

As of February 19, 2018, there were 17 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.

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 performance graph above is furnished and not filed for purposes of the Securities Act and the Exchange Act. The performance graph is not soliciting material subject to Regulation 14A.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Repurchases of Equity Securities by Registrant or its Affiliates in the Fourth Quarter

None.

ITEM 6. Selected Financial Data

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,

The balance sheet data as of December 31, 2017 and 2016 and the statement of operations data for each of the years ended December 31, 2017, 2016 and 2015 are derived from our audited financial statements included in Item 8 of this annual report. The balance sheet data as of December 31, 2015, 2014 and 2013 and statement of operations data for the years ended December 31, 2014 and 2013 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.

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 one of the largest integrated providers of workforce accommodations, logistics and facility management services to the natural resource industry. Our scalable modular facilities provide long-term and temporary accommodations where traditional accommodations and related infrastructure are insufficient, inaccessible or not cost effective. Once facilities are deployed in the field, we also provide catering and food services, housekeeping, laundry, facility management, water and wastewater treatment, power generation, communications and redeployment logistics. Our accommodations support our customers’ employees and contractors 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, primarily in Canada, Australia and the United States. We operate in three principal reportable business segments – Canada, Australia and U.S.

On February 7, 2017, we closed a public offering of 23,000,000 common shares at $3.00 per share. We used a portion of the net proceeds of $64.7 million from the offering to repay amounts outstanding under several revolving credit facilities provided by our primary credit agreement (the Credit Agreement) and are using the remaining proceeds for general corporate purposes.

On February 17, 2017, the third amendment to the Credit Agreement (as so amended, the Amended Credit Agreement) became effective, which (i) reduced the aggregate revolving loan commitments; (ii) added one additional level to the total leverage-based grid for determining interest rates; and (iii) increased the maximum leverage ratio allowed under the Amended Credit Agreement. For further information, please see Note 10 – Debt.

Noralta Acquisition

On November 26, 2017, we entered into a Share Purchase Agreement (the Purchase Agreement) with Noralta, Torgerson Family Trust (Torgerson Trust), 2073357 Alberta Ltd., 2073358 Alberta Ltd., 1818939 Alberta Ltd., 2040618 Alberta Ltd., 2040624 Alberta Ltd., 989677 Alberta Ltd. (989677) and Lance Torgerson. Under the terms and subject to the conditions set forth in the Purchase Agreement, at closing, we will acquire, directly or indirectly, all of the issued and outstanding shares of Noralta. The consideration for the acquisition payable at closing will be in an amount equal to (i) C$209,500,000 (or US$167 million, based on an exchange rate of $0.797 Canadian dollars to U.S. dollars as of February 16, 2018) in cash, subject to customary adjustments for working capital, debt, cash and transaction expenses, of which C$28,500,000 will be held in escrow by Alliance Trust Company (the Escrow Agent) to support the sellers’ indemnification obligations under the Purchase Agreement, (ii) 32,790,868 common shares of Civeo, no par value, of which 13,491,100 shares will be held in escrow by the Escrow Agent and released in three equal installments from escrow upon the satisfaction of certain conditions related to customer contracts remaining in place in June 2021, June 2022 and June 2023, and (iii) 9,679 shares of Class A Series 1 Preferred Shares of Civeo with an initial liquidation preference of US$96,790,000. We intend to fund the cash consideration with cash on hand and borrowings under the Amended Credit Agreement.

Consummation of the transactions contemplated by the Purchase Agreement is subject to various closing conditions, including but not limited to: (i) receipt of Canadian regulatory approvals and other regulatory and third party consents and approvals; (ii) the absence of any injunction or order prohibiting or restricting the consummation of the transactions contemplated by the Purchase Agreement; and (iii) the receipt of approval by our shareholders of our issuance of the common shares and preferred shares. We have received notice from the Competition Bureau that it does not intend to challenge the acquisition under the Competition Act (Canada), and we have been granted approval under the Investment Canada Act for the acquisition. The Purchase Agreement may be terminated by either party if such conditions are not satisfied by May 31, 2018.

In addition, at the closing of the Purchase Agreement, we will enter into a Registration Rights, Lock-Up and Standstill Agreement (the Registration Rights Agreement) with Torgerson Trust and 989677. Pursuant to the terms and conditions of the Registration Rights Agreement, for a period of 18 months following the closing, Torgerson Trust and 989677 will agree not to transfer any of their common shares without our prior written consent, with certain limited exceptions for permitted transfers. Following such 18-month period, Torgerson Trust and 989677 will be permitted to transfer common shares under Rule 144 or an effective registration statement under the U.S. Securities Act of 1933, subject to a limitation restricting transfers of more than 10% of the common shares (including common shares received upon conversion of the preferred shares) received by Torgerson Trust and 989677 during any 90-day period. The Registration Rights Agreement also provides that, as soon as practicable following the date that is 18 months after the date of the Registration Rights Agreement, but in no event more than 30 days thereafter, we will use our commercially reasonable efforts to prepare and file a shelf registration statement under the Securities Act covering the public offering of the registrable securities held by Torgerson Trust and 989677 and cause such shelf registration statement to become effective within 150 days after filing. In addition, Torgerson Trust and 989677 will have customary “piggy-back” rights with respect to public offerings of common shares by us. In the event the shelf registration statement does not become effective within the time period specified in the Registration Rights Agreement, the dividend rate of the preferred shares will be increased by (i) 0.25% per annum commencing on the first succeeding dividend date after such registration default and (ii) 0.25% per annum on each subsequent dividend date until such time as a shelf registration statement becomes effective (up to a maximum increase of 1.00% per annum). Finally, Torgerson Trust and 989677 each agreed to be subject to customary standstill restrictions, including a restriction on additional purchases of common shares, and a restriction on voting common shares that limits the voting by such holders of common shares (including common shares held in escrow) in excess of 15% of the voting power of the outstanding common shares, which will be voted consistently with all other shareholders. The transfer, standstill and voting restrictions terminate at such time as the shares beneficially owned by Torgerson Trust and 989677 no longer constitute at least 5% of our common shares then outstanding (calculated assuming conversion of all of the outstanding preferred shares) or upon a bankruptcy or change of control of Civeo.

Holders of the preferred shares will be entitled to receive a 2% annual dividend, paid quarterly in cash or, at our option, by increasing the preferred shares’ liquidation preference. The preferred shares are convertible into common shares at a conversion price of US$3.30 per preferred share. We have the right to elect to convert the preferred shares into common shares if the 15-day volume weighted average price of the common shares is equal to or exceeds the conversion price. Holders of the preferred shares will have the right to convert the preferred shares into common shares at any time after two years from the date of issuance, and the preferred shares mandatorily convert after five years from the date of issuance. The preferred shares also convert automatically into common shares upon a change of control of Civeo. We may redeem any or all of the preferred shares for cash at the liquidation preference, plus accrued and unpaid dividends. The preferred shares do not have voting rights, except as statutorily required.

Basis of Presentation

Unless otherwise stated or the context otherwise indicates, all references in these consolidated financial statements to “Civeo,” “the Company,” “us,” “our” or “we” refer to Civeo Corporation (Civeo) and its consolidated subsidiaries. All references in this report to “dollars” or “$” are to U.S. dollars.

Macroeconomic Environment

We provide workforce accommodations to the natural resource 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 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 and estimates of resource production. As a result, demand for our products and services is largely sensitive to expected commodity prices, principally related to crude oil and metallurgical (met) coal.

In Canada, Western Canadian Select (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 West Texas Intermediate (WTI) crude and the availability of transportation infrastructure. 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.

