NEWALTA CORPORATION MANAGEMENT S DISCUSSION AND ANALYSIS

Transcription

1 NEWALTA CORPORATION MANAGEMENT S DISCUSSION AND ANALYSIS Three months and year ended 2017 and 2016 The following management s discussion and analysis ( MD&A ) is a review of the financial position and operational results of Newalta Corporation ( Newalta or the Corporation ). The MD&A should be read in conjunction with (i) the audited consolidated Financial Statements of Newalta, and the notes thereto ( Financial Statements ), for the year ended 2017 and 2016, (ii) the MD&A of Newalta for the year ended 2016, and (iii) the most recently filed Annual Information Form of Newalta. The Financial Statements of the Corporation are prepared in accordance with International Financial Reporting Standards ( IFRS ), which are the generally accepted accounting principles ( GAAP ) for public Canadian companies and are available on SEDAR ( Information for the three months and year ended 2017, along with comparative information for 2016, is provided. This MD&A is dated March 6, 2018, and takes into consideration information available up to that date. Throughout this document, unless otherwise noted, all currency is stated in Canadian dollars and n/m indicates the percentage change is not meaningful. NEWALTA WHO WE ARE Newalta is a leading provider of innovative engineered environmental solutions that enable customers to reduce disposal, enhance recycling and recover valuable resources from oil and gas exploration and production waste streams. We simplify the critical challenges of sustainable environmental practices through the use of advanced processing capabilities deployed through a differentiated business model. We serve customers onsite directly at their operations and through a network of locations throughout North America. Our proven processes and excellent record of safety make us the first-choice provider of sustainability-enhancing services for oil and gas customers. With a highly skilled team of people, more than a two-decade track record of innovation and a commitment to commercializing new solutions, Newalta is positioned for sustained future growth and improvement. We are Sustainability Simplified TM. Our business is comprised of two operating divisions and two business units within each of the divisions: Heavy Oil Division Oilfield Division Facilities Facilities Onsite Drilling Services 1

2 HEAVY OIL Heavy Oil includes an integrated network of facilities to serve both the oil sands in Alberta and the conventional heavy oil region in Alberta and Saskatchewan. We began working in the heavy oil industry over 20 years ago when we introduced centrifugation as a solution to treat waste oil emulsions. The business has expanded from processing heavy oil waste at facilities in our network to include long-term contracts to process waste on our customers sites. Leveraging our facilities as staging areas and piloting and commercializing processing programs, we deliver a broad range of specialized services at numerous customer sites. The following tables describe our Heavy Oil business units: Facilities SERVICES PROVIDED WASTE STREAMS FACTORS IMPACTING RESULTS Process oilfield-generated wastes including treatment, water disposal, salt cavern disposal, and landfilling, as well as the sale of recovered crude oil to our account. Slop and slop oil from steam-assisted gravity drainage ( SAGD ) and Cold Heavy Oil Production with Sand ( CHOPS ), wastewater and associated by-products, tank bottom emulsions, turnaround waste from storage, terminal or battery facilities. Production activity from SAGD and CHOPS drives the amount and makeup of waste generated by customers. Given high decline rates for CHOPS wells, the rate of new wells drilled is a leading indicator of CHOPS waste volumes. Crude oil prices impact the price we receive for the crude oil recovered to our account from waste volumes and can impact future production activity. Western Canadian Select ( WCS ) is our heavy crude oil industry benchmark. Onsite SERVICES PROVIDED WASTE STREAMS FACTORS IMPACTING RESULTS Provide specialized onsite services using centrifugation or other processes for heavy oil producers involved in heavy oil mining and in situ production (i.e. SAGD). Mature fine tailings ( MFT ) and other oil sands mining waste, slop oil and lime sludge from SAGD production. Number and scope of projects and contracts are directly impacted by our ability to attract and retain customers with existing operations and new heavy oil operations as they come on stream. Generally, these services have no direct commodity price exposure. Timing and term of projects and contracts, since the onsite services we provide generally cannot be performed during the winter months. Level of investment in SAGD and oil sands mining by our customers. 2

3 OILFIELD Oilfield includes an integrated network of facilities and mobile equipment to service key markets in western Canada and the U.S. The following tables describe our Oilfield business units: Facilities SERVICES PROVIDED WASTE STREAMS FACTORS IMPACTING RESULTS Process oilfield-generated wastes including water disposal and landfilling, as well as the sale of recovered crude oil to our account. Midstream services include processing production fluids (custom treating), clean oil terminalling and produced water disposal. Drilling-related waste includes waste from cuttings, drilling mud, frac fluids and completions. Production-related waste includes tank bottom emulsions, waste from well work-overs, spills, and turnaround waste from storage, terminal or battery facilities. Drilling activity, including metres drilled and drilling techniques, will impact the volume and makeup of waste received. The level of completions activity also impacts the volume and mix of waste received. Ongoing production activity drives the makeup of waste generated by our customers and accounts for approximately 55% of our waste volume. The stage of development or expansion of plays impacts demand for our midstream services. In the early stages, infrastructure limitations drive volumes to our facilities. As takeaway infrastructure is established, volumes to our facilities decline. Crude oil prices impact the price we receive for the crude oil recovered to our account from waste volumes. In Canada, Canadian Light Sweet ( CLS ) is our conventional crude oil industry benchmark and in the U.S., West Texas Intermediate ( WTI ) is our crude oil industry benchmark. Drilling Services SERVICES PROVIDED FACTORS IMPACTING RESULTS DRILL SITE SERVICES Provide the supply and operation of drill site processing equipment, including equipment for solids control and drill cuttings management. Drill Site utilization is impacted by the number of active drilling rigs and the number of days of drilling activity in the markets we serve. Results are impacted by changes in drilling activity in the respective plays we serve as indicated by active rigs and changes in our market share and operations. ENVIRONMENTAL SERVICES Provide environmental services comprised of environmental projects, drilling waste management services and site remediation. Demand for environmental services is impacted by oil and gas activity levels and customers capital budgets. 3

4 STRATEGY As we enter 2018, we will maintain our focus on strengthening our balance sheet and improving financial flexibility by proactively managing operating cash flows, streamlining processes, and managing costs. Our long-term vision remains fundamentally unchanged; we will leverage our core competencies, drive improved returns from our investments and grow profitable revenue streams. Our strategy will focus on the following: STRATEGY CUSTOMER-DRIVEN, VALUE-ADDED SOLUTIONS Sustainability Simplified TM PLAY-BASED INFRASTRUCTURE EXPANSION OPERATIONAL EXCELLENCE STRATEGY DESCRIPTION Develop an integrated service offering at each stage of drilling, completions and production and create value through product recovery; continue to move processing closer to source to optimize logistics. Leverage core competencies in centrifugation, onsite processing and project management to deploy innovative solutions to provide value to our customers. Increase market position in SAGD and mining by establishing technically differentiated and contracted relationships with customers. Expand our operating footprint in the Western Canadian Sedimentary Basin ( WCSB ) where we have an established network. Establish a presence with scale in high activity plays. Implement a structured methodology to improve performance in the significant areas of our business such as utilization, process efficiency and innovation. We are subject to a number of risks and uncertainties in carrying out our activities including market conditions, ability to expand the business, competition, regulation, ability to secure financing on acceptable terms, and the ability to attract and retain personnel. A complete list of our risk factors is disclosed in our most recently filed Annual Information Form. INDUSTRIAL SALE In February 2015, we completed the sale of our Industrial Division. As a result, we defined our Industrial Division as Discontinued Operations, the remaining operations as Continuing Operations and the total Discontinued Operations and Continuing Operations as Combined Operations. In accordance with the requirements of IFRS 5 Non-current Assets Held for Sale and Discontinued Operations, income, expenses and cash flow provided and used associated with the business that was sold were classified as Discontinued Operations in the Financial Statements for the periods presented. Unless otherwise noted, commentary and the financial results will refer to Continuing Operations. 4

5 FORWARD-LOOKING INFORMATION Certain statements contained in this document constitute "forward-looking information" as defined under applicable securities laws. When used in this document, the words "may", "would", "could", "will", "intend", "plan", "anticipate", "believe", "estimate", "expect", "potential", "strategy", "target" and similar expressions, as they relate to Newalta Corporation and the subsidiaries of Newalta Corporation, or their management, are intended to identify forward-looking information. In particular, forward-looking information included or incorporated by reference in this document includes information with respect to: future operating and financial results; business prospects and strategy including related timelines; capital expenditure programs and other expenditures; realization of anticipated benefits of growth capital investments, acquisitions, divestitures and our innovation and process development initiatives; realization of anticipated benefits from the implementation of cost rationalization initiatives including the anticipated value and sustainability of the cash savings from such initiatives; the availability to us of financing alternatives, including those that may permit the refinancing of our November 2019 debentures prior to their maturity and the timing of such refinancing, if any; our capital structure objectives; anticipated industry activity levels; anticipated commodity prices; expected demand for our services; expected expansion opportunities for our business; the amount of dividends declared or payable in the future; our projected cost structure and cash flow management activities; expectation and implications of changes in legislation; and the Arrangement (as defined herein), including the timing and business of the annual and special meeting of the Newalta securityholders to be called to consider the Arrangement (the Newalta Meeting ) and the timing and business of the annual and special meeting of the Tervita shareholders to be called to consider the Arrangement (the Tervita Meeting ), the timing of mailing of the joint information circular in respect of the Newalta Meeting and the Tervita Meeting, the consideration to be paid under the Arrangement, the ability to obtain all necessary approvals for completion of the Arrangement and the expected closing date of the Arrangement. Expected future financial and operating performance and related assumptions are set out under Outlook & Operating Leverage. Such information reflects our current views with respect to future events and are subject to certain risks, uncertainties and assumptions, including, without limitation: strength of the oil and gas industry, including drilling activity; general market conditions; fluctuations in commodity prices for oil and the price we receive for our recovered oil; fluctuations in interest rates and exchange rates; financial covenants in our debt agreements that may restrict our ability to engage in transactions or to obtain additional financing; effectiveness of our cash flow management activities and cost rationalization initiatives; success of our growth, acquisition and innovation and process development strategies including integration of businesses and processes into our operations and potential liabilities from acquisitions; our ability to secure future capital to support and develop our business, including the issuance of additional common shares; our ability to secure alternative financing, if needed, and including financing that may permit the refinancing of our November 2019 debentures prior to their maturity, at all or on terms acceptable to us and consistent with our capital structure objectives; the highly regulated nature of the environmental services and waste management business in which we operate; the competitive environment of our industry in Canada and the United States; possible volatility of the price of, and the market for, our common shares, and potential dilution for shareholders in the event of a sale of additional shares; dependence on our senior management team and other operations management personnel with waste industry experience; potential operational and safety risks and hazards, obtaining insurance for such risks and hazards on reasonable financial terms and potential failure of meeting customer safety standards; the seasonal nature of our operations; timing and term of contracts for our services; risk of pending and future legal proceedings; risk to our reputation; our ability to attract, retain and integrate skilled employees; open access for new industry entrants and the general unprotected nature of technology used in the waste industry; costs associated with operating our landfills; the receipt, in a timely manner, of regulatory, shareholder, court and third party approvals in respect of the Arrangement; the satisfaction or waiver of all conditions to closing of the Arrangement; that the Arrangement Agreement (as defined herein) will not be terminated prior to closing of the Arrangement; and such other risks or factors described from time to time in reports we file with securities regulatory authorities. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking information will not occur. Many other factors could also cause actual results, performance or achievements to be materially different from any future results, performance or achievements that may be expressed or implied by such forward-looking information and readers are cautioned that the foregoing list of factors is not exhaustive. Should one or more of these risks or uncertainties materialize, or should assumptions underlying the forward-looking information prove incorrect, actual results may vary materially from those described herein as intended, planned, anticipated, believed, estimated or expected. Furthermore, the forward-looking information contained in this document is made as of the date of this document and, in each case, is expressly qualified by this cautionary statement. Unless otherwise required by law, we do not intend, or assume any obligation, to update any such forward-looking information. 5

6 RECONCILIATION OF NON-GAAP MEASURES The following MD&A contains references to certain financial measures that do not have any standardized meaning prescribed by IFRS and may not be comparable to similar measures presented by other corporations or entities. These financial measures are identified and defined below. Adjusted EBITDA and Adjusted EBITDA per share are measures of our operating profitability. Adjusted EBITDA is defined as net earnings (loss) before depreciation and amortization, finance charges, income tax, stock-based compensation, impairment, restructuring and other expense, and gains or losses on embedded derivatives. Management believes that Adjusted EBITDA provides improved continuity with respect to the comparison of our operating results over a period of time and, as such, is an important indicator of the company s ability to generate future operating profitability. Adjusted EBITDA provides an indication of the results generated by our principal business activities prior to: how these activities are financed; how the results are taxed in various jurisdictions; non-cash charges (such as impairment, depreciation, amortization and gains or losses on embedded derivatives); charges outside the normal course of business (such as restructuring and other (recovery) expense); charges that introduce volatility unrelated to operating profitability by virtue of the impact of external factors (such as stock-based compensation which fluctuates with changes in our share price); and charges that are non-recurring in nature. Adjusted EBITDA is derived from the consolidated statements of operations and comprehensive income (loss). Adjusted EBITDA per share is derived by dividing Adjusted EBITDA by the basic weighted average number of shares outstanding for the respective periods. Adjusted EBITDA is calculated as follows: Three months ended Year ended ($000s except per share data) Net loss (12,262) (75,346) (48,170) (158,476) Add back: Depreciation and amortization (1) 17,341 17,939 67,525 61,360 Stock-based compensation (2) (627) 3,849 Restructuring and other (recovery) expense (3) (1,328) (9,567) (3,556) 22,300 Impairment - 56,030-60,749 Finance charges (3) 7,453 7,182 29,592 28,233 Embedded derivative (gain) loss (100) (11) (135) 1,527 Income tax expense - 14,962-2,310 Adjusted EBITDA 11,565 11,486 44,629 21,852 Weighted average number of shares 88,148 88,148 88,148 78,557 Adjusted EBITDA per share ($) (1) Includes non-cash gains or losses on asset disposal and other non-cash charges. (2) Non-cash stock-based compensation was an expense of $467 and a recovery of $1,116 for the three months and year ended 2017 (expense of $211 and $3,557 for the three months and year ended 2016). (3) Certain prior period comparative figures have been reclassified to conform to current year presentation. Divisional EBITDA provides an indication of the results generated by the division s principal business activities prior to how activities are financed and assets are amortized or impaired. Divisional EBITDA is calculated including directly attributable costs (such as divisional executive, business development, and customer service and sales) prior to the allocation of all non-direct general and administrative ( G&A ) costs, restructuring and other (recovery) expense or stock-based compensation. Management believes that Divisional EBITDA provides improved continuity with respect to the comparison of our divisional operating results over a period of time and, as such, is also an important indicator of the company s ability to generate future divisional operating profitability. 6

7 Divisional EBITDA is derived from the consolidated statements of operations and comprehensive income (loss). Divisional EBITDA is calculated as follows: Three months ended Year ended ($000s except per share data) Loss before income taxes (12,262) (60,384) (48,170) (156,166) Add back: Depreciation and amortization (1) 17,341 17,939 67,525 61,360 Stock-based compensation (2) (627) 3,849 Restructuring and other (recovery) expense (3) (1,328) (9,567) (3,556) 22,300 Impairment - 56,030-60,749 Finance charges (3) 7,453 7,182 29,592 28,233 Embedded derivative (gain) loss (100) (11) (135) 1,527 Adjusted EBITDA 11,565 11,486 44,629 21,852 Add back: G&A 6,934 7,690 27,919 31,060 Divisional EBITDA 18,499 19,176 72,548 52,912 Heavy Oil 7,216 11,571 32,581 33,709 Oilfield 11,283 7,605 39,967 19,203 (1) Includes non-cash gains or losses on asset disposal and other non-cash charges. (2) Non-cash stock-based compensation was an expense of $467 and a recovery of $1,116 for the three months and year ended 2017 (expense of $211 and $3,557 for the three months and year ended 2016). (3) Certain prior period comparative figures have been reclassified to conform to current year presentation. Total Debt is defined as the sum of the amount drawn on the Credit Facility, Letters of Credit, Finance Lease Obligations and Senior Unsecured Debentures less Cash on Hand. Refer to Liquidity and Capital Resources section for calculation. References to Adjusted EBITDA, Adjusted EBITDA per share, Divisional EBITDA, and Total Debt throughout this document have the meanings set out above. 7

8 SELECT ANNUAL FINANCIAL INFORMATION (1) ($000s except per share data) Continuing Operations Revenue 246, , ,584 General & administrative expenses 27,919 31,060 45,464 Net loss (48,170) (158,476) (166,027) - per share ($) basic and diluted (0.55) (2.02) (2.95) Adjusted EBITDA (2) 44,629 21,852 54,614 - per share ($) Maintenance capital expenditures (2) 9,691 8,152 11,900 Growth capital expenditures (2)(3) 4,485 6,683 63,047 Total Assets 688, , ,483 Non-current Liabilities 454, , ,836 Dividends declared ,600 - per share ($) (2) Dividends paid - 3,515 26,809 Weighted average shares outstanding 88,148 78,557 56,221 Shares outstanding, (4) 88,148 88,148 56,237 Combined Operations Revenue 246, , ,692 Net loss (48,170) (158,465) (183,056) - per share ($) basic and diluted (0.55) (2.02) (3.25) (1) Refer to Newalta s Management s Discussion and Analysis and Consolidated Financial Statements for further information. References to GAAP are synonymous with IFRS and references to Consolidated Financial Statements and notes are synonymous with Financial Statements. (2) These financial measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other issuers. Non-GAAP financial measures are identified and defined throughout the attached Management s Discussion and Analysis. (3) Growth capital expenditures are net of 2015 and 2016 contributions from a midstream joint venture partner for its interest in a modular processing facility ( MPF ). (4) Newalta had 88,148,148 shares outstanding as at March 6,

9 SELECT QUARTERLY FINANCIAL INFORMATION (1) Three months ended ($000s except per share data) (unaudited) % change Revenue 61,740 63,707 (3) General & administrative expenses 6,934 7,690 (10) Net loss (12,262) (75,346) (84) - per share ($) basic and diluted (0.14) (0.85) (84) Adjusted EBITDA (2) 11,565 11, per share ($) basic and diluted Maintenance capital expenditures (2) 3,229 4,097 (21) Growth capital expenditures (2)(3) 1,722 2,969 (42) Weighted average shares outstanding 88,148 88,148 - Shares outstanding, (4) 88,148 88,148 - (1) Refer to Newalta s Management s Discussion and Analysis and Consolidated Financial Statements for further information. References to GAAP are synonymous with IFRS and references to Consolidated Financial Statements and notes are synonymous with Financial Statements. (2) These financial measures do not have any standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other issuers. Non-GAAP financial measures are identified and defined throughout the attached Management s Discussion and Analysis. (3) Growth capital expenditures are net of 2016 contributions from a midstream joint venture partner for its interest in a modular processing facility. (4) Newalta had 88,148,148 shares outstanding as at March 6,

10 CORPORATE OVERVIEW Financial Results Q revenue of $61.7 million decreased by 3% compared to prior year, driven by a decline in production related waste volumes at our Heavy Oil facilities partially offset by increased utilization in Drilling Services. Revenue for the year increased 20% to $246.4 million from $205.4 million in prior year, primarily driven by an increase in Drilling Services utilization and drilling and production related waste volumes received at our Canadian Oilfield Facilities. Net loss for the quarter was $12.3 million compared to $75.3 million in prior year. The year-over-year improvement primarily related to the $56 million of impairment recognized in Q Net loss for the year improved from $158.5 million in the prior year to $48.2 million, due to impairment recognized in 2016 as well as increased contributions from the Oilfield division and reduced restructuring and other expense in Adjusted EBITDA for the quarter remained flat at $11.6 million compared to prior year, as increased contributions realized by Drilling Services and cost savings in G&A were offset by decreased contributions from the Heavy Oil division. Adjusted EBITDA for 2017 was $44.6 million, an increase of $22.7 million over prior year. The 104% increase was driven by Divisional EBITDA improvements of $19.6 million and G&A savings of $3.1 million. Effective March 31, 2017, we amended and extended the terms of our Credit Facility to extend the waiver of our Total Debt to Covenant EBITDA covenant to Q and to revise the Senior Debt to Covenant EBITDA and Interest Coverage covenant thresholds. 10

11 Our contract model continued to provide predictable cash flow. These contracts are of varying lengths, generally are not tied directly to commodity price changes or drilling activity and provide a solid foundation for our business, particularly in depressed markets. In 2017, contracts represented 18% of our revenue. (1) Step Change is primarily comprised of the net impact of production waste volumes and shifts in waste mix, net impact of contributions from Onsite contracts and, to a lesser extent, customer pricing and operational efficiencies. (2) Cost Rationalization is comprised of the savings from our various initiatives to right-size the organization, streamline cost structures and business processes, and rationalize office space. Heavy Oil In the fourth quarter, Heavy Oil revenue decreased by 26% to $19.6 million primarily driven by decreased SAGD volumes received at our facilities. Net earnings before taxes in the quarter were $0.9 million, a $43.1 million improvement over prior year primarily due to impairment recognized in Divisional EBITDA decreased by 38% to $7.2 million in the quarter due to decreased contributions from our Facilities business unit. In 2017, Heavy Oil revenue remained flat at $88.2 million compared to prior year as increased demand for project work in Onsite and higher commodity prices were offset by a decrease in SAGD volumes received at our facilities. Net earnings before taxes for the year were $7.3 million, an improvement of $44.2 million over prior year primarily driven by the same factor as the quarter. Divisional EBITDA remained flat at $32.6 million compared to prior year due to the same factor as the quarter, partially offset by increased contributions from Onsite. Oilfield In the fourth quarter, Oilfield revenue increased 13% over prior year to $42.1 million primarily driven by improvements in Drilling Services. Net earnings before taxes in the quarter were $3.3 million, a $12.8 million improvement over prior year. The increase was primarily driven by impairment recognized in 2016 as well as increased contributions from Drilling Services, partially offset by increased depreciation and amortization expense. Divisional EBITDA increased by 48% over prior year to $11.3 million primarily as a result of improved drilling activity. In 2017, Oilfield revenue increased by 37% over prior year to $158.2 million due to improvements in both Drilling Services and Facilities. Net earnings before taxes for the year were $10.1 million, a $30.5 million improvement over prior year driven by the same factors as the quarter and reduced restructuring and other expense. Divisional EBITDA increased 108% over prior year to $40.0 million due to the same factors as the quarter. 11

12 Capital Expenditures Capital expenditures for the three months and year ended 2017 were $5.0 million and $14.2 million, respectively, a decrease of 30% and 4% over prior year. Expenditures for the quarter and year have been primarily focused on maintenance projects. G&A and Restructuring G&A decreased 10% to $6.9 million and $27.9 million, respectively, for the three months and year ended The year-over-year improvement was driven by our disciplined approach to maintaining the benefit of the cost rationalization initiatives taken throughout the downturn. Restructuring and other recovery for the three months and year ended 2017, were $1.3 million and $3.6 million compared to a recovery of $9.6 million and expense of $22.3 million in the prior year. The current year recovery is primarily comprised of a decrease to the non-cash decommissioning liabilities related to inactive sites, partially offset by a fair value loss on held-for-trading investment. Recent Developments On February 28, 2018, we entered into an arrangement agreement (the Arrangement Agreement ) with Tervita Corporation ( Tervita ), pursuant to which Tervita has agreed, through a series of transactions, to acquire all of our issued and outstanding common shares on the basis of: (i) of a Class A Common share ( Amalco Share ) of Amalco (as defined herein); and (ii) of one warrant to purchase one Amalco Share, for each outstanding common share of Newalta, and Newalta and Tervita will amalgamate to form Tervita Corporation ( Amalco ). Each Amalco Warrant will be exercisable for a period of two years from the closing of the Arrangement (as defined herein) at a price of $2.75 per equivalent common share of Newalta. The transaction is to be completed by way of a plan of arrangement (the "Arrangement") under the Business Corporations Act (Alberta). The Arrangement is subject to customary conditions for a transaction of this nature, which include, without limitation, court and regulatory approvals including the Toronto Stock Exchange and approval under the Competition Act (Canada), the approval of 66 2/3% of the votes cast by our securityholders represented in person or by proxy at an annual and special meeting of our securityholders to be called to consider the Arrangement (the Newalta Meeting ) and the approval of 66 2/3% of the votes cast by the shareholders of Tervita represented in person or by proxy at an annual and special meeting of the shareholders of Tervita to be called to consider the Arrangement (the Tervita Meeting ). A joint information circular regarding the Arrangement is expected to be mailed to our securityholders and the shareholders of Tervita in early April 2018 for the Newalta Meeting and the Tervita Meeting, each scheduled to take place in late April Closing of the Arrangement is expected to occur upon receipt of all required regulatory approvals, including the approval under the Competition Act (Canada). 12

13 The following section contains forward-looking information as it outlines our Outlook for Our Outlook is based on several key assumptions including growth capital contributions, commodity prices and activity levels in the oil and gas industry. Changes to these assumptions could cause our actual results to differ materially. We are subject to a number of risks and uncertainties in carrying out our activities including market conditions, ability to expand the business, competition, regulation, and the ability to attract and retain personnel. A complete list of our risk factors is disclosed in our most recently filed Annual Information Form. OUTLOOK & BUSINESS DRIVERS Our business performance is tied to drilling and production related activities in western Canada and the United States. Sustained, stable oil and gas prices enable our customers to make capital decisions to invest in the drilling and completion of new wells and reactivation of shut-in wells. Activity levels, which correlate to the generation of production waste volumes, will vary among plays based on their cost profile. We provide enhanced value solutions to our customers, enabling them to extract greater value from their operations irrespective of cost profile. The key drivers of our business performance are as follows: Crude Oil Prices Crude oil prices (primarily Canadian benchmarks WCS and CLS) directly impact the value of the products we recover from waste. Relative strength and stability of crude oil benchmarks impact confidence amongst producers and play a key role in determining their capital budgets, which in turn drives activity levels. Drilling Activity Drilling Services performance is driven by active rigs and is the first business line to respond to changes in activity. Wells drilled and completed in the areas we serve drive waste volumes into our facilities. Drilling activity in the areas we serve is dependent on the cost profile of the play, with low cost profile shale play activity being initiated at lower oil prices than the more expensive profile plays such as in heavy oil areas. At higher asset utilization levels, we generally see improved pricing for our services. Production Impact & Other Primarily comprised of the net impact of production waste volumes and shifts in waste mix, net impact of contributions from Onsite contracts and, to a lesser extent, customer pricing and operational efficiencies. We typically see a time lag between the deployment of producers capital budgets, including turnarounds and workovers, and the subsequent production waste volume increases to our business. The composition of waste volumes impacts the degree of processing complexity and the amount of recoverable oil. CHOPS waste volumes are also dependent on the drilling of new wells to replace production volumes lost through their naturally steep decline curves. SAGD waste volumes are dependent on the number, timing and length of event-based upsets occurring in the normal course of SAGD facility operations. The timing and amount of mining contributions will be dependent on the approval of producers mitigation plans to meet the Tailings Management Framework. We continue to work with producers to develop solutions to meet these requirements. We continue to prudently manage our operational and corporate cost structure. Outlook Our outlook for 2018 is based on our expectation of year-over-year trends including: Increased commodity prices Strengthening WTI and CLS prices Minor improvement to WCS with the WTI-WCS differential remaining wide due to the impact of limitations on takeaway capacity 13

14 Marginal increases in drilling and completions activity in the areas we serve Production related activity down slightly on a net basis, driven by: Reduction in midstream services, primarily related to the Pembina Phase III pipeline which came into service mid-2017 Lower event-based SAGD volumes Increased waste volumes at our Oilfield Facilities Incremental improvements in CHOPS waste volumes Disciplined focus on maintaining our streamlined cost structure and business processes Our Q1 and full-year 2018 guidance ranges are: Revenue of $50 million to $60 million for the first quarter and $235 million to $260 million for the full year; and Adjusted EBITDA of $10 million to $12 million for the first quarter and $50 million to $60 million for the full year. The following table outlines the factors we expect to impact Adjusted EBITDA performance in the first quarter and full year of 2018: Factor Actual (1) Assumption (1) Expected impact on Adjusted EBITDA compared to prior year period (1) Q Q1 and Full Year 2018 Q West Texas Intermediate (US$/bbl) Q4: $55.38 Q1 2018: $60 $ : $ : $55 $65 Canadian Light Sweet (CDN$/bbl) (2) Q4: $66.93 Q1 2018: $70 $ : $ : $65 $75 $0M $0.5M $0.5M $3M Western Canadian Select Q4: $54.86 Q1 2018: $45 $50 (CDN$/bbl) (2) 2017: $ : $47 $55 Flat $0.5M $0.5M Drilling activity (2) over prior year Q4: 30% Q1 2018: 15% 25% 2017: 30% 2018: 15% 20% $1M $2.5M $3M $8M Production Impact & Other (3)(4) Q4: ($4.1M) 2017: $4.3M $1.5M $2.5M $4M Adjusted EBITDA Guidance $10M $12M $50M $60M (1) M refers to millions. (2) Impact derived from annual sensitivities based on forecast performance and volumes outlined in the Sensitivities section. The actual impact from crude oil prices may vary with fluctuations in volumes. (3) This factor is expected to have an impact on our performance through the year and cannot be quantified on any linear sensitivity. (4) 2017 balances include Step Change and Savings from Cost Rationalization. Total Debt, Capital & Cash Flow Management Management continues to focus on moving towards a positive cash flow model and to date we have made significant progress through proactive management of operating cash flows and cost rationalization initiatives. In 2017, we made progress towards our near-term financial objective of cash flow neutral, ending the year with a $14.1 million cash draw. Moving into 2018, we will continue to maintain our focus on cash flow and exercise prudent judgment in managing our capital expenditures, in alignment with our longer-term target of positive cash flow. Effective March 31, 2017, we amended and extended the terms of our Credit Facility to extend the waiver of our Total Debt to Covenant EBITDA covenant to Q and to revise the Senior Debt to Covenant EBITDA and Interest Coverage covenant thresholds. These amendments provide us with the flexibility to continue to manage our balance sheet as our performance improves. Managing debt leverage and use of cash and capital are our highest priorities. We expect to remain within our debt covenants throughout RESULTS OF OPERATIONS HEAVY OIL The Heavy Oil division is organized into two business units, Facilities and Onsite. The business units contributed the following to division revenue: Three months ended Year ended Facilities 44% 49% 39% 45% Onsite 56% 51% 61% 55% 14

15 The following table compares Heavy Oil s results for the periods indicated: Three months ended Year ended ($000s) % change % change Revenue 19,636 26,514 (26) 88,198 89,994 (2) Operating expenses 12,420 14,943 (17) 55,617 56,285 (1) Divisional EBITDA 7,216 11,571 (38) 32,581 33,709 (3) Divisional EBITDA as % of revenue 37% 44% 37% 37% Depreciation and amortization 6,330 8,293 (24) 25,278 24,317 4 Restructuring and other expense - 46 (100) (100) Impairment - 45,467 (100) - 45,467 (100) Net earnings before taxes 886 (42,235) (102) 7,303 (36,878) (120) Maintenance capital 868 1,494 (42) 1,483 2,683 (45) Growth capital (96) (70) Assets employed (1) 183, ,268 (11) (1) Assets employed is provided to assist management and investors in determining the effectiveness of the use of the assets at a divisional level. Assets employed is the sum of capital assets, intangible assets and goodwill allocated to each division. Assets employed as defined does not include capital assets held by Corporate. Corporate assets include information technology and leasehold improvements. Heavy Oil revenue in the quarter decreased by 26% over prior year to $19.6 million, driven by a decrease in SAGD and recovered crude volumes received at our facilities and lower contributions from Onsite. Net earnings before taxes in the quarter were $0.9 million, a $43.1 million improvement from prior year primarily due to impairment recognized in Divisional EBITDA decreased 38% over prior year to $7.2 million primarily due to decreased contributions from our Facilities business unit. In 2017, Heavy Oil revenue remained flat to the prior year at $88.2 million, as increased demand for project work in Onsite and higher commodity prices were offset by a decrease in SAGD and recovered crude volumes received at our facilities. Net earnings before taxes for the year were $7.3 million, an improvement of $44.2 million over prior year primarily driven by the same factor as the quarter. Divisional EBITDA of $32.6 million was flat to the prior year as increased contributions from Onsite were offset by decreased contributions from Facilities. Contract revenue generated approximately 49% of Heavy Oil revenue in

16 HEAVY OIL FACILITIES Revenue for the quarter decreased by 34% as the waste volumes received at our facilities and recovered crude oil volumes declined from prior year. Production waste volumes for the quarter declined approximately 16% over prior year, with an increase in CHOPS volumes being more than offset by a reduction in event-based SAGD volumes. We continue to see steady improvements in CHOPS volumes, with Q4 continuing the 2017 trend of year-over-year improvements. A change in waste mix toward lower oil content waste streams resulted in a 60% reduction in recovered crude oil volumes in the quarter compared to the prior year. In 2017, revenue decreased by 15% over prior year primarily due to lower event-based SAGD waste volumes received at our facilities. Production waste volumes received at our facilities were down year-over-year by approximately 13%, with an increase in CHOPS volumes being more than offset by lower event-based SAGD volumes. The year-over-year increase in oil price partially mitigated the impact of the decline in recovered crude oil volumes. Heavy Oil Facilities Metrics and Industry Drivers Three months ended Year ended % change % change Recovered crude oil ( 000 bbl) (1) (60) (46) Average crude oil price received (CDN$/bbl) Recovered crude oil sales ($ millions) (53) (30) Western Canadian Select (CDN$/bbl) (2) (1) Represents the total crude oil recovered and sold for our account. (2) WCS is a readily available industry benchmark for heavy crude oil. 16

17 ONSITE Revenue for the quarter decreased 18% over prior year as increased demand for project work was more than offset by the conclusion of a long-term contract operating a full-scale MFT facility. In 2017, Onsite revenue increased by 9% over prior year due to increased demand for project work and the recovery of the impact from the 2016 Fort McMurray wildfires, partially offset by lower contributions from mining contracts. We continue to see demand for onsite projects improve as crude oil prices and activity levels stabilize. Onsite Metrics Three months ended Year ended Percentage point change Percentage point change Contract revenue as % of Onsite revenue 76% 85% (9) 76% 84% (8) RESULTS OF OPERATIONS OILFIELD The Oilfield division is organized into two business units, Facilities and Drilling Services. The business units contributed the following to division revenue: Three months ended Year ended Facilities 59% 65% 62% 70% Drilling Services 41% 35% 38% 30% 17

18 The following table compares Oilfield s results for the periods indicated: Three months ended Year ended ($000s) % change % change Revenue 42,104 37, , , Operating expenses 30,821 29, ,247 96, Divisional EBITDA 11,283 7, ,967 19, Divisional EBITDA as % of revenue 27% 20% 25% 17% Depreciation and amortization 8,033 6, ,868 24, Restructuring and other expense (100) - 4,812 (100) Impairment - 10,562 (100) - 10,562 (100) Net earnings (loss) before taxes 3,250 (9,545) (134) 10,099 (20,438) (149) Maintenance capital 2,244 2,507 (10) 7,042 5, Growth capital (1) 1,452 2,394 (39) 3,213 4,930 (35) Assets employed (2) 429, ,419 (1) (1) Growth capital expenditures are net of 2016 contributions from a midstream joint venture partner for its interest in an MPF. (2) Assets employed is provided to assist management and investors in determining the effectiveness of the use of the assets at a divisional level. Assets employed is the sum of capital assets, intangible assets and goodwill allocated to each division. Assets employed as defined does not include capital assets held by Corporate. Corporate assets include information technology and leasehold improvements. Oilfield revenue in the quarter increased 13% over prior year to $42.1 million primarily driven by improvements in Drilling Services. Net earnings before taxes in the quarter were $3.3 million, a $12.8 million improvement over prior year. The improvement was primarily driven by impairment recognized in 2016 as well as increased contributions from the Drilling Services business unit, partially offset by higher depreciation and amortization expense. Divisional EBITDA increased by 48% over prior year to $11.3 million, primarily as a result of improved drilling activity. In 2017, Oilfield revenue increased by 37% over prior year to $158.2 million due to improvements in both Drilling Services and Facilities. Net earnings before taxes for the year were $10.1 million, a $30.5 million improvement over prior year driven by the same factors as the quarter as well as reduced restructuring and other expense. Divisional EBITDA increased by 108% to $40.0 million primarily due to the same factors as the quarter. Divisional EBITDA margins improved by eight percentage points over prior year. OILFIELD FACILITIES In Canada, we have an integrated network of facilities serving the Western Canadian Sedimentary Basin throughout British Columbia, Alberta and Saskatchewan. In the U.S., we provide services through our modular processing facilities in the Bakken play. Three months ended Year ended Revenue generated by country Canada 95% 98% 95% 96% U.S. 5% 2% 5% 4% THE FOLLOWING TABLE DESCRIBES OUR OILFIELD FACILITIES BUSINESS UNIT: Facilities revenue in the quarter remained flat to the prior year. Increases in both recovered crude oil sales and drilling and production waste volumes received at our Canadian and U.S. facilities were offset by a decline in midstream services. In 2017, Facilities revenue increased by 22% compared to prior year driven by the same factors as the quarter as well as higher oil prices received. Drilling and production waste volumes received into our Canadian and U.S. Facilities increased by approximately 41% over prior year. 18

19 Oilfield Facilities Metrics and Industry Drivers Canadian Facilities Three months ended Year ended % change % change Recovered crude oil ( 000 bbl) (1) Average crude oil price received (CDN$/bbl) Recovered crude oil sales ($ millions) Canadian Light Sweet par price (CDN$/bbl) (2) U.S. Facilities Recovered crude oil ( 000 bbl) (1) (33) Average crude oil price received (CDN$/bbl) Recovered crude oil sales ($ millions) West Texas Intermediate par price (CDN$/bbl) (3) (1) Represents the total crude oil recovered and sold for our account. (2) CLS is a readily available industry benchmark for conventional crude oil. (3) WTI is a readily available industry benchmark for conventional crude oil sold in the U.S. 19

20 DRILLING SERVICES Drilling Services includes Drill Site Services as well as our Environmental Services. We serve the oil and gas industry in western Canada and the U.S., with operations primarily in the Marcellus/Utica, Bakken, Eagleford, Niobrara and Permian plays. Drill Site Services generates between 70% and 80% of annual Drilling Services revenue. Three months ended Year ended Revenue generated by country Canada 34% 42% 28% 42% U.S. 66% 58% 72% 58% Q4 and full year 2017 Drilling Services revenue increased by 34% and 73%, respectively compared to prior year. The improvement was primarily driven by our U.S. Drill Site operations due to an increase in active rigs in the areas we serve and our focus on enhanced customer value creation. For the three months and year ended 2017, utilization in Drill Site increased by 21 and 24 percentage points respectively, over prior year. Three months ended Percentage point change Year ended Percentage point change Drill Site utilization Canada 37% 13% 24 26% 8% 18 Drill Site utilization U.S. 51% 33% 18 48% 21% 27 Total Drill Site utilization 47% 26% 21 40% 16% 24 Average equipment available (1) (1) Average equipment available is the average number of units available to be deployed during the period. 20

21 CORPORATE AND OTHER Three months ended Year ended ($000s) % change % change General and administrative expenses 6,934 7,690 (10) 27,919 31,060 (10) G&A as % of revenue 11% 12% 11% 15% Stock-based compensation (627) 3,849 (116) Impairment - 56,030 (100) - 60,749 (100) Restructuring and other (recovery) expense (1) (1,328) (9,567) (86) (3,556) 22,300 (116) Finance charges (1) 7,453 7, ,592 28,233 5 Embedded derivatives (gain) loss (100) (11) n/m (135) 1,527 (109) Total Corporate and Other Expenses 13,420 61,621 (78) 53, ,718 (64) (1) Certain prior period comparative figures have been reclassified to conform to current year presentation. The following section outlines the material changes in Corporate and Other expenses. G&A G&A expenses decreased by 10% over prior year to $6.9 million and $27.9 million for the three months and year ended The year-over-year improvement was driven by a full year realization of the cost rationalization initiatives undertaken in the first half of 2016 and our disciplined approach to maintaining the benefit of those initiatives. We will continue prudent management of our overheads. Stock-Based Compensation Stock-based compensation was an expense of $0.5 million and a recovery of $0.6 million for the three months and year ended 2017, respectively. Cash stock-based compensation expense for the quarter and year were nil and $0.5 million, respectively, compared to $0.1 million and $0.3 million for the same periods in the prior year. Stock-based compensation expense and/or recovery fluctuates based on the effects of vesting, normal course expiries of previous grants and volatility in our share price. Restructuring and Other (Recovery) Expense Restructuring and other recovery was $1.3 million and $3.6 million for the three months and year ended 2017, compared to a recovery of $9.6 million and expense of $22.3 million for the same periods in the prior year. The recoveries in the quarter and full year 2017 were primarily comprised of a decrease to the non-cash decommissioning liabilities related to inactive sites, partially offset by a fair value loss on a held-for-trading investment. The full year was also impacted by a recovery in the onerous contracts expense. For further information, see Note 5 to the Financial Statements. Finance Charges Three months ended Year ended ($000s) % change % change Bank fees and interest 1,891 1, ,384 6, Debenture interest, amortization of issue costs, and other Finance charges before unwinding of the discount (1) 4,797 4,820-19,256 19,279-6,688 6, ,640 25,280 5 Unwinding of the discount (2)(3) ,952 2,953 - Finance charges (3) 7,453 7, ,592 28,233 5 (1) Reflects capitalized interest of $6 and $21 for Q4 and 2017, respectively (nil and $80, respectively in 2016). (2) Relates primarily to decommissioning liability. (3) Certain prior period comparative figures have been reclassified to conform to current year presentation. 21