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, 2016,2017, we had approximately 1,4001,700 full-time employees on a consolidated basis, 72% of whom are located in Canada, 21%20% of whom are located in Australia and 7%8% of whom are located in the U.S.  We were party to collective bargaining agreements covering approximately 700850 employees located in Canada and 120130 employees located in Australia as of December 31, 2016.2017.

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 20162017 that may affect us or our customers.

Air Quality Management

The Government of Alberta (Alberta) andFederal Regulatory Reforms

In 2017 the Government of Canada (Canada) each have frameworks for air quality management thatinitiated 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 usour operations and financial results as well as those of our customers.

In June 2016, Canada announced theMulti-Sector Air Pollutants RegulationsFederal as part of the implementation of the Air Quality Management System (AQMS) under the Canadian Council of Ministers of the Environment. TheMulti-Sector Air Pollutants Regulations impose mandatory air emissions standards for industry. The proposed standards limit the amount of:

These regulations may impact emission performance standards for compressors and boilers used by our customers in conventional and steam assisted gravity operations in the oil sands and may affect our customers’ operations.

In addition to federal requirements, emissions from facilities in Alberta are subject to provincial regulation. On March 22, 2016, the Alberta Energy Regulator (AER), which is responsible for regulating upstream oil and gas activity in the province, published Directive 60 which requires operators to eliminate or reduce flaring associated with a wide variety of energy development activities and operations. Meeting these regulatory requirements may result in additional costs or liabilities for our customers’ operations.

Climate Change Regulation

Scientific studies have suggested that emissions of greenhouse gases (GHG), including carbon dioxide and methane, may be contributing to warming of the Earth’sEarth’s atmosphere and other climatic changes. On January 29, 2010, Canada affirmed its desire to be associated with the Copenhagen Accord that was negotiated in December 2009 as part of the international meetings on climate change regulation in Copenhagen.  The Copenhagen Accord, which is not legally binding, allows countries to commit to specific efforts to reduce GHG emissions, although how and when the commitments may be converted into binding emission reduction obligations, if ever, is currently uncertain.  Pursuant to the Copenhagen Accord process, Canada has indicated an economy-wide GHG emissions target that equates to a 17 percent reduction from 2005 levels by 2020, and the former Canadian conservative federal government indicated an objective of reducing overall Canadian GHG emissions by 60 percent to 70 percent from 2006 levels by 2050.  However, with current climate change measures in place, Canada’s GHG emissions are forecast to be almost exactly at 2005 levels by 2020 and federal regulations for the oil and gas sector have yet to be introduced.

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 September 2016, the new federal government confirmed that it would not commit to a more ambitious INDC than the preceding conservative federal government. Canada has not implemented any new regulations specifically targeted at achieving its INDC.

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. Until In May 2017, Canada released the federalproposed 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 reduction regulations are finalized, it is not possibleand to determineimplement leak detection and repair programs by 2020. If implemented, the impact of such regulations on our customers. The federal methane reduction regulations, when implemented,new regulatory requirements would be phased in between 2020 and 2023 and may result in additional costs or liabilities for our customers' operationsoperations.

In March 2016, as a further effort to meet Canada’sCanada’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 applyserve as a "backstop" in any province that does not establish an equivalent framework by 2018. Federal regulations implementing the carbon price have not been released.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 Additionally, GHGchange regulation can also take place at the provincial level. For example, Alberta’sClimate Change and Emissions Management Act provides a framework for managing GHG emissions by reducing specified gas emissions, relative to total production from facilities that emit over 100,000 tons of carbon dioxide equivalent per year. The accompanying regulation, theSpecified Gas Emitters Regulation, requires mandatory emissions reductions through the use of emissions intensity targets, and a company can meet the applicable emissions limits by making emissions intensity improvements at regulated facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring “fund credits” (akin to allowances) by making payments for each ton of GHG emissions over the required reduction target to the Alberta Climate Change and Emissions Management Fund. 

In June 2015 the government of Alberta amended theSpecified Gas Emitters Regulation to increase the price per fund credit from $15 to $20 per credit in 2016 and to $30 per credit in 2017. In addition, the amendedSpecified Gas Emitter Regulation also increased the required emission reductions for regulated facilities. Facilities in their ninth or subsequent year of commercial operation were historically required to reduce their net emissions intensity to 12 percent below an established baseline until 2015. These facilities were required to reduce their net emissions intensity to 15 percent below the established baseline in 2016 and to 20 percent below the established baseline in 2017. These amendments are likely to significantly increase the cost of compliance for some of our customers. There are financial penalties for non-compliance for every ton of carbon dioxide equivalent over a facility’s net emission intensity limit as well as for contraventions of other provisions contained in the Specified Gas Emitters Regulation. Further, theSpecified Gas Reporting Regulation imposes GHG emissions reporting requirements on a company that has GHG emissions of 50,000 tons or more of carbon dioxide equivalent from a facility in a calendar year.  In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations in approvals and under other environmental regulations.