After beginning to drop in the second half of 2014, global oil prices dropped during the first quarter of 2016 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. With falling WTI oil prices, WCS also fell.  Prices began to increase in March 2016, and after falling slightly in the second quarter of 2017, prices continued to increase through the second half of 2017.  WCS prices in the fourth quarter of 2017 averaged $38.65 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.  The WCS Differential increased from $16.10 per barrel at the end of the fourth quarter of 2016 to $26.00 per barrel at the end of the fourth quarter of 2017.  As of February 16, 2018, the WTI price was $61.68 and the WCS price was $35.05, resulting in a WCS Differential of $26.63. The increased WCS Differential is resulting from pipeline access limitations.

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 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 services in late 2014 and throughout 2015 and 2016. Although we have seen an increase in oil prices in late 2016 and through 2017, we are not expecting significant improvement in customer activity in the near-term, as we anticipate that our customers’ capital spending will generally lag increased oil prices by nine to 12 months. The current outlook for expansionary projects in Canada is primarily related to proposed pipeline and insitu 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.

Our U.S. business is also primarily tied to oil prices, specifically oil shale drilling and completion activity, and therefore WTI oil prices, in the Bakken, Rockies and Permian Basins.  With the recovery in oil prices in late 2016 and through 2017, coupled with ample capital availability for U.S. E&P companies, oil 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 of 2016 to over 700 rigs active in the fourth quarter of 2017.  As of February 16, 2018, there were 798 active oil rigs in the U.S. (as measured by Bakerhughes.com).  U.S. oil drilling and completion activity will continue to be dependent on sustained higher WTI oil prices 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 5.5% during 2017 compared to 2016.  On March 28, 2017, a Category 4 cyclone made landfall on the coast of Queensland, Australia, temporarily shutting down the majority of Bowen Basin coal export rail infrastructure, causing a spike in met coal spot prices from $152 per metric tonne on March 31, 2017 to over $250 per metric tonne.  As of February 19, 2018, met coal spot prices were $229.25 per metric tonne and benchmark contract prices for the first quarter of 2018 paid to Australian metallurgical coal producers by Japanese steel producers had not settled. Following cyclone Debbie, the market began to shift away from quarterly benchmark pricing to an index linked approach as a pricing mechanism. The changes in met coal pricing this year have not led our customers to approve any significant new projects.  We expect that customers will look for a period of sustained higher prices before new projects are approved.  Long-term demand for steel is expected to be driven by increased steel consumption per capita in developing 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:

__________

Overview

As noted above, demand for our 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 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 three-fourths of our revenue is generated by our large-scale lodge and village facilities. Where traditional accommodations and infrastructure are insufficient, inaccessible or cost ineffective, our lodge and village facilities provide comprehensive accommodations 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.

In response to decreases in crude oil prices beginning in late 2014, 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 accommodations of the kind we provide. 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.

In recent months, 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 is forecasted to be relatively flat, in the aggregate. In addition, 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. 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, 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 accommodations services, we do not expect an immediate improvement in our business. Accordingly, we plan to focus on enhancing the quality of our operations, maintaining financial discipline and proactively managing our business as market conditions continue to evolve.

We began expansion of our room count in Kitimat, British Columbia during the second half of 2015 to support potential liquefied natural gas (LNG) projects on the west coast of British Columbia. We were awarded a contract with LNG Canada (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 436 rooms, with the potential to expand to serve future accommodations demand in the region.

In addition, we were awarded a contract with LNGC to construct a 4,500 person workforce accommodation center (Cedar Valley Lodge) for a proposed liquefaction and export facility in Kitimat, British Columbia. Construction of Cedar Valley Lodge will not commence until LNGC’s joint venture participants have made a positive final investment decision (FID). The FID was originally planned for the end of 2016. However, FID has been delayed. Recent public statements by LNGC and news reports indicate that FID for LNGC is expected in the second half of 2018. Should the project ultimately move forward, British Columbia LNG activity 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.

However, there can be no assurance that LNGC’s joint venture participants will reach a positive FID or that our contracts with LNGC will be extended. Further, on July 25, 2017, Petronas and its partners announced the cancellation of their Pacific NorthWest (PNW) liquefied natural gas project they had planned to build in Port Edward, British Columbia. If the LNGC project, and other potential projects in the area, do not move forward, our future results of operations and our existing long-lived assets in Canada, including our Sitka Lodge, may be negatively affected, and we may be required to record material impairment charges equal to the excess of the carrying values of these assets over their fair values. As of December 31, 2017, the net book value of long-lived assets that are currently supporting, or could be used to support, potential LNG projects in British Columbia was approximately $80 million.

Due to the PNW cancellation, we identified an indicator that certain asset groups used, or expected to be used, in conjunction with potential LNG projects in British Columbia may be impaired. As a result, we assessed the carrying values of each of the asset groups to determine if they continued to be recoverable based on their estimated future cash flows. Based on the assessment, the carrying values of certain undeveloped land positions in British Columbia were determined to not be recoverable, and an impairment charge totaling $1.2 million was recorded in the third quarter of 2017.

We identified an indicator that certain asset groups used in the southern oil sands may be impaired due to market developments, including project delays, occurring in the fourth quarter of 2017. We assessed the carrying value of each of the asset groups in the southern portion of the region to determine if they continued to be recoverable based on their estimated future cash flows.  Based on the assessment, the carrying values of two of our lodges were determined to not be fully recoverable, and we proceeded to compare the estimated fair value of those assets groups to their respective carrying values.  Accordingly, the value of the two lodges were written down to their fair value of zero, and an impairment charge totaling $27.2 million was recorded in the fourth quarter of 2017.

In estimating future cash flows, we made numerous assumptions with respect to future circumstances that might directly impact each of the asset groups’ operations in the future and are therefore uncertain. These assumptions with respect to future circumstances included future oil, coal and natural gas prices, anticipated customer spending, and industry and/or local market conditions. These assumptions represented our best judgment based on the current facts and circumstances. However, different assumptions could result in a determination that the carrying values of additional asset groups are no longer recoverable based on estimated future cash flows. Our estimate of fair value was primarily calculated using the income approach, which derives a present value of the asset group based on the asset groups estimated future cash flows. We discounted our estimated future cash flows using a long-term weighted average cost of capital based on our estimate of investment returns required by a market participant.

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 Canadian dollar was valued at an average exchange rate of U.S. $0.77 for 2017 compared to U.S. $0.76 for 2016, an increase of approximately 2%. The Canadian dollar was valued at an exchange rate of $0.80 on December 31, 2017 and $0.74 on December 31, 2016. The Australian dollar was valued at an average exchange rate of U.S. $0.77 for 2017 compared to U.S. $0.74 for 2016, an increase of approximately 3%. The Australian dollar was valued at an exchange rate of $0.78 on December 31, 2017 and $0.72 on December 31, 2016. 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.

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 2018 capital expenditures, exclusive of any business acquisitions, will total approximately $15 million to $20 million, compared to 2017 capital expenditures of $11.2 million. Please see “Liquidity and Capital Resources” below for further discussion of 2018 and 2017 capital expenditures.

Results of Operations

Unless otherwise indicated, discussion of results for the years ended December 31, 2017 and 2016 is based on a comparison with the corresponding period of 2016 and 2015, respectively.

Results of Operations – Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

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 proposed Noralta Acquisition, included in Selling, general and administrative (SG&A) expense below.

We reported net loss attributable to Civeo for the year ended December 31, 2016 of $96.4 million, or $0.90 per diluted share. As further discussed below, net loss included (i) a $46.1 million pre-tax loss ($35.9 million after-tax, or $0.34 per diluted share) resulting from the impairment of fixed assets, included in Impairment expense, and (ii) a $1.3 million pre-tax loss ($1.2 million after-tax, or $0.01 per diluted share) from costs incurred in connection with the Redomicile Transaction, included in SG&A expense below.

Revenues. Consolidated revenues decreased $15.0 million, or 4%, in 2017 compared to 2016. This decline was largely driven by decreases in Canada due to lower rates and lower mobile, open camp and product activity, partially offset by increased occupancies at some of our lodges. This decrease was offset by increases in the U.S. due to increased activity levels and in Australia due to increased occupancy, as well as stronger Canadian and Australian dollars in 2017 compared to 2016. Please see the discussion of segment results of operations below for further information.

Cost of Sales and Services. Our consolidated cost of sales decreased $2.4 million, or 1%, in 2017 compared to 2016, primarily due to decreases in Canada due to lower mobile, open camp and product activity, as well as a focus on cost containment and operational efficiencies. This was partially offset by increases in the U.S. due to increased activity levels and in Australia due to increased occupancy, as well as stronger Canadian and Australian dollars in 2017 compared to 2016. Please see the discussion of segment results of operations below for further information.

Selling, General and Administrative Expenses. SG&A expense increased $8.1 million, or 15%, in 2017 compared to 2016. This increase was primarily due to higher share based compensation expense associated with phantom share awards, higher incentive compensation costs and higher professional fees when compared to 2016. The increase in share based compensation was due to the increase in our share price during the period, which is used to remeasure the phantom share awards at each reporting date. The higher professional fees include $2.3 million related to the proposed Noralta Acquisition. These items were partially offset by reduced compensation as a result of workforce reductions in 2016 and other administrative cost reductions.

Depreciation and Amortization Expense. Depreciation and amortization expense decreased $4.9 million, or 4%, in 2017 compared to 2016 primarily due to reduced depreciation expense resulting from impairments recorded in 2016, partially offset by increased depreciation expense associated with an enterprise information system placed in service in 2017.

Impairment Expense. Impairment expense of $31.6 million in 2017 consisted of:

Impairment expense of $46.1 million in 2016 consisted of:

Please see Note 3 - Impairment Charges to the notes to the consolidated financial statements in Item 8 of this annual report for further discussion.

Operating Loss. Consolidated operating loss increased $2.2 million, or 2%, in 2017 compared to 2016 primarily due to lower contracted rates in Canada and higher SG&A expenses, partially offset by lower impairment expense and lower depreciation and amortization expense in 2017 compared to 2016.

Interest Expense and Interest Income, net. Net interest expense decreased by $0.7 million, or 3%, in 2017 compared to 2016 primarily due to lower amounts outstanding under our revolving credit facilities in 2017 as compared to 2016, offset by increases from the 2017 write-off of $0.8 million of debt issuance costs associated with an amendment to the Credit Agreement (as compared to a $0.3 million write-off of debt issuance costs in the first quarter 2016) and higher interest rates on term loan and revolving credit facility borrowings.

Income Tax Benefit.  Our income tax benefit for the year ended December 31, 2017 totaled $13.5 million, or 11.4% of pretax loss, compared to a benefit of $20.1 million, or 17.3% of pretax loss, for the year ended December 31, 2016.  Our effective tax rate in 2017 was lower than the Canadian statutory rate of 27%, primarily due to losses in Australia and the U.S. 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 net deferred tax assets in Canada.

Our effective tax rate in 2016 was lower than the Canadian statutory rate of 27%, primarily due to losses in Australia and the U.S. for which no tax benefit was recorded.  As a result, a valuation allowance of $15.1 million was established against net deferred tax assets in the U.S. and Australia.

Other Comprehensive Income (Loss). Other comprehensive income increased $31.6 million in 2017 compared to 2016 primarily as a result of foreign currency translation adjustments due to changes in the Canadian and Australian dollar exchange rates compared to the U.S. dollar. The Canadian dollar exchange rate compared to the U.S. dollar increased 7% from December 31, 2016 to December 31, 2017 compared to a 3% increase from December 31, 2015 to December 31, 2016. The Australian dollar exchange rate compared to the U.S. dollar increased 8% from December 31, 2016 to December 31, 2017 compared to a 1% decrease from December 31, 2015 to December 31, 2016.

Segment Results of Operations – Canadian Segment