In addition to the amendments to theSpecified Gas Emitters Regulation discussed above, Alberta announced a new Climate Leadership Plan (the CLP) in November 2015.(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 emittingthat emit over 100,000 tonnes of carbon dioxide equivalent annually. Those regulations are expected(CO2e) per year as well as other facilities which opt in to be releasedthe 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 early 2017. 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 proposesproposed introducing a broad economy-wide levy on GHG emissions from the combustion of fossil fuels, subject to limited exceptions. In May 2016, Alberta passed theClimate 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. TheAlberta's carbon levy iswas set at $20 per tontonne in 2017 and will increaseincreased to $30 per tontonne effective January 1, 2018. The increase in 2018 andthe carbon levy will add to the cost of most fossil based fuels. This change to the regulation of GHG emissionsfossil-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. It is not certain how this will be achieved, but it is contemplated that new performance standardsThe Alberta Energy Regulator (AER) has been tasked with developing a multifaceted approach to reducing methane emissions from equipment willthe 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 incentivized and potentially mandated. Legislation andequivalent to the federal Proposed Regulations described above. If equivalent, the Alberta methane reduction regulations requirement to implement these policies are anticipatedwould apply in 2017.lieu of the federal Proposed Regulations. Further, as contemplated in the CLP, Alberta passed theOil Sands Emissions Limit Actin 2016 which capsoilcapsoil sands GHG emissions at 100 million tonnes annually. The CLP also targets the phasing out of coal generatedcoal-generated electricity (or the emissions therefrom) by 2030. The combination of the announced carbon levy, and coal phase outphase-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’sEarth’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 condition and results as well as those of operations.

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

Alberta’s Electricity Marketcustomers.

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.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 is intended to take placeconcluded in 2017 andDecember 2017. Alberta procured almost 600 MW of wind generation capacity, achieving the projects must be operational by 2019. lowest price in Canada. Details regarding the next procurement process have not yet been released.

Alberta furtheralso announced on November 23, 2016 that it would restructure its powerelectricity 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 orand our customers.

Royalty Regulations

In January 2016, the Government of Alberta announced Alberta’s Modernized Royalty Framework (Framework). In April 2016, the Government of Alberta finalized the applicable formulas for the Framework which into effect in January 1, 2017. The implementation of the Framework could have an adverse impact on some of 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.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. In addition, the Oil Pollution Act of 1990, as amended (OPA), imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the U.S.  A responsible party under OPA includes the owner or operator of an onshore facility or vessel, or the lessee or permittee of the area in which an offshore facility is located.  The Clean Water Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the OPA,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 2015.2015 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 be regulatedqualify 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’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. ThatWhile that decision is currently being appealed by the federal government.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. Throughout 2015 and Although we have seen an increase in oil prices in late 2016 and continuing intothrough 2017, we are not expecting significant improvement in customer activity in the near-term, as we anticipate that our customers’ expenditures have declined significantly duewill generally lag increased oil prices by nine to the long-term decline in commodity prices.12 months. If our customers’ expenditures continuefail to declineincrease in regions where our facilities are located, our business will be further 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 levellevels 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, and higher than normal inventory levels haveincluding increased U.S. shale oil production, also negatively impacted pricing. With falling Brent Crude and West Texas Intermediate (WTI) oil prices, Western Canadian Select (WCS) has also fallen.fell. Oil prices and WCS have rebounded in recent periods. WCS prices in the fourth quarter of 20162017 averaged $34.34$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 20, 2017,16, 2018, the WTI price was $53.40,$61.68, and the WCS price was $39.78. $35.05. 

In addition, met coal prices have decreased materiallyfluctuated from approximately $119/metric tontonne as of December 31, 2014 to approximately $92.50/metric tontonne 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 20, 2017, contract met coal prices were approximately $285.00 per metric tonne and19, 2018, spot prices for met coal were $150 per $229.25/metric tonne significantly higher thanand benchmark contract prices for the September 2016 contract pricefirst quarter of $92.50 per metric tonne, due2018 paid to supply side factors that have restrictedAustralian metallurgical coal producers by Japanese steel producers had not settled.  The increase in met coal volumes.pricing in 2017 and early 2018 have not led our customers to approve any significant new projects. The existinglow commodity price environment has significantly depressed exploration, development, and production activity.  A sustained continuationdeterioration of these prices or further deteriorationthis 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’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 currentrecent 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’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 including intangibles, of $31.6 million and $46.1 million in 2017 and $79.7 million in 2016, and 2015, 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, 2016, 97%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 97%93% of our consolidated revenue in the year ended December 31, 2016.2017. 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 20172023 and 20262027 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 2011, major flooding caused by seasonal rain and2017, 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’slodge’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 1.1 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. Throughout 2015 andequity. Although we have seen an increase in oil prices in late 2016 and continuing intothrough 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 Gulf of Mexico.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. Our operations in the Gulf of Mexico are also affected by weather patterns. 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’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 an individuala 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: