Osum Oil Sands Corp. · 2020. 6. 25. · 2017 Annual Report Page Review and Outlook 5 Management's Discussion and Analysis 8 Report of Management 40 ... generation capacity of up

Osum Oil Sands Corp.2017 Annual Report to Shareholders

Dated March 13, 2018

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2017 Annual Report Page

Review and Outlook 5Management's Discussion and Analysis 8Report of Management 40Independent Auditor's Report 41Consolidated Financial Statements 42Notes to the Consolidated Financial Statements 46Corporate Information 75


Review and Outlook2017 Annual Review

Prudent and disciplined management through a challenging business environment in 2015 and 2016positioned Osum for a transformative year in 2017 that included a significant financing, the completion ofan expansion at Orion, and the sanctioning of an additional fully funded expansion that is expected todouble production to 18,000 bbl/d by late 2019. Supported by an improved commodity price environment,2017 operating results significantly exceeded those of the prior year and the Company exited 2017 withrecord quarterly average production and its highest quarterly netback since 2014.

Points of note for 2017 included:

• Completion of Orion Phase 2A expansion: The Phase 2A expansion that began in 2016 with theinstallation of a 3rd boiler was completed in 2017 on time and on budget and the new wells areexpected to add 1,500 bbl/d of production in 2018, bringing total production capacity to around 9,000bbl/d. Following steam circulation, all three Phase 2A wells were on production in Q4 2017 andreached peak rates ahead of schedule. The waste crystallizer unit was commissioned near the endof 2017 and is performing as anticipated.

• Significant financing through the sale of a royalty: Osum, through its wholly-owned subsidiary, OsumProduction Corp., completed the sale of a 4.0% gross overriding royalty interest ("GORR") on Orionto Franco-Nevada Corporation for cash proceeds of $92.5 million, before transaction costs andadjustments. The GORR sale closed on September 29, 2017. The royalty applies to bitumen salesfrom the Orion project, including any future development within the Orion leases. The GORR saleproceeds bolstered the Company's cash position, enabling the accelerated expansion of Orion.

• Commencement of Orion Phase 2BC: Coincident with the GORR sale, in October 2017 Osumannounced the commencement of Phase 2B, a 3,000 bbl/d expansion of its Orion facility. Then inDecember 2017, in order to accelerate the pace of development and capitalize on drilling andconstruction efficiencies, Osum commenced the follow-on Phase 2C. The two phases are now beingexecuted concurrently in a consolidated program termed Phase 2BC. The combined expansionincludes the installation from existing inventory of a 4th boiler and 3rd and 4th evaporators (seepicture on page 6), along with other processing equipment and infrastructure to support steamgeneration capacity of up to 10,000 m3/d and production from 18 new horizontal SAGD well pairsdrilled. After steaming and full ramp-up of the new wells, production at Orion is expected to double to18,000 bbl/d in late 2019 from a total of 43 well pairs.

• Record production: Average annual production at Orion of 8,100 bbl/d in 2017 was 12% higher thanthe 7,256 bbl/d in the prior year. The increase was partly due to contributions in Q4 2017 from thethree new Phase 2A well pairs. On the strength of the new wells, Orion achieved record averagequarterly production of 9,306 bbl/d in Q4 2017.

• Higher average realized bitumen price: The average realized bitumen price in 2017 of $39.43/bblwas up $10.26/bbl or 35% from the prior year. The increase reflected a higher average price forWest Texas Intermediate crude oil ("WTI") and a narrowing in the differential between WTI and theprice of Cold Lake Blend, partially mitigated by a strengthening of the Canadian dollar.

2017 Annual Report 5

• Steady unit operating costs despite significantly higher steam volumes: Average unit operating costsin 2017 of $18.03/bbl were slightly lower than the prior year, improving by 3% or $0.56/bbl. Thedecrease reflected a 2% or $0.36/bbl reduction in average non-fuel operating costs to $14.27/bbl,and a 5% or $0.20/bbl decrease in fuel operating costs to $3.76/bbl, mainly due to a lower averagenatural gas price.

• More than a doubling of total netback: The 2017 field netback of $59.1 million or $19.97/bbl was$32.2 million or $9.85/bbl higher than a field netback of $26.9 million or $10.12/bbl in the prior year.Orion's Q4 2017 netback of $21.3 million was the highest total quarterly netback of the past threeyears.

• Realized hedging losses but program achieving its objectives: During 2017, Osum continued toexecute its strategy of methodically locking in forward prices, quarter by quarter, to manage cashflow volatility and improve predictability. Financial hedges that settled in 2017 were entered intoduring 2016 when oil prices were generally lower and resulted in realized net losses of $7.9 millionor $2.68/bbl. Conversely, in 2016, net financial hedging gains totaled $14.7 million or $5.55/bbl, duelargely to gains of $13.3 million recorded in Q1 2016 when the average WTI price plummeted to US$33.52/bbl. The effectiveness of the program in managing volatility and smoothing cash flow wasdemonstrated by a year-over-year increase in the netback of only 10% after adjusting for hedging,compared with a 97% increase before hedging. At December 31, 2017, the Company's netunrealized hedging liabilities were $0.3 million.

• Continued focus on reducing overhead costs: Net general and administrative expenses were $13.3million, down 21% from $16.8 million in the prior year. The decrease mainly reflected the impact ofhead office staff reductions in both 2016 and 2017, combined with ongoing efforts to limit spendingand preserve non-producing assets at a minimum cost.

• Spending focused on growth with low sustaining capital: Capital expenditures in 2017 were $74.4million, of which $64.8 million related to Orion facility expansion projects, including Phases 2A and2BC.

• Funded to fully execute Orion Phase 2BC: With the receipt of the GORR sale proceeds, Osum iswell-capitalized to fund its Orion Phase 2BC expansion. At December 31, 2017, cash on hand was$230.5 million and net working capital, excluding the current portions of net unrealized hedgingliabilities and deferred consideration, totaled $213.2 million.

Outlook

Through 2016 and 2017, Osum established a strong track record of project execution, meeting cost andschedule targets while executing Phase 2A and maintaining base operations with a strong safety record.This success helped set the stage for Phase 2BC, which provides very strong incremental economics andcapital efficiencies, quick execution and measurable benefits. The expansion is well underway with twodrilling rigs operating in the field through the winter and spring. Steaming of the first six wells is expectedby mid-2018 with the remainder to follow through Q3 when the 4th boiler is brought on stream. The newwells are forecast to begin to contribute to production in Q4 and should lead to 2018 exit production ofover 11,000 bbl/d. However, the full impact of all new well pairs will not be realized until late 2019.

While there is considerable focus on drilling and construction activities, the safe and efficient operation ofexisting wells and base production continue to be of paramount importance. Osum's hedging programsupports this effort by protecting operating cash flows through the construction period. In anticipation of


the decision to move ahead with Phase 2C, in December Osum increased its hedging target from 60% to70% of projected 2018 production, net of royalties.

With the full ramp-up of production from Phase 2BC complete in late 2019 or early 2020, Osum expectsto be strategically and financially better positioned with materially lower unit operating and overhead costsresulting in improved business sustainability at lower commodity prices. Beyond that, the Company hasother growth opportunities in the Cold Lake area both at Orion and its wholly-owned Taiga project, whichhas regulatory approval for production of 35,000 bbl/d.

The picture above depicts construction progress of the Phase 2BC evaporator package at Orion on January 26, 2018, with theerection of the last of four new towers in the foreground and the operational Phase 1 evaporator towers in the background. The twotaller towers in the centre are evaporator vessels, the second of which is being raised by tandem crane lifts, and the smaller towerson the outside are vapour separators. The safe and successful completion of this activity was a critical milestone for the Phase 2BCprogram.


Management’s Discussion and AnalysisThe following management’s discussion and analysis (“MD&A”) of financial results is dated March 13,2018 and is to be read in conjunction with the accompanying audited annual consolidated financialstatements and related notes for the year ended December 31, 2017 of Osum Oil Sands Corp. (“Osum”or "the Company”). The consolidated financial statements for the year ended December 31, 2017 havebeen prepared in accordance with International Financial Reporting Standards ("IFRS"). All amounts areexpressed in thousands of Canadian dollars ("C$") unless otherwise specified.

Nature of Business

Osum is a private company principally focused on the development and operation of in-situ bitumenproperties in Alberta, Canada. Since inception, Osum has concentrated its efforts on: acquiringprospective oil sands properties; developing those properties into projects; and securing the financial andhuman resources required to construct and operate those projects.

The Company's wholly-owned Orion oil sands project (“Orion”) is a producing in-situ project in the ColdLake oil sands area of Alberta and represents the Company’s only commercial production. The Companyalso has a 100% interest in five other potential development projects: Taiga (also in Cold Lake), SepikoKesik ("SK"), Saleski West, Liege and Portage, as well as a 40% non-operated interest in the Saleski jointventure.

Non-IFRS Financial Measures

This document includes references to financial measures commonly used in the oil and gas industry, suchas adjusted working capital, netback, adjusted netback and funds flow, as well as adjusted working capitalplus capital from outstanding callable warrants. These financial measures are not defined by IFRS asissued by the International Accounting Standards Board ("IASB") and therefore are referred to as non-IFRS measures. The non-IFRS measures used by the Company may not be comparable to similarmeasures presented by other companies. The Company uses these non-IFRS measures to help evaluateits performance.

Reconciliations of the non-IFRS measures to comparable IFRS measures are provided below:

Adjusted working capital and adjusted working capital plus available capital from outstanding callablewarrants

In describing its liquidity and financial resources, the Company makes reference to adjusted workingcapital and adjusted working capital plus available capital from outstanding callable warrants. Thesemeasures are not based on IFRS, but are terms specific to the Company and its capital structure.

Adjusted working capital is equal to working capital, an IFRS measure, adjusted to exclude the currentportions of financial risk management contract assets and liabilities, which are fair value estimates ofunrealized gains and losses and are subject to a high degree of volatility prior to ultimate settlement, anddeferred consideration, which is not cash-settled. Management included available capital fromoutstanding callable warrants in its representation of liquidity and financial resources in 2016 because theterms of the callable warrant agreements were structured such that the exercise of the warrants on callwas more likely to occur than not. The Company called the warrants in December of 2016 and receivedthe cash proceeds in February of 2017.


A reconciliation of each measure to working capital, an IFRS measure, is provided below:

As at December 31, 2017 2016Working capital 212,565 66,133Add: current portion of deferred consideration 1,336 —Deduct: current portion of risk management contracts 740 10,553Adjusted working capital 214,641 76,686Available capital from outstanding callable warrants — 100,000Adjusted working capital plus available capital fromoutstanding callable warrants 214,641 176,686

Netback and adjusted netback

The Company reports netback and adjusted netback measures to evaluate operating efficiency and itsability to fund future growth. Netback is calculated by deducting the related diluent, transportation,royalties and field operating costs from blend sales revenue. Adjusted netback is calculated by adjustingthe netback to include realized gains and losses on financial risk management contracts. Each netbackon a per-unit basis is calculated by dividing by bitumen production. Though widely used in the oil and gasindustry, these or similar measures do not have standardized meanings prescribed by IFRS and thereforemay not be comparable to similar measures used by other companies. A reconciliation of each measureto net loss, an IFRS measure, is provided below:

For the year ended December 31, 2017 2016Net and comprehensive loss (157,017) (48,617)Add (deduct):

Depletion, depreciation and impairment 218,841 7,477Net finance costs 17,556 17,878General and administrative expenses 13,335 16,812Deferred income tax expense (906) 15,853Share-based compensation expense 4,075 5,428Accretion 671 548Exploration costs 20 93Gain on disposition of property, plant and equipment (14,922) —Unrealized foreign exchange gain (17,784) (8,296)Gain (loss) on risk management contracts (4,071) 16,242Onerous contract expense (recovery) (380) 3,445Deferred consideration (353) —

Netback 59,065 26,863Realized net gain (loss) on financial risk management contracts (7,914) 14,744Adjusted netback 51,151 41,607

Funds flow

Funds flow is calculated as cash flows from operating activities before changes in non-cash operatingworking capital, which is presented on the consolidated statement of cash flows. The Company considersit a key measure as it is indicative of the funds available for re-investment or to maintain the operations ofthe Company.


Funds flow is not intended to represent operating profit (loss), nor should it be viewed as an alternative tocash flows from operating activities, net income (loss) or other measures of financial performancecalculated in accordance with IFRS. The Company’s funds flow is reconciled to cash flows from operatingactivities, an IFRS measure, below:

For the year ended December 31, 2017 2016Cash flows from operating activities 18,398 6,451Less: Changes in non-cash operating working capital (1,953) (332)Funds flow 20,351 6,783


Bitumen Reserves

The Company's bitumen reserves related to its Orion and Taiga projects were evaluated by independentthird-party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") in their report effective December 31,2017. Bitumen reserves estimates were prepared in accordance with definitions, standards andprocedures contained in the Canadian Oil and Gas Evaluation Handbook.

Future net revenue arising from the anticipated development and production of reserves, net of theassociated royalties (inclusive of the gross overriding royalty ("GORR")), was estimated by GLJ usingforecast prices, operating costs, development costs and abandonment and reclamation costs, but beforecorporate overhead or other indirect costs, including interest and income taxes. Future net revenuedisclosed does not represent fair market value. Also, estimations of reserves and future net revenuediscussed in this section constitute forward looking information. See "Forward-Looking Statements" in thisMD&A.

The following table compares bitumen reserves and the net present value of future net revenue at a 10%discount rate as at December 31, 2017 and December 31, 2016:

Bitumen Reserves – Gross(Mbbl)

Net Present Value of FutureNet Revenue at 10% –

Before Taxes ($ millions)As at December 31, 2017(1) 2016(2) % 2017(1) 2016(2) %Total proved (3) 117,779 47,650 147% 957 436 119%Total proved plus probable (3)(4) 537,331 507,546 6% 1,890 1,873 1%

(1) GLJ reserve estimates based on forecast prices and costs as of January 1, 2018, effective December 31, 2017.(2) GLJ reserve estimates based on forecast prices and costs as of January 1, 2017, effective December 31, 2016.(3) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the

actual remaining quantities recovered will exceed the estimated proved reserves.(4) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that

the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Estimated proved bitumen reserves ("1P reserves") assigned to the Orion project increased by 70,129thousand barrels (Mbbl) or 147% to 117,779 Mbbl at December 31, 2017, mainly due to the execution ofPhase 2A and the sanctioning and execution of Phase 2BC, which resulted in all of the reservoir withinthe approved development area becoming 1P reserves. The increase was net of 2017 production of2,957 Mbbl.

The ten percent present value of estimated future net revenue ("PV10") of 1P reserves wasapproximately $957 million at December 31, 2017, an increase of 119% from December 31, 2016. Theincrease was largely due to the increase in 1P reserves, partially offset by lower forecast commodityprices.

Estimated proved plus probable bitumen reserves ("2P reserves") assigned to both the Orion and Taigaprojects increased by 29,785 Mbbl or 6% to 537,331 Mbbl at December 31, 2017. The increase in 2Preserves related to Orion and reflected the continued strong performance of Orion and SAGD analogues.

The PV10 of 2P reserves of approximately $1,890 million at December 31, 2017 was largely unchangedfrom $1,873 million at December 31, 2016, as the positive impact of higher 2P reserves was offset bylower forecast commodity prices.

The following table displays gross bitumen reserves and bitumen reserves net of forecast royalties(inclusive of the GORR), along with the present values of estimated future net revenue using a range ofdiscount rates at December 31, 2017:

Bitumen Reserves(1) – (Mbbl)

Net Present Value of Future Net Revenue –Before Taxes ($millions)

Forecast Prices and CostsGross Net 0% 5% 10% 15% 20%

Total proved (2) (1P) 117,779 92,487 2,430 1,478 957 656 471Total proved plus probable (2)(3) (2P) 537,331 447,144 9,723 4,020 1,890 970 523

(1) GLJ reserve estimates based on forecast prices and costs as of January 1, 2018, effective December 31, 2017.(2) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the

actual remaining quantities recovered will exceed the estimated proved reserves.(3) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that

the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

GLJ's pricing assumptions used in its December 31, 2017 evaluation are summarized below:

Year

WesternCanadian

Select (C$/bbl)WTI at Cushing

(US$/bbl)

Diluent(condensate)

(C$/bbl)AECO gas

(C$/mmbtu)Exchange rate

(US$/C$)2018 48.89 59.00 76.42 2.20 0.792019 53.16 59.00 74.68 2.54 0.792020 56.25 60.00 74.38 2.88 0.802021 59.26 63.00 77.16 3.24 0.812022 62.20 66.00 79.88 3.47 0.822023 65.06 69.00 82.53 3.58 0.832024 68.67 72.00 86.14 3.66 0.832025 72.29 75.00 89.76 3.73 0.832026 75.10 77.33 92.57 3.80 0.832027 76.96 78.88 94.43 3.88 0.83Remainder +2.0% per year +2.0% per year +2.0% per year +2.0% per year 0.83


Financial and Operational Summary

For the years ended December 31, 2017 2016Business Environment (1)

West Texas Intermediate (WTI) – US$/bbl 50.85 43.37Cold Lake Blend (CLB) – US$/bbl 38.20 28.61Differential – WTI less CLB – US$/bbl 12.65 14.76Differential – CLB % of WTI 24.9% 34.0%Foreign exchange rate – C$/US$ 1.2979 1.3256CLB – $/bbl 49.58 37.93AECO – $/mcf 2.04 2.05

Operational (1) (2)

Bitumen production – bbl/d 8,100 7,256Blended bitumen sales (3) – bbl/d 11,037 9,864

Blended bitumen sales less diluent and transportation costs (3) – $/bbl 39.43 29.17Royalties – $/bbl (1.43) (0.46)Non-fuel operating costs – $/bbl (14.27) (14.63)Fuel costs – $/bbl (3.76) (3.96)Netback (3) (4) – $/bbl 19.97 10.12Realized gain (loss) on financial risk management contracts – $/bbl (2.68) 5.55Adjusted netback (3) (4) – $/bbl 17.29 15.67

FinancialNetback (3) (4) 59,065 26,863Adjusted netback (3) (4) 51,151 41,607Funds flow (5) 20,351 6,783Cash flows from operating activities 18,398 6,451Net and comprehensive loss (157,017) (48,617)Net loss per share (basic and diluted) – $ (1.21) (0.40)Capital investment (6) 74,355 25,996General and administrative expenses (net) (7) 13,335 16,812

Cash and cash equivalents (8) 230,463 83,525Adjusted working capital (9) 213,161 76,686Adjusted working capital plus available capital from outstanding callable warrants (9)(10) 213,161 176,686Outstanding principal – long-term debt (11) 252,812 273,108Shareholders' equity 328,639 383,350Weighted average common shares outstanding 130,119 122,485

See footnotes on the next page.


(1) Business environment and operational metrics are averages for the period.(2) Dollar per barrel metrics are calculated based on bitumen production volumes. Year-over-year per barrel metrics may be affected

by differences between the timing of bitumen production and blended bitumen sales.(3) Blended bitumen sales, blended bitumen sales less diluent and transportation costs, netback and adjusted netback include any

realized gains and losses on physical risk management contracts.(4) Netback is calculated by deducting the related diluent, transportation, royalties and field operating costs from blend sales revenue.

Adjusted netback is calculated by adjusting the netback to include realized gains and losses on financial risk managementcontracts.

(5) Funds flow is calculated as cash flows from operating activities before changes in non-cash operating working capital, which ispresented on the consolidated statement of cash flows.

(6) Capital investment includes capitalized general and administrative expenses but excludes capitalized stock-based compensationexpense.

(7) General and administrative expenses (net) is calculated after reductions for capitalized salaries and benefits, onerous leasepayments and exploration costs.

(8) Cash and cash equivalents include restricted cash.(9) Adjusted working capital is calculated as working capital adjusted to exclude the current portions of risk management contracts,

which are fair value estimates of unrealized gains and losses and are subject to a high degree of volatility prior to ultimatesettlement, and deferred consideration, which is not cash-settled.

(10) In 2016, adjusted working capital plus available capital from outstanding callable warrants included $100,000 associated withthe aggregate exercise value of 8,000,000 outstanding callable common share purchase warrants. On December 1, 2016 theCompany called all of the outstanding callable common share purchase warrants and the proceeds were received in Februaryof 2017.

(11) Outstanding principal of long-term debt consists of the non-current portion of the outstanding principal balance of the US$210,000term loan and any amounts outstanding under the US$15,000 revolving loan, translated to Canadian dollars at the period-endforeign exchange rate and presented before unamortized transaction costs.


Results of Operations

Netback and adjusted netback

For the years ended December 31, 2017 2016Production – bbl/d 8,100 7,256Blended bitumen sales – bbl/d 11,037 9,864

($000s) $/bbl ($000s) $/bblBlended bitumen sales 198,804 137,292Diluent and transportation costs 82,215 59,831Blended bitumen sales less diluent and transportation costs 116,589 39.43 77,461 29.17Royalties (4,218) (1.43) (1,232) (0.46)Operating costs – fuel (11,122) (3.76) (10,515) (3.96)Operating costs – non-fuel (42,184) (14.27) (38,851) (14.63)Netback 59,065 19.97 26,863 10.12Realized gain (loss) on financial risk management contracts (7,914) (2.68) 14,744 5.55Adjusted netback 51,151 17.29 41,607 15.67

Production

For the year ended December 31, 2017, daily bitumen production averaged 8,100 bbl/d, 12% higher thanaverage production for the year ended December 31, 2016 of 7,256 bbl/d. The increase was partly due tocontributions in Q4 2017 from the three new Phase 2A well pairs, along with more consistent reservoirperformance during the year. On the strength of the new wells, Orion achieved record average quarterlyproduction of 9,306 bbl/d in Q4 2017.

Blended bitumen sales

Bitumen produced at Orion is mixed with purchased diluent and marketed as a heavy crude oil blendknown as Cold Lake Blend ("CLB"). CLB is priced in US dollars ("US$") and generally trades at a discountto the price of West Texas Intermediate crude oil ("WTI"). As a result, the price received by the Companyfor its blended bitumen is a function of a number of factors, including the WTI price, the size of thedifferential between WTI and CLB, and the US$/C$ exchange rate.

For the year ended December 31, 2017, blended bitumen sales increased 45% to $198,804 comparedwith $137,292 in the prior year. The increase mainly reflected a 12% increase in blended bitumen salesvolumes to an average of 11,037 bbl/d from 9,864 bbl/d in the previous year and an increase of 31% inthe average C$ CLB price. The Company did not have any physical risk management gains or lossesrecorded within blended bitumen sales for the year ended December 31, 2017, compared with losses of$70 in the prior year.

Diluent and transportation costs

Condensate is a diluent that is purchased and added to produced bitumen to create a less viscousblended bitumen stream capable of being transported by pipeline. Generally, the price of condensate isclosely tied to the price of WTI.

For the year ended December 31, 2017, diluent and transportation costs were $82,215, compared with$59,831 in the prior year. The increase of $22,384 or 37% was mainly the result of a 12% increase inaverage daily bitumen production, which led to a 13% increase in condensate usage, and a 15% increase


in the average price of WTI in C$, which resulted in a similar percentage increase in the price ofpurchased condensate.

Royalties

A portion of the Company’s royalty expense is based on price-sensitive royalty rates set by theGovernment of Alberta. As well, the applicable royalty rate changes depending on whether a project ispre-payout or post-payout, with payout being defined as the point in time when a project has generatedsufficient net revenues to recover its cumulative costs and a rate of return. The Company's operatingproperty, Orion, is currently pre-payout. The royalty rate applicable to pre-payout oil sands operationsstarts at 1% of bitumen sales and increases proportionately for every dollar that WTI in C$ is pricedabove $55 per barrel, to a maximum of 9% when the price is $120 per barrel or higher.

In addition to crown royalties, for the year ended December 31, 2017 the Company's royalties included agross overriding royalty of 4% of calculated bitumen revenue generated subsequent to the closing of theGORR sale on September 29, 2017.

For the year ended December 31, 2017, total royalties were $4,218 translating to an average royalty rateof 3.6%, compared with a royalty rate of 1.6% for the year ended December 31, 2016. For the year endedDecember 31, 2017, crown royalties to the Government of Alberta were $2,725 or 2.3% of blendedbitumen revenue less diluent and transportation costs, compared with $1,232 or 1.6% in the prior year.The increase in the provincial royalty rate resulted from a higher average C$ WTI price. For the yearended December 31, 2017, gross overriding royalties were $1,493 (2016 – nil).

Operating expenses

For the year ended December 31, 2017, non-fuel operating costs were $42,184 or $14.27/bbl, comparedwith $38,851 or $14.63/bbl in the prior year, an increase of 9% overall but a 2% decrease on a per barrelbasis. The increase in total non-fuel operating costs largely resulted from higher variable costs such asthose related to chemicals, utilities and waste disposal, driven by an increase in steam, production, wellsand equipment from the Phase 2A expansion. The decrease in non-fuel unit operating costs mainlyreflected the project's fixed costs being spread over a higher production volume.

For the year ended December 31, 2017, fuel operating costs were $11,122 or $3.76/bbl, compared with$10,515 or $3.96/bbl in the previous year, an increase of 6% overall and a decrease of 5% on a per barrelbasis. The increase in total fuel costs for 2017 resulted from higher gas usage related to the operation ofthe 3rd boiler, which contributed to an 18% increase in year-over-year steam injection. The increasedusage was partially offset by an 8% decrease in the average AECO gas price.

Realized gain (loss) on risk management contracts

Financial hedges that settled in 2017 were entered into during 2016 when oil prices were generally lowerand resulted in realized net losses of $7,914 or $2.68/bbl. Conversely, in 2016, net financial hedginggains totaled $14,744 or $5.55/bbl, due largely to gains of $13,347 recorded in Q1 2016 when theaverage WTI price plummeted to US$33.52/bbl.


Deferred consideration

On September 29, 2017, the Company sold a 4.0% GORR on its Orion property for cash proceeds of$92,500, before transaction costs and adjustments. At the time of the sale, the Company recordeddeferred consideration of $64,400 in its consolidated statement of financial position, representing thepresent value of then estimated future costs expected to be incurred in relation to future production of theGORR owner's share of proved plus probable reserves. Deferred consideration was recognized inrevenue based on the ratio of production in the period to the estimate of proved plus probable reserves ineffect at the end of the period, adjusted for production during the period.

Deferred consideration of $353 was recorded as revenue during the year ended December 31, 2017(2016 – nil).

Change in fair value of financial risk management contracts

For the year ended December 31, 2017, the Company recorded an unrealized gain on financial riskmanagement contracts of $11,985, compared with a loss of $30,374 in the previous year.

The gain and loss reflected the net change in the value of the Company's financial risk managementcontracts due to the changes in the C$ WTI price and WTI/WCS differential forward curves from thecontract execution dates to the reporting dates, adjusted for contracts settled or entered into between thereporting dates.

Depletion, depreciation and impairment

Depletion and Depreciation

The Company’s producing oil sands property, Orion, is depleted on a unit of production basis based onindependently estimated proved and probable reserves. For the year ended December 31, 2017,depletion and depreciation totaled $34,945, compared with $40,477 in the prior year. The averagedepletion rate for 2017 of $11.58/bbl at Orion was lower than $14.68/bbl in the prior year largely due tothe full year impact in 2017 of higher proved plus probable reserves and lower estimated futuredevelopment costs in the December 31, 2016 reserve evaluation compared with the December 31, 2015evaluation used in the depletion calculations for the first three quarters of 2016.

Impairment

Property, plant and equipment ("PP&E") assets

During 2017 the Company observed a decline in the average long-term price forecasts of a number ofreserve engineering firms. The Company considered the price forecast decline an indicator of impairmentfor its Taiga CGU and performed an impairment test at December 31, 2017.


The Company estimated the recoverable amount of its Taiga CGU based on fair value less costs ofdisposal calculations. The fair value of the CGU was estimated based on the present value of after-taxcash flows resulting from production from proved and probable reserves from 2018 to 2066 usingassumptions consistent with those used by the Company’s independent reserve evaluator, includingcapital and operating cost estimates, corporate tax rates, and a cost inflation factor of two percent, andusing an after-tax discount rate of 12%. The following forward prices and foreign exchange rates wereused to estimate the recoverable amount as at December 31, 2017:

Year

WesternCanadian Select

(C$/bbl)WTI at Cushing

(US$/bbl)

Diluent(condensate)

(C$/bbl)AECO gas


(US$/C$)2018 49.56 56.88 71.47 2.32 0.7882019 55.17 60.34 74.08 2.65 0.8002020 59.41 63.70 76.35 3.08 0.8192021 63.47 68.50 80.79 3.35 0.8342022 66.92 72.33 84.55 3.56 0.8432023 68.65 74.19 86.53 3.67 0.8452024 70.61 76.08 88.77 3.83 0.8452025 72.58 77.98 91.02 3.97 0.8452026 74.39 79.76 93.13 4.06 0.845Remainder +2.0% per year +2.0% per year +2.0% per year +2.0% per year 0.845

Source: Average of GLJ Petroleum Consultants, McDaniel & Associates Consultants, Sproule Associates and Deloitte Research Evaluation & Advisoryprice forecasts, effective January 1, 2018.

Based on the calculations performed, the Company recorded an impairment charge on its Taiga CGU of$135,525.

Impairment testing was also performed at December 31, 2016. The recoverable amount of the Orion CGUexceeded the carrying value and no impairment was recorded for the Orion CGU at December 31, 2016.

At December 31, 2016 the recoverable value of the Taiga CGU exceeded the carrying value and the fullinception to date impairment charge on the Taiga CGU of $149,871 was reversed. The reversal was aresult of lower forecast operating and capital costs.


The following forward prices and foreign exchange rates were used to estimate the recoverable amountsas at December 31, 2016:

Year

WesternCanadian Select

(C$/bbl)WTI at Cushing

(US$/bbl)

Diluent(condensate)

(C$/bbl)AECO gas



Source: Average of GLJ Petroleum Consultants, McDaniel & Associates Consultants, Sproule Associates and Deloitte Research Evaluation & Advisoryprice forecasts, effective January 1, 2017

For the year ended December 31, 2017, an increase to the after-tax discount rate used in the Company'simpairment test of 1% would have resulted in additional impairment of $72,065 and a $2 decrease to theUS$ WTI price would have resulted in additional impairment $74,900.

The fair value measurements are categorized as level 3 with inputs that are not based on observablemarket data.

Exploration, evaluation ("E&E") and other other intangible assets

The Company's E&E assets are comprised of its Saleski Joint Venture, Saleski West, Sepiko Kesik, andLiege properties, located in the Saleski area and its Portage property located in the Athabasca area.

During 2017 the Company observed a decline in the average of the long-term price forecasts of a numberof reserve engineering firms. The Company considered the price forecast decline an indicator ofimpairment and assessed the recoverable amount of its grouped CGU. Based on the test performed, theCompany recorded impairment of $48,371 (2016 – nil).

The recoverable amount of the Company's E&E assets was estimated using a value per barrel ofrecoverable resource reflective of the current commodity price environment and the nature of theresource. The measurement was categorized as level 3 with inputs that are not based on observablemarket data.

General and administrative ("G&A") expenses

For the years ended December 31, 2017 2016Gross general and administrative costs 17,857 20,338Capitalized salaries and benefits (3,360) (2,980)Onerous lease settlements (1,142) (453)Salaries and benefits related to pre-lease acquisition (20) (93)Net general and administrative expenses 13,335 16,812

For the year ended December 31, 2017, gross G&A costs were $17,857 compared with $20,338 in theprior year. The decrease mainly reflected the impact of head office staff reductions in both 2016 and


2017, combined with ongoing efforts to limit spending and preserve non-producing assets at a minimumcost.

Capitalized G&A during the year ended December 31, 2017 of $3,360 increased 13% from $2,980compared with the year ended December 31, 2016. The increase was the result of more time spent onthe Orion expansion projects by corporate head office staff.

Share-based compensation expense

For the year ended December 31, 2017, the incentives granted to employees and directors totaled 0.5million stock options, 0.8 million restricted share units ("RSUs") and 1.1 million performance share units("PSUs"). Total share-based compensation expense for the year was $4,075.

Total share-based compensation expense of $5,428 in 2016 was $1,353 or 25% higher than for 2017mainly due to the expense related to the March 15, 2016 grant of 4.3 million stock options, 1.1 millionRSUs and 1.9 million PSUs, and to the simultaneous cancellation of the unvested portion of 5.5 millionstock options previously issued at higher prices following a restructuring of the Company's share-basedincentives.

Exploration costs

For the year ended December 31, 2017, exploration costs were $20, compared with $93 in 2016.Exploration costs decreased as a result of staff reductions in 2016 and 2017 and the Company's focusshifting to its producing Orion asset.

Onerous contract expense (recovery)

During the year ended December 31, 2016, the Company recognized a provision for an onerous contractrelated to its Calgary head office lease. The provision represented the present value of the differencebetween the the estimated minimum future lease payments that the Company is obligated to make underthe lease until its expiry on March 31, 2019, less estimated sublease recoveries. At December 31, 2016,expected sublease recoveries included only those from contracts in place at the time.

During the year ended December 31, 2017, the Company recorded an onerous contract recovery of $380(2016 – expense of $3,445). The recovery resulted from the Company securing subleases on a portion ofits vacant head office space in late 2017 for the remainder of the term of the headlease.

During the year ended December 31, 2017, cashflows were discounted using risk-free discount ratesranging from 0.9% to 1.7% (2016 – 0.5% to 0.8%). Estimates may fluctuate in future periods as a result ofchanges in estimated sublease recoveries and actual lease payments.


Net finance costs

For the years ended December 31, 2017 2016Interest expense, long-term debt 17,979 18,247Amortization of deferred transaction costs 1,838 1,720Realized foreign exchange loss (gain) 188 (68)Interest income (2,449) (1,021)Other income — (1,000)Net finance costs 17,556 17,878

During the year ended December 31, 2017, the Company recorded net finance costs of $17,556, largelyconsistent with $17,878 in the prior year. The increase in interest income due to higher cash balances onhand from the proceeds of the callable common share purchase warrants and the GORR sale waspartially offset by the absence of a $1,000 non-completion fee received in the prior year related to aproposed asset sale.

Unrealized foreign exchange gain on long-term debt

The Company records an unrealized foreign exchange gain or loss upon translating the outstanding US$principal balance on its senior secured term loan at each year end to C$ at the related foreign exchangerate.

During the year ended December 31, 2017, the Company recorded an unrealized foreign exchange gainof $17,784 compared with a gain of $8,296 in the prior year as the C$ strengthened more during 2017than 2016.

Gain on disposition of PP&E

As discussed in "Deferred Consideration" above, the Company sold a 4.0% GORR on its Orion propertyon September 29, 2017 for cash proceeds of $92,500, before transaction costs and adjustments, andrecorded deferred consideration of $64,400. The remaining net proceeds of $26,593 were compared tothe carrying value attributable to the PP&E that was sold, which resulted in the recognition of a gain ondisposal of $14,922 (2016 – nil).

Accretion

For the year ended December 31, 2017, accretion expense related to decommissioning liabilities and theonerous lease provision increased to $671 from $548 in the prior year, mainly due to higher average risk-free interest rates.

Deferred income tax expense (recovery)

During the year ended December 31, 2017, the company recorded a deferred tax recovery of $906 (2016– expense of $15,853). The recovery in 2017 resulted from an increase to the tax basis of PP&E incomparison to the accounting basis, along with an increase to the non-capital loss pools.


Statement of Financial Position Accounts

Adjusted working capital

As at December 31, 2017, the Company had an adjusted working capital surplus of $213,161 comparedwith a surplus of $76,686 at December 31, 2016:

Adjusted working capitalAdjusted working capital surplus as at December 31, 2016 76,686Netback 59,065Proceeds from callable common share purchase warrants 100,000Net proceeds from sale of royalty interest 90,993Proceeds from disposition of E&E assets 2,114Interest and other income 2,449Realized loss on financial risk management contracts (7,914)Capital investment (74,355)Interest expense and principal payments (20,674)General and administrative expenses and other (15,203)Adjusted working capital surplus as at December 31, 2017 213,161

The Company’s adjusted working capital increased by $136,475 during the year ended December 31,2017. The increase reflected the net difference between income generated from Orion operations, fundsraised through callable common share purchase warrants, net proceeds from the sales of the GORR andE&E assets, and interest income, totaling $254,621, and expenditures on capital, realized loss on riskmanagement contracts, general and administrative, net finance and other expenditures totaling $118,146.

At December 31, 2017, the Company’s adjusted working capital consisted of cash and cash equivalentsof $230,463 (December 31, 2016 – $83,525) which included $13,456 (December 31, 2016 – $11,192) ofrestricted cash, accounts receivable of $24,003 (December 31, 2016 – $16,957) and prepaid expensesand other assets of $1,909 (December 31, 2016 – $1,037), less accounts payable and accrued liabilitiesof $39,202 (December 31, 2016 – $20,740), the current portion of long-term debt of $2,640(December 31, 2016 – $2,823) and the current portion of share unit liabilities of $164 (December 31,2016 – $113). Accounts receivable were substantially related to production revenue for the month ofDecember 2017. Accounts payable and accrued liabilities largely consisted of amounts incurred in thefourth quarter of 2017 in relation to royalties, diluent and transportation costs, operating costs, capital andadministrative expenditures and December's realized financial risk management contract liability.


Capital investment

Year endedDecember 31, 2017

Property, plant and equipment:Balance – beginning of year 507,423Orion 73,479Taiga 989Corporate assets 134Total cash investments 74,602Capitalized share-based compensation 611Changes to decommissioning liability 4,188Total non-cash investments 4,799Depletion & depreciation (34,924)Dispositions (net) (11,671)Impairment (135,525)

Balance – end of year 404,704

Exploration and evaluation:Balance – beginning of year 78,510Operated properties (SK, Saleski West, Liege and Portage) 634Saleski joint venture (881)Total cash investments (net) (247)Capitalized share-based compensation 12Changes to decommissioning liability (145)Capitalized depreciation 1,794Total non-cash investments 1,661Depreciation (1,815)Dispositions (2,114)Impairment (48,371)

Balance – end of year 27,624

Total cash capital investment (net) 74,355Total non-cash capital investment 6,460

Total capital investment 80,815

For the year ended December 31, 2017, the Company invested a total of $80,815 in capital assets, ofwhich $74,355 was funded by cash and $6,460 related to the non-cash impacts of capitalized share-based compensation and depreciation as well as changes in the Company’s provision for itsdecommissioning obligations.

Of the $80,815 of capital asset additions in the year ended December 31, 2017, $78,173 related to capitalinvestment in Orion, $1,093 related to the Company’s Taiga development at Cold Lake, $709 related tothe Saleski JV, and $706 related to exploration, evaluation, and development activities at SK, SaleskiWest, Liege and Portage. In addition, $134 was spent on corporate and other assets. Included in the


figures presented above, for the year ended December 31, 2017, are capitalized cash G&A and share-based employee-related costs of $4,044.

During the year ended December 31, 2017, the Company recorded $34,232 of depletion and $458 ofdepreciation related to its Orion project. There was no depletion charged against other oil sands projectsas they were still in the development stage at December 31, 2017. During the year ended December 31,2017 the Company charged $234 of depreciation against corporate and other intangible assets. Duringthe year ended December 31, 2017, the Company capitalized $1,794 of Saleski Joint Venture Pilot facilityand infrastructure depreciation to its intangible E&E assets.

As discussed in the depletion, depreciation and impairment section, during the year ended December 31,2017, the Company recorded impairment of $183,896, consisting of $135,525 applied to the Taiga CGUand $48,371 applied to E&E assets.

Provision

At December 31, 2017, the total provision for the onerous contract related to the Company's Calgaryhead office lease was $1,511 (2016 – $3,005) , of which $1,208 (2016 – $1,157) was recorded withinaccounts payable, accrued liabilities and provision, and $303 (2016 – $1,848) as a non-current provision.

For the years ended December 31, 2017 2016Balance – beginning of year 3,005 —Liabilities incurred — 2,403Change in estimated future cash flows (380) 1,042Liabilities settled (1,142) (453)Accretion 28 13Balance – end of year 1,511 3,005Less: current portion of provision 1,208 1,157Non-current portion of provision 303 1,848

As discussed in the "Results of Operations" section, the change in estimated cash flows during the yearended December 31, 2017 was due to the Company securing subleases on a portion of its vacant headoffice space.

Long-term debt

As at December 31, 2017, the US$15,000 revolving loan was undrawn and the balance of the term loan,net of unamortized debt issue costs, was $250,127 (December 31, 2016 – $268,768), which included$2,640 classified as current (December 31, 2016 – $2,823). The decrease in the C$ balance of the termloan from the prior year end mainly resulted from translating the outstanding US$ principal into C$ at theDecember 31, 2017 exchange rate of US$1 = C$1.2573, compared with the December 31, 2016 rate ofUS$1 = C$1.3442. During the years ended December 31, 2017 and 2016, the Company made scheduledprincipal repayments of US$2,100 (2017 – C$2,695, 2016 – C$2,759) on the term loan.

The associated unamortized transaction costs at December 31, 2017 of $5,325 (December 31, 2016 –$7,163) are being amortized over the life of the term loan utilizing the effective interest method. During theyear ended December 31, 2017, $1,838 was amortized against long-term debt (2016 – $1,720).

Decommissioning liabilities

The Company estimated the net present value of its total decommissioning liabilities to be $36,176 as atDecember 31, 2017 (December 31, 2016 – $31,861). The increase from the prior year was mainly due to


the estimated liabilities associated with 18 new wells (9 well pairs) drilled or spudded in 2017 and theadditional equipment associated with Orion's expansion projects. At December 31, 2017, the Companyestimated expenditures required to settle the liabilities will be made over the next 38 years with themajority of payments being made around 2045. As at December 31, 2017, the Company used discountrates ranging from 1.7% to 2.3% (December 31, 2016 – 0.7% to 2.3%) based on the Bank of Canada’srisk-free bond rates and an inflation rate of 1.7% (December 31, 2016 – 1.8%) to calculate the presentvalue of the decommissioning liabilities. During the year ended December 31, 2017, the Companyincurred $371 of expenditures to settle decommissioning obligations (2016 – $119).

Share unit liabilities

As at December 31, 2017, the Company's share unit liabilities for those RSUs and PSUs expected to besettled in cash were $3,470 (December 31, 2016 – $1,293). The increase in the liability was mainly due tothe granting of 811,900 RSUs and 1,168,950 PSUs in 2017, along with an increase in the estimated fairvalue per share unit to $2.50 from $2.25 at December 31, 2016.

As the Company's common shares do not trade in an active market, the fair values at December 31, 2017and 2016 were estimated using an independent third party evaluation.

As at December 31, 2017, $164 (December 31, 2016 – $113) of the Company's share unit liabilities wereclassified as current, relating to those RSUs and PSUs scheduled to vest in the next 12 months.

Deferred consideration

As discussed in the "Results of Operations" section, the Company sold a 4.0% GORR on its Orionproperty on September 29, 2017 for cash proceeds of $92,500, before transaction costs and adjustments,and recorded deferred consideration of $64,400. Deferred consideration is recognized in revenue basedon the ratio of production in the period to the estimate of proved plus probable reserves in effect at theend of the period, adjusted for production during the period.

At December 31, 2017, total deferred consideration was $64,047, of which $1,336 was classified ascurrent.

Deferred tax asset

The Company recognized a deferred tax asset as at December 31, 2017 of $34,454 (December 31, 2016– $33,548). The deferred tax asset resides entirely in OPC and the increase was the result of an increaseto the tax basis of PP&E in comparison to the accounting basis, along with an increase to the non-capitalloss pools.

As at December 31, 2017 the Company had approximately $1,031,608 in available tax pools, includingoperating loss carry forwards for income tax purposes in the amount of 489,023 which are available tooffset future taxable income. These operating losses start to expire in 2034.

Management’s forecasts indicate that it is likely that future taxable profits will be sufficient to utilize thelosses prior to expiry.


Shareholders’ equity

December 31, 2017 December 31, 2016Common shares 1,032,277 932,094Contributed surplus 63,777 61,654Cumulative deficit (767,415) (610,398)Total shareholders’ equity 328,639 383,350

The balance in common shares increased to $1,032,277 at December 31, 2017 from $932,094 atDecember 31, 2016 mainly due to the proceeds of $100,000 received upon the redemption of 8,000,000callable common share purchase warrants in February 2017.

During the year ended December 31, 2017, contributed surplus increased to $63,777 from $61,654. Theincrease was mainly the result of regular vesting of stock options and share units.

The increase in the cumulative deficit from $610,398 at December 31, 2016 to $767,415 at December 31,2017 was due to the net loss in 2017.


Equity Securities

During the year ended December 31, 2017, there were: 569,600 stock options granted; 593,000 stockoptions forfeited; 811,900 RSUs and 1,168,950 PSUs issued; 133,644 RSUs and 82,194 PSUs vested;and 109,676 RSUs and 102,106 PSUs forfeited.

As at December 31, 2017 and December 31, 2016, the following common shares, callable common sharepurchase warrants, stock options and performance warrants were issued and outstanding. In addition, asat December 31, 2017 and December 31, 2016, the following number of issued and outstanding RSUsand PSUs were expected to be settled in exchange for common shares of the Company:

(thousands) December 31, 2017 December 31, 2016Common shares outstanding 130,963 122,914Callable common share purchase warrants — 8,000Stock options 5,555 5,578Performance warrants 12 12Restricted share units 550 371Performance share units 897 587Total including dilutive securities 137,977 137,462

Long-term incentives plans

To ensure the Company’s long-term incentives plans remain competitive in the marketplace, theCompany’s Board of Directors periodically reviews the plans’ effectiveness as part of the Company’s totalcompensation program to attract, retain and motivate key personnel, encourage commitment to theCompany and its goals, align staff interests with the interests of shareholders and reward staff forperformance. In doing this review during 2017, the Board of Directors considered publicly available dataand information from external sources, including independent experts. On March 13, 2018 the Company'sBoard of Directors approved a grant of up to 0.6 million stock options, 0.7 million RSUs and 1.2 millionPSUs to employees, officers and directors of the Company.

As at March 13, 2018, the Company had the following common shares, stock options and performancewarrants issued and outstanding, and the following number of issued and outstanding RSUs and PSUswere expected to be settled in exchange for common shares of the Company:

(thousands) March 13, 2018Common shares outstanding 130,963Stock options 6,115Performance warrants 12Restricted share units 766Performance share units 1,248Total including dilutive securities 139,104


Liquidity, Financial Resources and Outlook

The Company's capital includes its working capital, senior secured credit facilities and share capital. AtDecember 31, 2017, the Company had $213.2 million of working capital, before the current portions of netunrealized hedging liabilities and deferred consideration. The total reflects the receipt of $100 million ofproceeds from the common share purchase warrants in February 2017, the sale of a 4.0% GORR onOrion for cash proceeds of $92.5 million, before transaction costs and adjustments, in September 2017as well as the cash contribution from the Company's Orion operation during the year.

The Company's term loan matures on July 31, 2020 and at December 31, 2017 it was in full compliancewith its asset-based financial covenants. Further, the Company has access to a US$15,000 revolving lineof credit which matures on July 31, 2019 and is currently undrawn. Details of the Company’s debt andequity capital are discussed in notes 13 and 15, respectively.

A substantial portion of the Company's available capital resources, including the expected cashcontribution from Orion operations, will be used to fund the expansion of the Orion facility and the drillingof new wells in 2018. The total is judged to be more than sufficient to cover all of the costs and anyrelated contingency. The activity is expected to lead to significant increases in production and cash flowsfrom operations in 2019.

As a means of protecting operating cash flows, the Company has an active commodity hedging program,targeting 60% of forecast production volumes, net of maximum royalties, for the forward 12 months and30% of volumes for the next 6 months, executed on a rolling basis. In late 2017, in anticipation of of thesanction of the next phase of expansion at Orion, the Company adjusted its hedging policy for the 2018calendar year to 70% of forecast production volumes to better manage price volatility during the period ofOrion facility construction and production ramp up.

Contractual Obligations and Commitments

The information presented in the table below reflected management’s estimate of the contractualmaturities of the Company’s obligations for its oil sands properties and its general corporate activities asat December 31, 2017.

Total 2017 2018 2019 2020+Contracts and purchase orders (1) 47,529 47,311 198 10 10Transportation agreements (2) 37,390 7,630 7,468 7,468 14,824Operating leases (3) 2,812 2,035 640 137 —Outstanding share units (4) 4,466 11 1,958 2,497 —Interest and fees on term loan (5) 43,278 16,889 16,715 9,674 —Repayment of term loan (5) 255,452 2,640 2,640 250,172 —Total 390,927 76,516 29,619 269,958 14,834

(1) Contracts and purchase orders including commitments relating to the Orion expansion projects and costs for the storage of the evaporatorsprocured for use at Taiga.

(2) Firm service gas and bitumen blend transportation commitments.(3) Future commitments for the head office leases and field vehicles. The amounts reported are net of expected settlements of the onerous lease

provision on the consolidated statement of financial position. (4) Unaccrued fair value of outstanding share units expected to be settled for cash. (5) Minimum obligations under the term loan using the foreign exchange and interest rates in effect at December 31, 2017.


Risk Factors

The Company is exposed to a number of business risks, some of which are common to all businesses,while others are specific to the sector in which the Company operates.The following discussion reviewsthese general and specific risks and includes the Company's approach to managing these risks. Theserisks can be categorized as operational, financial, regulatory and cyber security.

Operational risks

Operational risks include risks associated with health and safety, resource exploration and development,project construction, commercial production and the Company’s ability to retain and attract key personnel.

The development and operation of the Company’s properties are subject to hazards of finding,recovering, transporting and processing hydrocarbons including, but not limited to: blowouts; fires;explosions; gaseous leaks; migration of harmful substances; oil spills; corrosion; acts of vandalism andterrorism; and other accidents or hazards that may occur at or during transport to or from commercial orindustrial sites. Any of these hazards can interrupt development, including facility construction, andoperations, impact the Company’s reputation, cause loss of life or personal injury, result in loss of ordamage to equipment, property, information technology systems, related data and control systems, causeenvironmental damage that may include polluting water, land or air, and may result in fines, civil suits, orcriminal charges against the Company.

A significant source of risk with regard to resource development is accurately estimating the quantities ofreserves and resource given the level of uncertainty inherent in such estimates. As such, no assurancecan be given that the indicated level of reserves or resource or recoverable bitumen will be realized. Ingeneral, estimates of resource and of economically recoverable bitumen reserves are based upon anumber of factors, such as geological and engineering estimates, the assumed effects of regulation bygovernmental agencies, royalties and estimates of future commodity prices, operating costs and capitalcosts, all of which may vary considerably from actual results. Estimates based solely on these methodsare generally less certain than those based on production history. Reserves and resource estimates mayrequire revision based on actual production experience and data as they become available in future

periods. Potential changes in reserves and resource estimates in future periods could have a materialimpact on the net asset value of the Company, its operations, and its ability to obtain financing.

Project construction requires specialized labour, equipment, engineering expertise and constructionmanagement. There can be no assurance that all of the specialized labour and equipment will beavailable at the times or costs projected in the Company’s current plans. The Company may experienceshortages of specialized labour and equipment, labour disruptions and increases in compensation andequipment costs. Productivity of construction personnel is an important factor in developing its plannedprojects. Should low productivity occur, it may result in project completion delays and an increase inproject costs. The Company currently does not have regulatory approvals for the development of allphases of its projects. These regulatory approvals may delay or restrict the development of the projects.

The success of current and future commercial production is dependent on effective extraction of identifiedreserves and resources. The actual performance of Steam Assisted Gravity Drainage (“SAGD”), CyclicSteam Stimulation (“CSS”) and other potential recovery techniques may differ from expectations and todate those techniques have not been applied on a commercial scale to carbonate reservoirs. There aremany factors related to the characteristics of the reservoir and SAGD/CSS operating facilities that couldcause bitumen production to be lower than anticipated. In addition, the Company may develop andimplement alternative extraction processes that have not been widely used in the industry and whoseresults could differ from expectations.

The Company’s overall success also depends on its management team and key technical and otherpersonnel to run the business and execute on its project development plans. The loss of any of these keyindividuals could have a material adverse effect on the Company and the development of its assets. Dueto the specialized nature of the Company’s business, the Company believes that its future success willalso depend upon its continued ability to attract, retain and motivate skilled and experiencedmanagement, technical, operations and marketing personnel.

The Company manages these operational risks and hazards by maintaining a diversified portfolio ofassets, as well as by assembling and retaining an experienced management and technical team with therequisite skills to plan and either execute, or outsource to experienced third-party professionals, allaspects of the development, construction, and production stages of the projects. In addition, theCompany maintains certain insurance policies to mitigate the risks associated with potential operationalhazards. While there can be no certainty that the insurance policies will be sufficient to cover all potentialhazards, they are considered appropriate given the nature of the Company’s business and the currentstage of development of its projects.

Financial and market risks

The development of oil sands projects requires a significant amount of capital investment that occurs overa number of years and prior to the commencement of commercial operation of the Company’s projects.While the Company is in a strong financial position, a substantial portion of its capital resources will beused to fund the costs of increasing production at the Company's Orion project. There can be noguarantee that funds available will be sufficient to fund the costs in all circumstances. As a result, it maybe necessary to complete additional equity, debt, or other financings in future periods in order to completethe expansion of Orion or to advance future projects. The inability of the Company to access sufficientcapital for those activities could have a material adverse effect on the timing of project development andits financial condition, results of operations, or prospects.

The Company has existing debt and may take on additional debt in the future to finance any portion of itsplanned development activity. There can be no guarantee that it will have sufficient funds from availableequity or cash flow from operations to make payments with respect to its indebtedness or to fund its other


liquidity needs. In these circumstances, the Company may need to refinance all or a portion of its debt onor before maturity. There can be no guarantee that the Company will be able to refinance any of itsindebtedness on commercially reasonable terms or at all.

In addition, as the Company reports its operating results in C$, fluctuations in product pricing and in therate of exchange between the US$ and C$ affect the Company’s reported results. Further, all of theCompany's long-term debt is denominated in US$ and is at a variable interest rate. Fluctuations inexchange rates and interest rates may significantly increase or decrease the amount of debt and interestexpense recorded in the Company's financial statements, which could have a significant effect on theCompany's results of operations, financial condition and prospects.

With the recent and projected growth in production from unconventional sources in North America,additional infrastructure (e.g., pipeline and rail capacity) is required to transport all the potential productionto the desired markets. These projects have generally been identified. There is considerable risk that anyone or more of the projects may not proceed in line with current timing estimates, or at all. Until resolved,this has and could continue to lead to constraints in the Company’s production and a failure to capture thebest possible market pricing.

The Company’s revenues are based on the US$, since revenue received from the sale of bitumen andbitumen blends is generally referenced to a price denominated in US$. The Company incurs most of itsoperating and other costs in C$. As a result, the Company is impacted by exchange rate fluctuationsbetween the US$ and the C$, and any strengthening of the C$ relative to the US$ could negativelyimpact the Company’s operating margins and cash flows.

Markets for blended bitumen produced by the Company exist within North America; however, crude oildemand and price as well as market differentials for bitumen blend are affected by North American and, inthe case of crude oil, worldwide supply and demand fundamentals that are beyond the control of theCompany. World oil prices and blended bitumen differentials have fluctuated widely in recent years and oilprices have decreased materially in the past three years, negatively impacting net production revenue.Any additional decline in prices or widening of blended bitumen differentials could further reduce futurenet production revenue. Certain wells or other projects may become uneconomic as a result of thedecline in world oil prices and/or any widening of blended bitumen differentials, leading to a reduction inthe volume of the Company’s bitumen resources and reserves. The Company also might elect not toproduce from certain wells at lower prices.

The Company may utilize financial instruments to manage the exposure to market risks relating to foreignexchange rates and commodity prices which may have an adverse effect on its financial results, conditionand prospects. All of these factors could result in a material decrease in the Company’s future netproduction revenue, negatively impacting its oil sands exploration and development activities.

During the year ended December 31, 2017, the Company continued to execute its commodity hedgingprogram. The Company's hedging objective is to increase the certainty of C$ operating cash flows as asource of funding by reducing commodity price and related foreign exchange volatility. As and whendeemed appropriate, the Company mitigates market risks by using financially and physically-settledderivatives to hedge up to 60% of its forecast bitumen production, net of maximum royalties. In late 2017,in anticipation of of the sanction of the next phase of expansion at Orion, the Company adjusted itshedging policy for the 2018 calendar year to 70% of forecast production volumes to better manage pricevolatility during the period of Orion facility construction and production ramp up. Management monitorscredit and counterparty concentration risks related to the risk management contracts but considers themacceptable due to the size and financial strength of the counterparties.


For the year ended December 31, 2017, realized gains and losses on risk management contractsincluded the following:

FinancialSwaps – WTI 2,670Options – WTI (1,580)Swaps – WTI/WCS differential (9,004)Net realized loss on financial risk management contracts (7,914)

As at December 31, 2017, the following financial risk management contracts were in place:

Contract Notional Price Remaining Term Fair ValueSwap – WTI/WCS differential 3,855 bbl/d $(21.50) Jan 1/18 - Mar 31/18 2,913Swap – WTI/WCS differential 3,240 bbl/d $(22.70) Jan 1/18 - Dec 31/18 2,966Swap – WTI/WCS differential 3,660 bbl/d $(19.70) Apr 1/18 - Jun 30/18 1,109Swap – WTI/WCS differential 3,974 bbl/d $(19.18) Jul 1/18 - Sep 30/18 1,406Swap – WTI/WCS differential 1,646 bbl/d $(20.86) Oct 1/18 - Dec 31/18 621Swap – WTI/WCS differential 4,041 bbl/d $(20.02) Jan 1/19 - Mar 31/19 1,385Swap – WTI/WCS differential 1,616 bbl/d $(21.39) Apr 1/19 - Jun 30/19 284Total unrealized financial risk management assets 10,684

Contract Notional Price Remaining Term Fair ValueSwap – WTI 2,881 bbl/d $71.13 Jan 1/18 - Mar 31/18 (1,192)Swap – WTI 2,375 bbl/d $73.50 Jan 1/18 - Dec 31/18 (673)Swap – WTI 2,729 bbl/d $62.54 Apr 1/18 - Jun 30/18 (3,119)Swap – WTI 2,968 bbl/d $65.84 Jul 1/18 - Sep 30/18 (2,174)Swap – WTI 4,008 bbl/d $69.48 Oct 1/18 - Dec 31/18 (1,117)Swap – WTI 2,993 bbl/d $63.26 Jan 1/19 - Mar 31/19 (2,163)Swap – WTI 1,550 bbl/d $66.21 Apr 1/19 - Jun 30/19 (567)Total unrealized financial risk management liabilities (11,005)

The Company has significant exposure to electricity costs and natural gas prices during the project life asthe majority of the energy required to generate steam for SAGD and CSS operations is from natural gas.High electricity costs and/or natural gas prices could result in a material increase in operating costs. Inaddition, the Company is exposed to condensate costs given that wellhead bitumen is blended withcondensate to deliver production to market. Should condensate costs increase disproportionately morethan the price the Company is able to obtain for blended bitumen sales, the Company’s overall profitabilitycould be affected.

To the extent that the Company is not the operator of its properties, such as the Saleski joint venture, theCompany will be dependent upon third parties’ operations for the timing of activities and will be largelyunable to control the activities of such operators. In addition, there is no certainty that third-partyoperators will be able to meet financial commitments to a particular project which could have a materialadverse effect on the viability of these projects and the business and operations of the Company.

Inflation risks subject the Company to potential erosion of product netbacks and overall profitability. Forexample, domestic prices for construction equipment and services and oil production equipment andservices can inflate the costs of project development and increase future operating costs.


The Company manages these risks through effective capital budgeting, financial and market forecastingand planning, expenditure and commitment monitoring and long-term corporate planning. The Companyassesses projects on stringent investment criteria. In addition, the Board of Directors reviews andapproves the annual operating and capital budgets and any material changes in the amount or scope tothe budgets.

Regulatory risks

The Company’s business is subject to substantial regulation under provincial and federal laws relating tothe exploration for, and the development, processing, marketing, pricing, taxation, and transportation of oilsands bitumen and related products and other matters. Amendments to current laws and regulationsgoverning operations and activities of oil sands operations could have a material adverse impact on theCompany’s business. In addition, there can be no assurance that laws, regulations and governmentprograms related to the Company’s projects and the oil sands industry will not be changed in a mannerwhich may adversely affect the projects and cause delays or inability to complete the projects. Permits,leases, licences, and approvals are required from a variety of regulatory authorities at various stages ofthe Company’s projects. There can be no assurance that the various government permits, leases,licenses and approvals sought will be granted in respect of the projects or, if granted, will not be cancelledor will be renewed upon expiry. There is no assurance that such permits, leases, licences, and approvalswill not contain terms and provisions which may adversely affect the final design and/or economics of theCompany’s projects. The Company currently does not have regulatory approvals for the development ofall phases of its projects. These regulatory approvals may delay or restrict the development of theprojects.

Future development of the Company’s projects is dependent on maintaining its current oil sands leasesand licences and receiving required regulatory approvals and permits on a timely basis. Maintenance ofthe Company’s undeveloped oil sands leases and licenses requires a Minimum Level of Evaluation in theform of drilling, seismic and/or other delineation activity. There can be no guarantee that the Company willhave sufficient capital, human or other resources to satisfy all its current requirements, or that therequirements will not be modified.

The Government of Alberta has initiated a process to control cumulative environmental effects ofindustrial development through the Lower Athabasca Regional Plan ("LARP"). While the LARP has nothad a significant effect on the Company, there can be no assurance that changes to the LARP or futurelaws or regulations will not adversely impact the Company's ability to develop or operate its projects. Allphases of the oil and natural gas business present environmental risks that are subject to environmentalregulation pursuant to a variety of national and international conventions, as well as municipal andprovincial laws and regulations. These laws and regulations require that wells and facility sites beoperated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.

Production and future development of the Company’s resources will result in the emission of greenhousegases (“GHGs”) and other industrial air pollutants, which the federal and provincial governments haveannounced intentions to regulate. In November, 2015, the Government of Alberta announced its climateleadership plan (“CLP”) highlighting four key strategies that the government intended to implement toaddress climate change: (1) the complete phase-out of coal-fired sources of electricity by 2030; (2) anAlberta economy-wide price on GHG emissions of $30 per tonne by January 1, 2018; (3) capping oilsands emissions to a province-wide total of 100 megatonnes per year, with certain exceptions forcogeneration power sources and new upgrading capacity; and (4) reducing methane emissions from oiland gas activities by 45 percent by 2025. The above measures formed the basis of the Province's CarbonCompetitiveness Incentive Regulation, an output-based emissions framework which became effective onJanuary 1, 2018. The Company's facility compliance costs are based on its emissions performance


against a facility-specific emissions intensity benchmark that is allocated and approved each year by theProvince relative to broader industry benchmarking. There can be no assurance as to the Company'sexpected emissions performance, the industry's emissions performance or the resultant compliance coststo the Company. Material compliance costs could materially impact the economics of the Company'soperations and development projects.

In October 2016, the Government of Canada announced a pan-Canadian approach to the pricing ofcarbon emissions. The plan includes imposing carbon pricing beginning at a minimum of $10 per tonne in2018 and rising by $10 per tonne each year to $50 per tonne in 2022. Provinces and territories had a yearto introduce their own carbon pricing or adopt a cap-and trade system that meets or exceeds the federalbenchmark. If provinces and territories failed to implement a price or cap-and-trade plan by 2018 such asAlberta's Carbon Competitiveness Incentive Regulation, the Government of Canada indicated it willimplement a price in that jurisdiction.

The federal Species at Risk Act and provincial Wildlife Act regulate threatened and endangered speciesand may limit the pace and amount of development in areas identified as critical habitat for species ofconcern such as Woodland Caribou. The federal and/or provincial implementation of measures to protectspecies at risk such as Woodland Caribou and their critical habitat in areas of the Company’s current orfuture operations may modify the Company’s pace and amount of development in affected areas.

Compliance with such legislation and the laws and regulations discussed above can require significantexpenditures, and a breach may result in the imposition of fines and penalties, some of which may bematerial. To manage these risks, the Company has both in-house expertise and also hires third-partyconsultants to advise on environmental and safety compliance matters. The Company makesenvironmental stewardship and safety the highest priorities in its project planning and budgeting.

The development of the Company’s projects relies on securing licences for non-potable groundwaterwithdrawal, and there can be no assurance that these licences will be granted on terms favourable to theCompany or at all, or that such water will in fact be available to divert under such licences. In addition,there can be no assurance that the licences to withdraw groundwater, when granted, will not be rescindedor that additional conditions will not be added to these licences. There can be no assurance that theCompany will not have to pay a fee for the use of water in the future or that any such fees will bereasonable.

The Company is also subject to risk in relation to potential stakeholder objections, including thoseoriginating from First Nations peoples who have claimed title and/or have certain treaty or traditionalrights in relation to large areas of land in the province of Alberta, including to the entirety or specificportions of current and future commercial regulatory applications associated with its oil sands projects.Such objections can result in having to participate in a regulatory hearing to reach a resolution, whichmay have an impact on the timing of project execution and have an adverse effect on the Company’sfuture financial condition or ability to proceed.

The Company manages these risks by employing and contracting stakeholder, environmental andregulatory experts to ensure that: it prepares and submits high quality regulatory project applications;initiates and maintains positive relationships with all stakeholders; and conducts all operations in anenvironmentally responsible manner.

Cyber security risk

The Company utilizes a number of information technology systems for the administration andmanagement of its business, including the safe operation of its Orion facility. If the Company's ability toaccess and use these systems is interrupted and cannot be quickly and easily restored then such eventcould have a material adverse effect on the Company and its operations. Further, although the


Company's information technology systems are considered to be secure, if an unauthorized third party isable to access the systems then such unauthorized access may compromise the Company's business ina materially adverse manner.

The Company manages these risks by: employing technical countermeasures such as anti-virus softwareand network firewalls; providing ongoing training and education of staff through initiatives such assimulated phishing emails; requiring all changes to security and access to be logged and audited in atracking system; and through design decisions by isolating and fortifying critical parts of the Company'sinformation infrastructure.


Critical Accounting Estimates and Judgments

The timely preparation of financial statements in accordance with IFRS requires management to makeestimates and judgments that affect the reported amounts of assets and liabilities and disclosure ofcontingencies at the dates of the annual consolidated financial statements and the reported amounts ofrevenues and expenses during the reporting period. Such estimates primarily relate to unsettledtransactions and events as of the date of the consolidated financial statements. The estimated fair valueof assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actualresults may differ materially from estimated amounts as future confirming events occur. Significantjudgments, estimates and assumptions made by management in the preparation of these consolidatedfinancial statements are outlined below.

Sale of a royalty interest

When the Company sells a royalty interest linked to production at a specific property, judgment is requiredin assessing the appropriate accounting treatment of the transaction on the closing date and in futureperiods. The Company considers the specific terms of the arrangement to determine whether it hasentered into a financing arrangement, disposed of an interest in the reserves of a property, and/orreceived an upfront payment for future services. This assessment considers the economic substance ofthe arrangement including the Company's method of settlement, the risks assumed by the royalty owner,the duration of the arrangement, the property or properties to which the royalty applies, the timing of theroyalty owner's investment including any potential future payments, any penalties for the Company failingto deliver the royalty, the royalty owner's involvement in the Company's ongoing decision-making, and anycommitments made by the Company to develop future expansions or projects at the property. To theextent it is determined that there is an upfront payment for future services, judgment is required toestimate the value of such services.

Bitumen reserves and resource

The estimation of reserves and resource involves the exercise of judgment. Forecasts are based onengineering data, estimated future prices, expected future rates of production and the cost and timing offuture capital and operating expenditures, all of which are subject to many uncertainties andinterpretations. The Company expects that over time its reserves estimates will be revised either upwardor downward based on updated information such as the results of future drilling, testing and production.Reserves and resource estimates can have a significant impact on net income (loss), as they are a keycomponent in the calculations of depletion and deferred consideration and for determining potential assetimpairment or reversals thereof. Reserves and resource estimates for properties in PP&E are prepared byindependent reserve engineers at least annually. Independently prepared resource estimates for E&Eproperties may be prepared less frequently but at minimum are reviewed and, if necessary, updated bymanagement annually.

Financial risk management contracts

The fair value of financial risk management contracts is dependent on estimates of forward commodityprices, differentials and foreign exchange rates. While forward prices and rates at the balance sheet datewere determined based on observable market data, they will likely differ from future prices and rates andsignificantly impact the fair value of financial risk management contracts.

Carrying value of exploration and evaluation assets

The application of the Company’s accounting policy for E&E expenditures requires judgment indetermining whether it is likely that future economic benefit exists when activities have not reached astage where technical feasibility and commercial viability can be reasonably determined and whentechnical feasibility and commercial viability have been reached. Estimates and assumptions may changeas new information becomes available.

Identification of cash generating units

CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows thatare largely independent of the cash inflows of other assets or groups of assets. The classification ofassets into CGUs requires significant judgment and interpretations with respect to the integration betweenassets, the existence of active markets, external users, shared infrastructures, and the way in whichmanagement monitors the Company’s operations.

Provisions

Provisions are recognized for the future decommissioning and restoration of the Company’s oil and gasassets to be incurred at the end of their economic life. The reported amount of the obligation is based onestimated future costs for the abandonment of the assets and reclamation of the site to its original statediscounted at a risk-free rate and must be reevaluated each reporting period. Estimating the timing,amount and present value of these retirement costs requires significant judgment. By their nature, theseestimates, as they become available, are subject to measurement uncertainty, and the impact on theconsolidated financial statements could be material.

The Company recognizes a provision relating to its head office lease equal to the present value of thedifference between the minimum future lease payments that the Company is obligated to make under thelease until its expiry, including estimated future operating costs, less estimated sublease recoveries.Actual recoveries and operating costs may differ significantly from these estimates.

In addition, the Company makes estimates of potential provisions owing within accounts payable andaccrued liabilities, which may include amounts disputed in the normal course of business. Amountsultimately paid may differ significantly from these estimates.


Share-based compensation

The Company uses a fair value-based method of accounting for share-based compensation for all awardsof shares, performance warrants, stock options, RSUs and PSUs. The Black-Scholes pricing model isused to estimate the fair value of stock options and performance warrants on the date of grant. The Black-Scholes pricing model includes inputs such as discount rates, expected exercise dates, and expectedvolatility, which are subject to judgment and may not be indicative of future experience. Into its vestingmodels, management has incorporated an estimated forfeiture rate, which is also subject to judgment.The liability for the portion of share unit awards that is expected to be settled in cash is based onmanagement's estimate of the Company's share price at the reporting date and an assumption that staffwill elect to receive the maximum cash award. As the Company is a private entity, its estimated shareprice is subject to significant judgment.

Deferred income taxes

The determination of deferred income tax assets and liabilities requires interpretation of complex lawsand regulations, and they are recognized at tax rates expected to be in effect at the estimated timing ofreversal of temporary differences between the accounting and tax treatment of certain assets andliabilities. To the extent these judgments change, there may be a significant impact on the consolidatedfinancial statements of future periods.

Deferred income tax assets are recognized to the extent that it is probable that the deductible temporarydifferences will be recoverable in future periods. The recoverability assessment involves a significantamount of estimation including an evaluation of when the temporary differences will reverse, anestimation of the amount of future taxable earnings, the availability of taxable income to offset the taxassets when the reversal occurs and the application of tax laws. To the extent that assumptions used inthe recoverability assessment change, there may be a significant impact on the consolidated financialstatements of future periods.


Future Accounting Policies

(a) IFRS 15 – Revenue from contracts with customers

IFRS 15 – Revenue from contracts with customers, intended to replace IAS 18 – Revenue, IAS 11 –Construction Contracts, and related interpretations, specifies how and when an IFRS reporter willrecognize revenue as well as requiring more informative, relevant disclosures. The standard provides asingle, principles-based five-step model to be applied to all contracts with customers. The standardrequires an entity to recognize revenue to reflect the transfer of goods and services for the amount itexpects to receive when the control is transferred to the purchaser. IFRS 15 was issued in May 2014 andapplies to annual reporting periods beginning on or after January 1, 2018, with early adoption permitted.

The Company intends to adopt IFRS 15 in its financial statements for the annual period beginning onJanuary 1, 2018. The Company is currently assessing and evaluating the impact of the standard on thefinancial statements. The Company anticipates there will be additional enhanced disclosures uponadoption.

(b) IFRS 9 – Financial instruments

IFRS 9 – Financial Instruments, intended to replace IAS 39 – Financial Instruments: Recognition andMeasurement, uses a single approach to determine whether a financial asset is measured at amortizedcost or fair value, replacing the multiple rules in IAS 39. The new standard also requires a singleimpairment method to be used, replacing the multiple impairment methods in IAS 39, and incorporates asubstantially reformed approach to hedge accounting. IFRS 9 is effective for annual periods beginning onor after January 1, 2018, with early adoption permitted.

The Company intends to adopt IFRS 9 in its financial statements for the annual period beginning onJanuary 1, 2018. The Company expects that there will not be any material changes in the measurementand carrying values of the Company's financial instruments as a result of the adoption if IFRS 9. Further,IFRS 9 also contains a new model to be applied for hedge accounting, however the Company does notcurrently apply hedge accounting to its risk management contracts nor does it intend to upon adoption ofIFRS 9.

(c) IFRS 16 – Leases

IFRS 16 – Leases, intended to replace IAS 17 – Leases, brings most leases on-balance sheet for lesseesunder a single model, eliminating the distinction between operating and finance leases. Lessoraccounting however remains largely unchanged and the distinction between operating and finance leasesis retained. IFRS 16 is effective for annual periods beginning on or after January 1, 2019 and theCompany intends to adopt IFRS 16 in its financial statements for the annual period beginning on January1, 2019. The extent of the impact of adoption of the standard has not yet been determined.


Quarterly Results

Changes in the reported amounts of quarterly income and cash flows were largely due to the fluctuationsin the oil price, production rates, and foreign exchange rates.

Other than funds flow, netback, adjusted netback, adjusted working capital and adjusted working capitalplus available capital from outstanding callable warrants, all non-IFRS measures, the figures as reportedin the following table for the eight most recent quarters are presented in accordance with IFRS.

2017 2016

Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1

Business Environment (1)

West Texas Intermediate (WTI) – US$/bbl 55.02 48.19 48.29 51.86 49.33 44.94 45.60 33.52

Cold Lake Blend (CLB) – US$/bbl 42.65 37.36 36.35 36.34 34.11 30.59 31.03 18.65

Differential – WTI less CLB – US$/bbl 12.37 10.83 11.94 15.52 15.22 14.35 14.57 14.87

Differential – CLB % of WTI 22.5% 22.5% 24.7% 29.9% 30.9% 31.9% 32.0% 44.4%

Foreign exchange rate – C$/US$ 1.2716 1.2527 1.3449 1.3234 1.3338 1.3049 1.2888 1.3747

CLB – $/bbl 54.23 46.80 48.89 48.09 45.50 39.92 39.99 25.64

AECO – $/mcf 1.60 1.37 2.65 2.56 3.10 2.32 1.10 2.15

Operational (1) (2)

Bitumen production – bbl/d 9,306 7,946 7,478 7,654 8,102 7,287 7,018 6,608

Blended bitumen sales (3) – bbl/d 12,961 10,402 10,201 10,564 11,125 9,348 9,606 9,370

Blended bitumen sales less diluent andtransportation costs (3) – $/bbl 42.82 38.64 39.48 36.03 36.71 31.57 31.30 14.87

Royalties – $/bbl (2.77) (0.61) (0.98) (1.06) (0.70) (0.55) (0.40) (0.15)

Non-fuel operating costs – $/bbl (12.91) (15.06) (15.74) (13.67) (12.57) (16.31) (13.35) (16.67)

Fuel costs – $/bbl (2.30) (2.87) (5.03) (5.28) (5.12) (4.11) (2.78) (3.61)

Netback (3) (4) – $/bbl 24.84 20.10 17.73 16.02 18.32 10.60 14.77 (5.56)

Realized gain (loss) on financial riskmanagement contracts – $/bbl (3.81) (1.86) (2.32) (2.49) (4.76) (2.13) 9.99 22.20

Adjusted netback (3) (4) – $/bbl 21.03 18.24 15.41 13.53 13.56 8.47 24.76 16.64

FinancialNetback (3) (4) 21,273 14,695 12,061 11,036 13,665 7,110 9,432 (3,344)

Adjusted netback (3) (4) – $/bbl 18,013 13,339 10,481 9,318 10,114 5,681 15,809 10,003

Funds flow (5) 10,511 5,961 3,135 748 3,411 (2,846) 5,767 452

Cash flows from (used in) operating activities 6,143 6,040 1,211 5,004 678 2,508 3,980 (714)

Net and comprehensive income (loss) (179,652) 11,929 7,108 3,599 99,197 (130,781) (18,384) 1,352

Net income (loss) per share (basic) – $ (6) (1.37) 0.09 0.05 0.03 0.81 (1.07) (0.15) 0.01

Capital investment (net cash) (7) 31,759 8,265 18,439 15,895 10,341 8,149 4,305 3,202

General and administrative expenses (net) (8) 3,558 2,961 2,933 3,883 3,066 3,558 5,050 5,138

Cash and cash equivalents (9) 230,463 236,798 154,589 172,910 83,525 95,252 99,025 98,877

Adjusted working capital (AWC) (10) 213,161 233,753 144,698 160,706 76,686 84,479 96,157 95,555

AWC plus available capital from outstandingcallable warrants (10)(11) 213,161 233,753 144,698 160,706 176,686 184,479 196,157 195,555

Outstanding principal – long-term debt (12) 252,812 251,415 262,075 269,910 273,108 267,458 263,961 266,277

Shareholders' equity 328,639 507,887 495,499 487,686 383,350 283,477 413,487 429,060

Weighted average common sharesoutstanding 130,962 130,927 130,915 127,623 122,680 122,444 122,413 122,401

(1) Business environment and operational metrics are averages for the period.(2) Dollar per barrel metrics are calculated based on bitumen production volumes. Quarter-over-quarter per barrel metrics may be affected by differences between the timing of

bitumen production and blended bitumen sales.(3) Blended bitumen sales, blended bitumen sales less diluent and transportation costs, netback and adjusted netback include any realized gains and losses on physical risk

management contracts.(4) Netback is calculated by deducting the related diluent, transportation, royalties and field operating costs from blend sales revenue. Adjusted netback is calculated by adjusting

the netback to include realized gains and losses on financial risk management contracts.(5) Funds flow is calculated as cash flows from operating activities before changes in non-cash operating working capital, which is presented on the consolidated statement of

cash flows.(6) For the three months ended December 31, 2016, diluted net income per share was $0.80 per share. For all other three-month periods, diluted net income (loss) per share

was the same as net income (loss) per share. (7) Capital investment includes capitalized general and administrative expenses but excludes capitalized stock-based compensation expense.(8) General and administrative expenses (net) is calculated after reductions for capitalized salaries and benefits, onerous lease payments and exploration costs.(9) Cash and cash equivalents include restricted cash.(10) Adjusted working capital is calculated as working capital adjusted to exclude the current portions of risk management contracts, which are fair value estimates of unrealized

gains and losses and are subject to a high degree of volatility prior to ultimate settlement, and deferred consideration, which is not cash-settled.(11) In 2016, adjusted working capital plus available capital from outstanding callable warrants for each period included $100,000 associated with the aggregate exercise value

of 8,000,000 outstanding callable common share purchase warrants. On December 1, 2016 the Company called all of the outstanding callable common share purchasewarrants and the proceeds were received in February of 2017.

(12) Outstanding principal of long-term debt consists of the non-current portion of the outstanding principal balance of the US$210,000 term loan and any amounts outstandingunder the US$15,000 revolving loan, translated to Canadian dollars at the period-end foreign exchange rate and presented before unamortized transaction costs.


Forward-Looking Statements

Certain statements contained in this MD&A, including the documents incorporated by reference, maycontain projections and “forward-looking statements” within the meaning of that phrase under Canadianand US securities laws. When used in this document, the words “may,” “would,” “could,” “will,” “intend,”“plan,” “anticipate,” “believe,” “estimate,” “expect” and similar expressions may be used to identifyforward-looking statements. Those statements reflect management’s current views with respect to futureevents or conditions, including prospective results of operations, financial position, predictions of futureactions or plans or strategies.

Certain material factors and assumptions were applied in drawing conclusions and making those forward-looking statements. By their nature, those statements reflect management’s current views, beliefs andassumptions and are subject to certain risks and uncertainties, known and unknown, and assumptions,including, without limitation, production and development delays; changing environmental regulations;government and administrative decisions and changes to laws and regulations; the ability to attract andretain business partners; changes in material and construction costs; the ability to exploit hydrocarbonresources with existing technology; the ability to attract and retain key personnel; the need to obtain andmaintain proprietary rights over technology; competition from other technologies; the ability of theCompany and its joint venture partner to access the capital required for research, technologydevelopment, operations and marketing, resource delineation and project development; the need togenerate positive cash flow in the foreseeable future; and changes in energy prices and currency levels.

Many factors could cause actual results, performance or achievements to be materially different from anyfuture results, performance or achievements that may be expressed or implied by these forward-lookingstatements. Should one or more of these risks or uncertainties materialize, or should the assumptionsunderlying the projections or forward-looking statements prove incorrect, the actual results may varymaterially from those described in this report as intended, planned, anticipated, believed, estimated, orexpected. There is no intention and the reader should not assume any obligation to update these forward-looking statements, whether as a result of new information, plans, events or otherwise.

Additional Disclosure

The Company is not a reporting issuer, nor are its securities traded on any stock exchange in Canada. Asa result, the Company is not subject to regulation by any Canadian stock exchange.

The Company's securities are also not registered under the United States Securities Act of 1933, nor arethey traded on any securities or stock exchange in the United States. As a result, the Company is notpresently subject to the reporting, certification or other requirements imposed on US registered issuersunder, among other things, the US Sarbanes-Oxley Act of 2002.



Report of ManagementManagement’s Responsibility for the Financial Statements

The accompanying consolidated financial statements of Osum Oil Sands Corp. (the “Company”) are theresponsibility of management. The consolidated financial statements have been prepared bymanagement in Canadian dollars in accordance with International Financial Reporting Standards (“IFRS”)as issued by the International Accounting Standards Board (“IASB”) and include certain estimates thatreflect management’s best judgments. Financial information contained throughout the annual report isconsistent with these consolidated financial statements.

The Company maintains systems of internal accounting and administrative controls. These systems aredesigned to provide reasonable assurance that the financial information is relevant, reliable and accurateand that the Company’s assets are properly accounted for and adequately safeguarded. Management’sevaluation concluded that our internal controls over financial reporting were effective as of December 31,2017.

The Company’s Board of Directors has approved the consolidated financial statements. The Board ofDirectors fulfills its responsibility regarding the consolidated financial statements mainly through its AuditCommittee which is composed of three directors, all of which are independent of management. The AuditCommittee has a written mandate that complies with the current requirements of Canadian securitieslegislation. The Audit Committee meets with management at least on a quarterly basis to review andapprove interim financial statements prior to their release as well as with management and theindependent auditors annually to review annual financial statements and management’s discussion andanalysis and recommend their approval to the Board of Directors.

PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has been engaged, asapproved by a vote of the shareholders at the Company’s most recent Annual General Meeting, to auditand provide their independent audit opinion on the Company’s consolidated financial statements as atand for the year ended December 31, 2017. Their report, contained herein, outlines the nature of theiraudit and expresses their opinion on the consolidated financial statements.

Steve Spence Victor RoskeyPresident and Chief Executive Officer Chief Financial Officer

March 13, 2018




Osum Oil Sands Corp. Consolidated Statements of Financial Position(Expressed in thousands of Canadian dollars)

December 31, 2017 December 31, 2016

AssetsCurrent assets:

Cash and cash equivalents 217,007 72,333

Restricted cash (note 6) 13,456 11,192

Accounts receivable 24,003 16,957

Financial risk management contracts (note 7) 9,015 3,215

Prepaid expenses and other assets 1,909 1,037

Total current assets 265,390 104,734

Non-current assets:

Property, plant and equipment (note 9) 404,704 507,423

Exploration, evaluation and other intangible assets (note 10) 27,624 78,510

Deferred tax asset (note 11) 34,454 33,548

Financial risk management contracts (note 7) 1,669 —

Abandonment deposits 336 322

Total assets 734,177 724,537

LiabilitiesCurrent liabilities:

Accounts payable, accrued liabilities and provision (note 12) 40,410 21,897


Current portion of long-term debt (note 13) 2,640 2,823

Current portion of deferred consideration (note 8) 1,336 —

Share unit liabilities (note 15) 164 113

Total current liabilities 52,825 38,601

Non-current liabilities:

Long-term debt (note 13) 247,487 265,945

Deferred consideration (note 8) 62,711 —

Decommissioning liabilities (note 14) 36,176 31,861

Share unit liabilities (note 15) 3,306 1,180


Provision (note 12) 303 1,848

Total non-current liabilities 352,713 302,586

Shareholders’ equityCommon shares (note 15) 1,032,277 932,094

Contributed surplus (note 15) 63,777 61,654

Cumulative deficit (767,415) (610,398)

Total shareholders' equity 328,639 383,350

Total liabilities and shareholders' equity 734,177 724,537

Contractual obligations and commitments (note 19)

The accompanying notes are an integral part of these consolidated financial statements.

Vincent ChahleyDirector

George CrookshankDirector

Osum Oil Sands Corp.Consolidated Statements of Net and Comprehensive Loss(Expressed in thousands of Canadian dollars, except share and per share amounts)

For the years ended December 31, 2017 2016Revenue:

Blended bitumen sales 198,804 137,292Deferred consideration (note 8) 353 —Royalties (4,218) (1,232)

Revenue net of royalties 194,939 136,060Gain (loss) on financial risk management contracts (note 7) 4,071 (16,242)

Revenue net of gain or loss on financial risk management contracts 199,010 119,818Expenses:

Diluent and transportation 82,215 59,831Operating expenses 53,306 49,366Depletion, depreciation and impairment (notes 9, 10) 218,841 7,477General and administrative expenses 13,335 16,812Share-based compensation expense (note 15) 4,075 5,428Exploration costs 20 93Onerous contract expense (recovery) (note 12) (380) 3,445

Total expenses 371,412 142,452Other expenses (income):

Net finance costs (note 18) 17,556 17,878Unrealized foreign exchange gain on long-term debt (note 13) (17,784) (8,296)Gain on disposition of property, plant and equipment (note 8) (14,922) —Accretion (notes 12, 14) 671 548

Total other expenses (income) (14,479) 10,130Net loss before taxes (157,923) (32,764)Deferred income tax expense (recovery) (note 11) (906) 15,853Net and comprehensive loss (157,017) (48,617)Net loss per share, basic and diluted (note 15) ($1.21) ($0.40)

Weighted average number of common shares outstanding (thousands):Basic 130,119 122,485Diluted 131,515 123,358



Osum Oil Sands Corp.Consolidated Statements of Changes in Equity(Expressed in thousands of Canadian dollars)

Number ofcommon shares

(thousands)Sharecapital

Contributedsurplus

Cumulativedeficit Total equity

Balance – January 1, 2017 122,914 932,094 61,654 (610,398) 383,350Net loss for the year — — — (157,017) (157,017)Share-based compensation — — 2,306 — 2,306Share issuance on exercise of callable common sharepurchase warrants 8,000 100,000 — — 100,000Share issuance on vesting of share units 49 — — — —Reallocation on vesting of share units — 183 (183) — —Balance – December 31, 2017 130,963 1,032,277 63,777 (767,415) 328,639

Balance – January 1, 2016 122,401 929,927 58,975 (561,781) 427,121Net loss for the year — — — (48,617) (48,617)Share-based compensation — — 4,774 — 4,774Share issuance on exercise of stock options andperformance warrants 410 74 — — 74Share issuance on vesting of share units 103 (2) — — (2)Reallocation on exercise of stock options andperformance warrants — 417 (417) — —Reallocation on vesting of share units — 1,678 (1,678) — —Balance – December 31, 2016 122,914 932,094 61,654 (610,398) 383,350

The accompanying notes are an integral part of these consolidated financial statements. Refer to note 15 for further details on share capital.


Osum Oil Sands Corp.Consolidated Statements of Cash Flows(Expressed in thousands of Canadian dollars)

For the years ended December 31, 2017 2016Cash provided by (used in)Operating activities:

Net loss for the year (157,017) (48,617)Items not involving cash:

Depletion and depreciation (notes 9, 10) 218,841 7,477Unrealized foreign exchange gain on long-term debt (note 13) (17,784) (8,296)Shared-based compensation expense (note 15) 4,075 5,428Amortization of deferred transaction costs (note 13) 1,838 1,720Accretion (notes 12,14) 671 548Change in fair value of financial risk management contracts (note 7) (11,985) 30,374Onerous contract expense (recovery) (note 12) (380) 3,445Gain on disposition of property, plant and equipment (note 8) (14,922) —Deferred income tax expense (recovery) (note 11) (906) 15,853Deferred consideration (note 8) (353) —

Settlements of onerous contract (note 12) (1,142) (453)Settlements of share unit liabilities (note 15) (214) (577)Settlements of decommissioning liabilities (note 14) (371) (119)Funds flow from operating activities before changes in non-cash working capital 20,351 6,783Change in non-cash operating working capital (note 20) (1,953) (332)

Total cash flows from operating activities 18,398 6,451Investing activities:

Property, plant and equipment expenditures (note 9) (74,602) (24,246)Net recovery of (investment in) exploration, evaluation and other intangible assets (note 10) 247 (1,750)Proceeds from disposition of property, plant and equipment (net) (note 8) 90,993 —Proceeds from disposition of exploration, evaluation and other intangible assets (note 10) 2,114 —Change in abandonment deposits (14) (12)Change in non-cash investing working capital (note 20) 12,497 (3,671)

Total cash from (used in) investing activities 31,235 (29,679)Financing activities:

Proceeds from share issuance (net of costs) (note 15) 100,000 71Principal repayments of long-term debt (note 13) (2,695) (2,759)

Total cash flows from (used in) financing activities 97,305 (2,688)Increase (decrease) in cash in year 146,938 (25,916)Cash and cash equivalents – beginning of year 72,333 98,258Restricted cash – beginning of year 11,192 11,183Cash and cash equivalents – end of year 217,007 72,333Restricted cash – end of year 13,456 11,192



Osum Oil Sands Corp.Notes to the Consolidated Financial Statements(Expressed in thousands of Canadian dollars)


1. The Company

Osum Oil Sands Corp. (“Osum” or the "Company”) is a private company formed under the AlbertaBusiness Corporations Act on June 24, 2005. The Company’s primary activities are the operation anddevelopment of its in-situ bitumen properties in Alberta, Canada. These annual consolidated financialstatements encompass the Company and its wholly-owned subsidiaries, Osum Production Corp.(“OPC”) and Osum Holdings Corp. ("OHC").

The address of the Company’s head office is Suite 1900, 255-5th Avenue SW, Calgary, Alberta,Canada, T2P 3G6.

2. Basis of Preparation

These annual consolidated financial statements have been prepared in accordance with InternationalFinancial Reporting Standards ("IFRS") as issued by the International Financial Accounting StandardsBoard ("IASB") and Interpretations of the International Financial Reporting Interpretations Committee("IFRIC"). These consolidated financial statements are presented in Canadian dollars ("C$"), theCompany's functional currency, and all financial information is reported in thousands of dollars unlessotherwise noted.

These consolidated financial statements reflect the activities of the Company and its wholly-ownedsubsidiaries. All intercompany transactions, balances, income and expenses have been eliminated onconsolidation.

These consolidated financial statements were authorized for issue by the Board of Directors onMarch 13, 2018.

3. Significant Accounting Policies

(a) Joint operations

Some of the Company’s oil sands activities are conducted jointly with other entities. The consolidatedfinancial statements reflect only the Company’s proportionate interest in such activities.

(b) Revenue recognition

Revenue associated with the sale of proprietary blended bitumen is recognized when title passesfrom the Company to its customers. Royalties are recognized at the time of production. Realized riskmanagement gains and losses are recognized in the related contract month. Deferred considerationis recognized based on the ratio of production in the period to estimated proved plus probablereserves at the beginning of the period.

(c) Accounts receivable

Accounts receivable relate primarily to blended bitumen sales and realized risk management gainsreceivable, which are recorded based on the Company's revenue recognition policy described above.If applicable, an allowance for doubtful accounts is recorded to provide for specific doubtfulreceivables.

(d) Property, plant and equipment and exploration, evaluation and other intangible assets

(i) Recognition and measurement

Exploration, evaluation and other intangible assets

The Company accounts for exploration, evaluation and other intangible ("E&E") costs inaccordance with the requirements of IFRS 6 “Exploration for and Evaluation of MineralResources”. Eligible costs of exploring for and evaluating oil sands properties are capitalized andthe resulting E&E assets are disaggregated into project areas. Once a project area categorizedas an E&E asset has been assigned proved and/or probable reserves and has, in management’sopinion, demonstrated commercial viability through the use of established technology, the asset isassessed for impairment and then transferred to property, plant and equipment ("PP&E"). Whentransferred from E&E, the associated assets are grouped into cash generating units ("CGUs"),which represent groups of assets that generate cash flows from continuing use, largelyindependent of cash flows from other assets or groups of assets.

E&E costs related to each licence or prospect are initially capitalized within E&E assets. SuchE&E costs may include costs of licence acquisition, technical services and studies, seismicacquisition, exploration drilling and testing, pilot project costs, costs of retiring assets (if any) anddirectly attributable general and administrative ("G&A") costs, but do not include generalprospecting or evaluation costs incurred prior to having obtained legal rights to explore the area,which are expensed directly in net income (loss) as they are incurred.

Tangible assets acquired for use in E&E activities are classified separately within E&E and otherintangible assets and, once available for use, are depreciated based on their estimated useful life.To the extent that these assets are consumed as part of E&E activities, the associateddepreciation is capitalized as part of the applicable E&E asset.

Intangible exploration assets are not depleted and are carried forward until technical feasibilityand commercial viability of extracting a resource has been demonstrated.

Property, plant and equipment

Development and production items of PP&E are measured at cost less accumulated depletion,depreciation and impairment losses. Development and production assets are grouped into CGUsfor impairment testing.

(ii) Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability ofPP&E are recognized as capital investment only when they increase the future economic benefitsembodied in the specific asset to which they relate. All other expenditures, including the costs ofday-to-day maintenance of PP&E, are recognized in net income (loss) as incurred. Suchcapitalized investments generally represent costs incurred to develop proved or probablereserves to commence or enhance production from such reserves, and are accumulated on afield or area basis.



(iii) Depletion and depreciation

The net carrying values of producing oil and gas assets in PP&E are depleted using the unit ofproduction method by reference to the ratio of production in the period to the related proved plusprobable reserves, taking into account estimated future development costs necessary to producethe reserves. Costs for plant turnarounds are amortized over the period until the next plannedturnaround.

Corporate assets in PP&E and tangible equipment available for use in E&E activities aredepreciated over their estimated useful lives on a straight-line basis. These estimated useful livesfor the current and comparative year are as follows:

Joint venture infrastructure at Saleski 30 yearsJoint venture pilot facilities at Saleski 10 yearsCapitalized geological and geophysical software 10 yearsOffice furniture & equipment 5 yearsComputer hardware/software 3 yearsLeasehold improvements Term of lease

Other intangible assets held by the Company which have a finite useful life are amortized overthat useful life and measured at cost less accumulated amortization. Depreciation methods,useful lives and residual values are reviewed at each reporting date.

(iv) Disposition of a gross overriding royalty interest

The proceeds from the sale of a gross overriding royalty interest are assessed to determine theportion that relates to (1) a payment for a partial disposal of an interest in PP&E; and (2) anupfront payment received for costs expected to be incurred by the Company in relation to futureproduction of the royalty owner's share of proved plus probable reserves.

The portion of the proceeds representing the present value of estimated future costs in relation tothe royalty owner's share of reserves at the time of the sale is recorded as deferred considerationand recognized in revenue in the manner described in note 3 (b).

The portion of the proceeds attributable to the disposal of PP&E is compared with the royaltyshare of the carrying amount of the property, and the resultant gain or loss is recorded in netincome (loss).

(e) Impairment

(i) Financial assets

A financial asset is assessed at each reporting period date to determine whether there is anyobjective evidence that it is impaired. A financial asset is considered to be impaired if objectiveevidence indicates that one or more events have had a negative effect on the future cash flows ofthat asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as thedifference between its carrying amount and the present value of the estimated future cash flowsdiscounted at the original effective interest rate. An impairment loss in respect of an available-for-sale financial asset is calculated by reference to its fair value.



Individually significant financial assets are tested for impairment on an individual basis. Theremaining financial assets are assessed collectively in groups that share similar credit-riskcharacteristics.

All impairment losses are recognized in net income (loss). Any cumulative loss in respect of anavailable-for-sale financial asset recognized previously in equity is transferred to net income(loss).

An impairment loss is reversed if the reversal can be related objectively to an event occurringafter the impairment loss was recognized. For financial assets measured at amortized cost andavailable-for-sale financial assets that are debt securities, the reversal is recognized in netincome (loss).

(ii) Non-financial assets

The carrying amounts of the Company’s non-financial assets are reviewed at each reporting dateto determine whether there is any indication of impairment or that a previous impairment nolonger exists. If any such indication exists, then the asset’s recoverable amount is estimated.

E&E assets are assessed for impairment when they are reclassified to PP&E and also if facts andcircumstances suggest that the carrying amount exceeds the recoverable amount.

For the purpose of impairment testing, PP&E assets are grouped into CGUs, the smallest groupof assets that generates cash inflows from continuing use that are largely independent of cashflows of other assets or groups of assets. All E&E assets are assessed together as a groupedCGU. The recoverable amount is the higher of the fair value less costs to dispose and the valuein use. As IFRS requires value in use estimates to be based on budgets and forecasts thatgenerally extend no longer than five years, fair value less costs to dispose is used by theCompany as it is the higher amount. In estimating fair value less costs to dispose, recent markettransactions are taken into account, if available. In the absence of such transactions, an after-taxdiscounted cash flow model is used to estimate the fair value less costs to dispose of PP&Eassets, while the recoverable amount of E&E assets is estimated using fair values per barrel ofrecoverable resource.

An impairment loss is recognized if the carrying amount of a CGU exceeds its estimatedrecoverable amount. Impairment losses are recognized in net income (loss). Impairment lossesrecognized in prior periods are assessed at each reporting date for any indications that the losshas decreased or no longer exists. An impairment loss is reversed only to the extent that theCGU’s carrying amount does not exceed the carrying amount that would have been determined,net of depletion and depreciation, if no impairment loss had been recognized.

(f) Foreign currency translation

The measurement and reporting currency of the Company is the Canadian dollar. Transactions of theCompany that are denominated in foreign currencies are recorded in Canadian dollars at exchangerates in effect at the related transaction date. Monetary assets and liabilities denominated in foreigncurrencies are adjusted to reflect exchange rates at the end of the reporting period. Non-monetaryassets, including related depreciation, are translated at historical rates. Exchange gains and lossesarising on the translation of monetary assets and liabilities are included in the determination of netincome (loss) for the period.



(g) Share-based compensation

The Company uses the fair value based method of accounting for share-based compensation for allawards of shares, performance warrants, stock options, restricted share units ("RSUs"), andperformance share units ("PSUs") granted. For all awards expected to be settled in shares,compensation cost is recognized over the vesting period of the award based on the estimated fairvalue on the grant date with a corresponding increase to contributed surplus. Compensation cost forall share unit awards expected to be settled in cash is also recognized over the vesting period of theaward but since the cash-settled portion of the awards is accounted for as a liability, its fair value isassessed and adjusted (if necessary) at each reporting period.

Management utilizes a graded vesting model to calculate compensation expense for all stock optionsgranted. Since there is no progressive vesting associated with share unit awards, their compensationcost is recognized on a straight-line basis over the life of the awards. Management has incorporatedan estimated forfeiture rate in its vesting models and, where appropriate, the Black-Scholes pricingmodel is used to estimate the fair value of an award on the date of grant. Proceeds received on theexercise of stock options and performance warrants are included in share capital.

(h) Deferred income taxes

Deferred income taxes are accounted for using the liability method. Under this method, deferred taxassets and liabilities are recognized for the future tax consequences attributable to differencesbetween the financial statement carrying amounts of existing assets and liabilities and their respectivetax bases. Deferred tax assets and liabilities are measured using enacted or substantively enactedincome tax rates expected to apply to taxable income in the years in which those temporarydifferences are expected to be recovered or settled. The effect of a change in tax rates on deferredtax assets and liabilities is recognized in income in the year that the substantive enactment occurs.

Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and theyrelate to income taxes levied by the same tax authority on the same taxable entity.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will beavailable against which the temporary difference can be utilized. Deferred tax assets are reviewed ateach reporting date and are reduced to the extent that it is no longer probable that the related taxbenefit will be realized.

(i) Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal orconstructive obligation that can be estimated reliably, and it is probable that an outflow of economicbenefits will be required to settle the obligation. Provisions are determined by discounting theexpected future cash flows at a risk-free rate that reflects current market assessments of the timevalue of money and the risks specific to the liability.

Some of the Company’s activities give rise to decommissioning and site disturbance remediationactivities. Provision is made for the estimated cost of site restoration and is capitalized in the relevantasset category. The Company also recognizes a provision for an onerous contract on its head officelease. An onerous contract is a contract in which the aggregate cost required to fulfill the agreementis higher than the economic benefit expected to be obtained from it.



Provisions are measured at the present value of management’s best estimate of the expendituresrequired to settle the present obligation at the end of each reporting period. Subsequent to initialmeasurement, the obligation is adjusted utilizing the risk-free rate at the end of each reporting periodto reflect the passage of time and changes in the estimated future cash flows underlying theobligation. The increase in the provision due to the passage of time (accretion) is recognized as anexpense, whereas increases/decreases due to changes in the estimated future cash flows arecapitalized. Actual expenditures incurred upon settlement of the obligation are charged against theprovision to the extent the provision was established.

(j) Income (loss) per share

Basic income (loss) per share is calculated using the weighted average number of shares outstandingin the year. The Company uses the treasury stock method to calculate diluted income (loss) pershare. Diluted income (loss) per share excludes the effect of all outstanding options and warrants thatwould be anti-dilutive.

(k) Comprehensive income (loss)

Comprehensive income (loss) is comprised of net income (loss) and other comprehensive income(loss) ("OCI"). The Company does not have any transactions that give rise to OCI; therefore, its netincome (loss) and comprehensive income (loss) are the same amount.

(l) Equity

Callable common share purchase warrants are treated as equity instruments and common sharesissued pursuant to their exercise are recorded at the amount of proceeds received, less associatedshare issue costs.

(m) Financial instruments

Financial instruments, which are comprised of financial assets, financial liabilities, derivatives andnon-financial derivatives, qualify as assets or liabilities and are recorded on the statement of financialposition. Financial instruments are separated into five categories that determine their initialmeasurement and subsequent recognition of gains and losses. The categories are: (i) loans andreceivables (ii) assets held to maturity (iii) assets available for sale (iv) fair value through profit andloss and (v) financial liabilities at amortized cost.

The Company has designated its cash and cash equivalents, restricted cash, abandonment depositsand accounts receivable as “loans and receivables”, which are accounted for at amortized cost withassociated gains and losses recognized in net income (loss) in the period in which they are incurred.Due to the current nature of cash and cash equivalents, restricted cash, abandonment deposits andaccounts receivable, the fair value is equal to the carrying value at each reporting date.

The Company's financial risk management contract assets/liabilities and share unit liabilities arecategorized as "fair value through profit or loss". Financial risk management contracts are recognizedinitially at fair value and any attributable transaction costs are recognized in net income (loss) whenincurred. Subsequent to initial recognition, financial risk management contracts are measured at fairvalue, and changes therein are recognized immediately in net income (loss). Share unit liabilities areinitially measured at the estimated fair value on the grant date, and fair value is subsequentlyadjusted (if necessary) each reporting period. The compensation cost for all share unit awardsexpected to be settled in cash is recognized evenly over the vesting period.



The Company’s accounts payable and accrued liabilities and long-term debt have been designatedas “financial liabilities at amortized cost”. Long-term debt is recognized initially at fair value, net of anytransaction costs incurred, and subsequently at amortized cost using the effective interest method.

Financial liabilities are classified as current liabilities if payment is due within twelve months.Otherwise, they are presented as non-current liabilities.

The Company has not designated any financial instruments as “assets held to maturity” or “assetsavailable for sale”.

(n) Risk Management Contracts

The Company's financial risk management contracts are derivative instruments, but are not used fortrading or speculative purposes. The Company has not designated its financial risk managementcontracts as effective accounting hedges, and thus has not applied hedge accounting, even thoughthe Company considers the contracts to be economic hedges. Financial risk management contractsare recognized initially at fair value and any attributable transaction costs are recognized in netincome (loss) when incurred. Subsequent to initial recognition, financial risk management contractsare measured at fair value, and changes therein are recognized immediately in net income (loss).

The Company accounts for its physical delivery sales contracts, which are entered into and held forthe purpose of delivery of blended bitumen in accordance with its expected sale, as executorycontracts. As such, these contracts are not considered to be derivative financial instruments and arenot recorded at fair value on the balance sheet. Settlement of these physical sales contracts arerecognized in blended bitumen sales.



4. Critical Accounting Estimates

The timely preparation of financial statements in accordance with IFRS requires management tomake estimates and judgments that affect the reported amounts of assets and liabilities anddisclosure of contingencies at the dates of the annual consolidated financial statements and thereported amounts of revenues and expenses during the reporting period. Such estimates primarilyrelate to unsettled transactions and events as of the date of the consolidated financial statements.The estimated fair value of assets and liabilities, by their very nature, are subject to measurementuncertainty. Accordingly, actual results may differ materially from estimated amounts as futureconfirming events occur. Significant judgments, estimates and assumptions made by management inthe preparation of these consolidated financial statements are outlined below.

Sale of a royalty interest

When the Company sells a royalty interest linked to production at a specific property, judgment isrequired in assessing the appropriate accounting treatment of the transaction on the closing date andin future periods. The Company considers the specific terms of the arrangement to determinewhether it has entered into a financing arrangement, disposed of an interest in the reserves of aproperty, and/or received an upfront payment for future services. This assessment considers theeconomic substance of the arrangement including the Company's method of settlement, the risksassumed by the royalty owner, the duration of the arrangement, the property or properties to whichthe royalty applies, the timing of the royalty owner's investment including any potential futurepayments, any penalties for the Company failing to deliver the royalty, the royalty owner's involvementin the Company's ongoing decision-making, and any commitments made by the Company to developfuture expansions or projects at the property. To the extent it is determined that there is an upfrontpayment for future services, judgment is required to estimate the value of such services.

Bitumen reserves and resource

The estimation of reserves and resource involves the exercise of judgment. Forecasts are based onengineering data, estimated future prices, expected future rates of production and the cost and timingof future capital and operating expenditures, all of which are subject to many uncertainties andinterpretations. The Company expects that over time its reserves estimates will be revised eitherupward or downward based on updated information such as the results of future drilling, testing andproduction. Reserves and resource estimates can have a significant impact on net income (loss), asthey are a key component in the calculations of depletion and deferred consideration and fordetermining potential asset impairment or reversals thereof. Reserves and resource estimates forproperties in PP&E are prepared by independent reserve engineers at least annually. Independentlyprepared resource estimates for E&E properties may be prepared less frequently but at minimum arereviewed and, if necessary, updated by management annually.


The fair value of financial risk management contracts is dependent on estimates of forwardcommodity prices, differentials and foreign exchange rates. While forward prices and rates at thebalance sheet date were determined based on observable market data, they will likely differ fromfuture prices and rates and significantly impact the fair value of financial risk management contracts.

Carrying value of exploration and evaluation assets

The application of the Company’s accounting policy for E&E expenditures requires judgment indetermining whether it is likely that future economic benefit exists when activities have not reached astage where technical feasibility and commercial viability can be reasonably determined and whentechnical feasibility and commercial viability have been reached. Estimates and assumptions maychange as new information becomes available.

Identification of cash generating units

CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflowsthat are largely independent of the cash inflows of other assets or groups of assets. The classificationof assets into CGUs requires significant judgment and interpretations with respect to the integration



between assets, the existence of active markets, external users, shared infrastructures, and the wayin which management monitors the Company’s operations.

Provisions

Provisions are recognized for the future decommissioning and restoration of the Company’s oil andgas assets to be incurred at the end of their economic life. The reported amount of the obligation isbased on estimated future costs for the abandonment of the assets and reclamation of the site to itsoriginal state discounted at a risk-free rate and must be reevaluated each reporting period. Estimatingthe timing, amount and present value of these retirement costs requires significant judgment. By theirnature, these estimates, as they become available, are subject to measurement uncertainty, and theimpact on the consolidated financial statements could be material.

The Company recognizes a provision relating to its head office lease equal to the present value of thedifference between the minimum future lease payments that the Company is obligated to make underthe lease until its expiry, including estimated future operating costs, less estimated subleaserecoveries. Actual recoveries and operating costs may differ significantly from these estimates.

In addition, the Company makes estimates of potential provisions owing within accounts payable andaccrued liabilities, which may include amounts disputed in the normal course of business. Amountsultimately paid may differ significantly from these estimates.

Share-based compensation

The Company uses a fair value-based method of accounting for share-based compensation for allawards of shares, performance warrants, stock options, RSUs and PSUs. The Black-Scholes pricingmodel is used to estimate the fair value of stock options and performance warrants on the date ofgrant. The Black-Scholes pricing model includes inputs such as discount rates, expected exercisedates, and expected volatility, which are subject to judgment and may not be indicative of futureexperience. Into its vesting models, management has incorporated an estimated forfeiture rate, whichis also subject to judgment. The liability for the portion of share unit awards that is expected to besettled in cash is based on management's estimate of the Company's share price at the reportingdate and an assumption that staff will elect to receive the maximum cash award. As the Company is aprivate entity, its estimated share price is subject to significant judgment.

Deferred income taxes

The determination of deferred income tax assets and liabilities requires interpretation of complex lawsand regulations, and they are recognized at tax rates expected to be in effect at the estimated timingof reversal of temporary differences between the accounting and tax treatment of certain assets andliabilities. To the extent these judgments change, there may be a significant impact on theconsolidated financial statements of future periods.

Deferred income tax assets are recognized to the extent that it is probable that the deductibletemporary differences will be recoverable in future periods. The recoverability assessment involves asignificant amount of estimation including an evaluation of when the temporary differences willreverse, an estimation of the amount of future taxable earnings, the availability of taxable income tooffset the tax assets when the reversal occurs and the application of tax laws. To the extent thatassumptions used in the recoverability assessment change, there may be a significant impact onthe consolidated financial statements of future periods.



5. Future Accounting Policies

(a) IFRS 15 – Revenue from contracts with customers

IFRS 15 – Revenue from contracts with customers, intended to replace IAS 18 – Revenue, IAS 11 –Construction Contracts, and related interpretations, specifies how and when an IFRS reporter willrecognize revenue as well as requiring more informative, relevant disclosures. The standard providesa single, principles-based five-step model to be applied to all contracts with customers. The standardrequires an entity to recognize revenue to reflect the transfer of goods and services for the amount itexpects to receive when the control is transferred to the purchaser. IFRS 15 was issued in May 2014and applies to annual reporting periods beginning on or after January 1, 2018, with early adoptionpermitted.

The Company intends to adopt IFRS 15 in its financial statements for the annual period beginning onJanuary 1, 2018. The Company is currently assessing and evaluating the impact of the standard onthe financial statements. The Company anticipates there will be additional enhanced disclosuresupon adoption.

(b) IFRS 9 – Financial instruments

IFRS 9 – Financial Instruments, intended to replace IAS 39 – Financial Instruments: Recognition andMeasurement, uses a single approach to determine whether a financial asset is measured atamortized cost or fair value, replacing the multiple rules in IAS 39. The new standard also requires asingle impairment method to be used, replacing the multiple impairment methods in IAS 39, andincorporates a substantially reformed approach to hedge accounting. IFRS 9 is effective for annualperiods beginning on or after January 1, 2018, with early adoption permitted.

The Company intends to adopt IFRS 9 in its financial statements for the annual period beginning onJanuary 1, 2018. The Company expects that there will not be any material changes in themeasurement and carrying values of the Company's financial instruments as a result of the adoptionif IFRS 9. Further, IFRS 9 also contains a new model to be applied for hedge accounting, however theCompany does not currently apply hedge accounting to its risk management contracts nor does itintend to upon adoption of IFRS 9.

(c) IFRS 16 – Leases

IFRS 16 – Leases, intended to replace IAS 17 – Leases, brings most leases on-balance sheet forlessees under a single model, eliminating the distinction between operating and finance leases.Lessor accounting however remains largely unchanged and the distinction between operating andfinance leases is retained. IFRS 16 is effective for annual periods beginning on or after January 1,2019 and the Company intends to adopt IFRS 16 in its financial statements for the annual periodbeginning on January 1, 2019. The extent of the impact of adoption of the standard has not yet beendetermined.



6. Restricted Cash

As at December 31, 2017, the Company had pledged $13,456 (December 31, 2016 – $11,192) inGuaranteed Investment Certificates as security for letters of credit in support of ongoing businessoperations and contractual commitments.

7. Risk Management Contracts


The Company recorded the following net gains (losses) related to its financial risk managementcontracts:

For the years ended December 31, 2017 2016Realized gain (loss) (7,914) 14,744Change in fair value 11,985 (30,374)Premiums paid — (612)Gain (loss) on financial risk management contracts 4,071 (16,242)

The following financial risk management contracts were in place as at December 31, 2017, and therelated fair values were recorded on the consolidated statement of financial position:

Contract Notional Price Remaining Term Fair ValueSwap – WTI/WCS differential 3,855 bbl/d $(21.50) Jan 1/18 - Mar 31/18 2,913Swap – WTI/WCS differential 3,240 bbl/d $(22.70) Jan 1/18 - Dec 31/18 2,966Swap – WTI/WCS differential 3,660 bbl/d $(19.70) Apr 1/18 - Jun 30/18 1,109Swap – WTI/WCS differential 3,974 bbl/d $(19.18) Jul 1/18 - Sep 30/18 1,406Swap – WTI/WCS differential 1,646 bbl/d $(20.86) Oct 1/18 - Dec 31/18 621Swap – WTI/WCS differential 4,041 bbl/d $(20.02) Jan 1/19 - Mar 31/19 1,385Swap – WTI/WCS differential 1,616 bbl/d $(21.39) Apr 1/19 - Jun 30/19 284Total unrealized financial risk management assets 10,684

Contract Notional Price Remaining Term Fair ValueSwap – WTI 2,881 bbl/d $71.13 Jan 1/18 - Mar 31/18 (1,192)Swap – WTI 2,375 bbl/d $73.50 Jan 1/18 - Dec 31/18 (673)Swap – WTI 2,729 bbl/d $62.54 Apr 1/18 - Jun 30/18 (3,119)Swap – WTI 2,968 bbl/d $65.84 Jul 1/18 - Sep 30/18 (2,174)Swap – WTI 4,008 bbl/d $69.48 Oct 1/18 - Dec 31/18 (1,117)Swap – WTI 2,993 bbl/d $63.26 Jan 1/19 - Mar 31/19 (2,163)Swap – WTI 1,550 bbl/d $66.21 Apr 1/19 - Jun 30/19 (567)Total unrealized financial risk management liabilities (11,005)

The fair market value measurements are categorized as level 2 as they are based on quoted WTI andWTI/WCS differential prices from independent pricing services in active markets for similar assets orliabilities.



The following table sets out the impact of changes in forward commodity prices on net loss beforetaxes related to changes in the fair value of financial risk management contracts in place as atDecember 31, 2017:

Price or rate Change Impact on net loss before taxesWTI $1.00/bbl 2,427WTI/WCS differential $1.00/bbl 2,890

Subsequent to December 31, 2017, the Company entered into financial risk management contractswith the following terms:

Contract Notional Price TermSwap – WTI/WCS differential 400 bbl/d $(30.25) Oct 1/18 - Mar 31/18Swap – WTI/WCS differential 1,100 bbl/d $(31.13) Oct 1/18 - Jun 30/19Swap – WTI/WCS differential 3,025 bbl/d $(28.72) Oct 1/18 - Sep 30/19Swap – WTI 590 bbl/d $71.08 Oct 1/18 - Dec 31/18Swap – WTI 4,867 bbl/d $72.25 Jan 1/19 - Mar 31/19Swap – WTI/WCS differential 2,055 bbl/d $(28.62) Jan 1/19 - Mar 31/19Swap – WTI 2,697 bbl/d $71.09 Apr 1/19 - Jun 30/19Swap – WTI 4,480 bbl/d $69.86 Jul 1/19 - Sep 30/19Swap – WTI/WCS differential 3,025 bbl/d $(25.22) Jul 1/19 - Sep 30/19

Credit and counterparty concentration risks related to the financial risk management contracts areconsidered acceptable due to the size and financial strength of the counterparties.

Physical risk management contracts

For the year ended December 31, 2017, the Company did not have any physical risk managementcontracts in place. For the year ended December 31, 2016, the Company recorded a realized loss of$70 within blended bitumen sales related to its physical risk management contracts.



8. Sale of a Royalty Interest

On September 29, 2017, the Company sold a 4.0% gross overriding royalty interest on its Orionproperty for cash proceeds of $92,500, before transaction costs. The sale had an effective date ofSeptember 1, 2017. The royalty interest applies to all current and future production from the Orionproperty and the owner of the royalty has the option of being paid either in cash or in kind. As part ofthe sale agreement, the proceeds are to be used for the development of the Orion property.

The Company applied judgment in concluding that the proceeds from the sale of the royalty interestcomprised two components: (1) a payment for partial disposal of an interest in PP&E; and (2) anupfront payment received for costs expected to be incurred by the Company in relation to futureproduction of the royalty owner's 4.0% share of proved plus probable reserves.

The Company recorded deferred consideration of $64,400, representing the present value ofestimated future costs at the time of the sale. The remaining net proceeds of $26,593 were comparedto the carrying value attributable to the partial disposal of PP&E, and resulted in the recognition of again on sale of $14,922.

At December 31, 2017, total deferred consideration was $64,047, of which $1,336 is classified ascurrent. Deferred consideration of $353 was recorded as revenue during the year endedDecember 31, 2017 based on the ratio of production in the period to the estimate of proved plusprobable reserves in effect at the end of the period, adjusted for production during the period.



9. Property, Plant and Equipment

Developmentand production

assetsCorporate

assets TotalCostBalance – December 31, 2016 611,794 5,238 617,032Additions 71,108 134 71,242Capitalized general and administrative expenses 3,360 — 3,360Capitalized share-based compensation 611 — 611Disposition (note 8) (16,520) — (16,520)Changes to decommissioning assets 4,188 — 4,188Balance – December 31, 2017 674,541 5,372 679,913

Accumulated depletion, depreciation and impairmentBalance – December 31, 2016 (104,731) (4,878) (109,609)Depletion and depreciation (34,690) (234) (34,924)Impairment (135,525) — (135,525)Disposition (note 8) 4,849 — 4,849Balance – December 31, 2017 (270,097) (5,112) (275,209)

Carrying amountsBalance – December 31, 2016 507,063 360 507,423Balance – December 31, 2017 404,444 260 404,704

Developmentand production

assetsCorporate

assets TotalCostBalance – December 31, 2015 586,790 5,216 592,006Additions 21,867 22 21,889Capitalized general and administrative expenses 2,357 — 2,357Changes to decommissioning assets 325 — 325Capitalized share-based compensation 445 — 445Capitalized depreciation 10 — 10Balance – December 31, 2016 611,794 5,238 617,032

Accumulated depletion, depreciation, and impairmentBalance – December 31, 2015 (97,551) (4,592) (102,143)Depletion and depreciation (40,180) (286) (40,466)Impairment (116,871) — (116,871)Impairment reversal 149,871 — 149,871Balance – December 31, 2016 (104,731) (4,878) (109,609)


During the year ended December 31, 2017, the Company recorded $34,232 (2016 – $38,999) ofdepletion and $458 (2016 – $1,171) of depreciation related to its Orion oil sands project. TheCompany included $1,211,000 of future development costs associated with proved plus probablereserves in its depletion calculation for the period ended December 31, 2017 (2016 – $1,538,000).

Impairment Assessments

During 2017 the Company observed a decline in the average long-term price forecasts of a number ofreserve engineering firms. The Company considered the price forecast decline an indicator ofimpairment for its Taiga CGU and performed an impairment test at December 31, 2017.



The Company estimated the recoverable amount of its Taiga CGU based on fair value less costs ofdisposal calculations. The fair value of the CGU was estimated based on the present value of after-tax cash flows resulting from production from proved and probable reserves from 2018 to 2066 usingassumptions consistent with those used by the Company’s independent reserve evaluator, includingcapital and operating cost estimates, corporate tax rates, and a cost inflation factor of two percent,and using an after-tax discount rate of 12%. The following forward prices and foreign exchange rateswere used to estimate the recoverable amount as at December 31, 2017:

Year

WesternCanadian


(US$/bbl)

Diluent(condensate)

(C$/bbl)AECO gas



Source: Average of GLJ Petroleum Consultants, McDaniel & Associates Consultants, Sproule Associates and Deloitte Research Evaluation &Advisory price forecasts, effective January 1, 2018.

Based on the calculations performed, the Company recorded an impairment charge on its Taiga CGUof $135,525.

Impairment testing was also performed at December 31, 2016. The recoverable amount of the OrionCGU exceeded the carrying value and no impairment was recorded for the Orion CGU atDecember 31, 2016.

At December 31, 2016 the recoverable value of the Taiga CGU exceeded the carrying value and thefull inception to date impairment charge on the Taiga CGU of $149,871 was reversed. The reversalwas a result of lower forecast operating and capital costs.



The following forward prices and foreign exchange rates were used to estimate the recoverableamounts as at December 31, 2016:

Year

WesternCanadian


(US$/bbl)

Diluent(condensate)

(C$/bbl)AECO gas


(US$/C$)2017 53.26 55.00 70.44 3.39 0.762018 57.92 60.21 74.34 3.22 0.782019 61.54 64.70 77.72 3.32 0.812020 64.85 69.10 81.12 3.64 0.832021 67.98 73.84 84.59 3.82 0.852022 71.51 77.10 89.19 3.95 0.852023 73.45 79.01 90.61 4.12 0.852024 75.45 80.96 92.88 4.30 0.852025 77.44 82.92 95.48 4.41 0.85Remainder +2.0% per year +2.0% per year +2.0% per year +2.0% per year 0.85Source: Average of GLJ Petroleum Consultants, McDaniel & Associates Consultants, Sproule Associates and Deloitte Research Evaluation &Advisory price forecasts, effective January 1, 2017

For the year ended December 31, 2017, an increase to the after-tax discount rate used in theCompany's impairment test of 1% would have resulted in additional impairment of $72,065 and a $2decrease to the US$ WTI price would have resulted in additional impairment $74,900.

The fair value measurements are categorized as level 3 with inputs that are not based on observablemarket data.



10. Exploration, Evaluation and Other Intangible Assets

Exploration andevaluation assets

Other Intangibleassets Total

CostBalance – December 31, 2016 482,157 416 482,573Additions (recoveries) (309) — (309)Capitalized depreciation 1,794 — 1,794Capitalized general and administrative expenses 62 — 62Capitalized share-based compensation 12 — 12Changes to decommissioning assets (145) — (145)Disposition (2,114) — (2,114)Balance – December 31, 2017 481,457 416 481,873

Accumulated depreciation and impairmentBalance – December 31, 2016 (403,812) (251) (404,063)Depletion and depreciation (1,794) (21) (1,815)Impairment (48,371) — (48,371)Balance – December 31, 2017 (453,977) (272) (454,249)


Exploration andevaluation assets

Other Intangibleassets Total

CostBalance – December 31, 2015 478,964 416 479,380Additions 1,126 — 1,126Capitalized depreciation 1,536 — 1,536Capitalized general and administrative expenses 624 — 624Changes to decommissioning assets (223) — (223)Capitalized share-based compensation 130 — 130Balance – December 31, 2016 482,157 416 482,573

Accumulated depreciation and impairmentBalance – December 31, 2015 (402,276) (230) (402,506)Depletion and depreciation (1,536) (21) (1,557)Balance – December 31, 2016 (403,812) (251) (404,063)




During the year ended December 31, 2017, the Company's partner and operator of the Saleski jointventure disposed of certain assets of the joint venture. The net proceeds attributable to theCompany's 40% working interest in the assets were $2.1 million, which approximated the assets'carrying value.

Impairment assessment

The Company's E&E assets are comprised of its Saleski Joint Venture, Saleski West, Sepiko Kesik,and Liege properties, located in the Saleski area and its Portage property located in the Athabascaarea.

During 2017 the Company observed a decline in the average long-term price forecasts of a number ofreserve engineering firms. The Company considered the price forecast decline an indicator ofimpairment and assessed the recoverable amount of its grouped CGU. Based on the test performed,the Company recorded impairment of $48,371 (2016 – nil).

The recoverable amount of the Company's E&E assets was estimated using a fair value per barrel ofrecoverable resource reflective of the current commodity price environment. The fair valuemeasurement was categorized as level 3 with inputs that are not based on observable market data.



11. Deferred Taxes

The Company’s net deferred tax asset resides in the OPC legal entity and is comprised of thefollowing, which are classified by source of temporary differences:

December 31, 2017 December 31, 2016Non-capital losses 78,334 55,412Petroleum & natural gas properties 3,802 2,511Decommissioning liabilities 498 358Risk management contracts 87 3,322Deferred consideration 17,293 —Unrecognized deferred tax assets (70,442) (35,337)Unrealized foreign exchange on account of capital 4,882 7,282Deferred tax asset 34,454 33,548

As at December 31, 2017, the Company had approximately $1,031,608 (December 31, 2016 –$1,066,661) in consolidated available tax pools, including operating loss carry forwards for income taxpurposes in the amount of $489,023 (December 31, 2016 – $424,845) which are available to offsetfuture taxable income. These operating losses start to expire in 2031.

The provision for income taxes reported differs from the amounts computed by applying thecumulative federal and provincial income tax rates to the income before tax provision due to thefollowing:

For the years ended December 31, 2017 2016Income (loss) before income taxes (157,923) (32,764)Statutory tax rate 27% 27%

(42,639) (8,846)Permanent differences (2,394) (1,113)Stock based compensation 1,100 1,466Change in uncertain tax position (SRED ITC) (1,618) —Tax provision true up to the tax return (548) 3,551Change in unrecognized deferred tax assets 44,749 20,644Other 444 151Deferred tax expense (recovery) (906) 15,853

The Canadian statutory tax rate from the rate reconciliation above represents the combined federaland provincial corporate tax rate. The federal corporate tax rate is 15.0% and the Alberta provincialtax rate is 12.0%.



12. Provision

Provision for onerous contract

At December 31, 2017, the total provision for an onerous lease contract related to the Company'sCalgary head office lease was $1,511 (December 31, 2016 – $3,005), of which $1,208 (December 31,2016 – $1,157) was recorded within accounts payable, accrued liabilities and provision, and $303(December 31, 2016 – $1,848) as a non-current provision.

For the years ended December 31, 2017 2016Balance – beginning of year 3,005 —Liabilities incurred — 2,403Change in estimated future cash flows (380) 1,042Liabilities settled (1,142) (453)Accretion 28 13Balance – end of year 1,511 3,005Less: current portion of provision 1,208 1,157Non-current portion of provision 303 1,848

The provision represented the present value of the difference between the estimated minimum futurelease payments that the Company is obligated to make under the lease until its expiry on March 31,2019, less estimated sublease recoveries. At December 31, 2017, these cashflows were discountedusing a risk-free discount rate range of 0.9% to 1.7% (December 31, 2016 – 0.8%). This estimatemay fluctuate in future periods as a result of changes in estimated sublease recoveries and actuallease payments.

13. Long-term Debt

December 31, 2017 December 31, 2016Senior secured term loan – US$ 203,175 205,275Year end exchange rate – US$1 = C$ 1.2573 1.3442Senior secured term loan – C$ 255,452 275,931Less: unamortized deferred debt issue costs (5,325) (7,163)

250,127 268,768Less: current portion of long-term debt (2,640) (2,823)Long-term debt 247,487 265,945

The Company's senior secured credit facility is comprised of a US$210,000 senior secured term loanmaturing on July 31, 2020 and a US$15,000 senior secured revolving loan maturing on July 31, 2019.The term loan bears interest at a floating rate based on the greater of LIBOR or 1%, plus a creditspread of 5.5%. The term loan is to be repaid in quarterly installments totaling 1% per annum of theoriginal principal, with the balance due on July 31, 2020.

During the year ended December 31, 2017 and 2016, the Company made scheduled principalrepayments totaling US$2,100 (2017 – C$2,695, 2016 – C$2,759) on the term loan. During the yearended December 31, 2017, $1,838 (2016 – $1,720) of deferred debt issue costs were amortizedagainst the loan balance.

The fair market value of the Company's long-term debt as at December 31, 2017 was approximately$227,068 (December 31, 2016 – $208,889), compared with a carrying amount of $255,452(December 31, 2016 – $275,931). The fair market value measurement is categorized as level 2 as itis based on quoted prices in inactive markets.

As at December 31, 2017 and December 31, 2016, the revolving loan was undrawn. The seniorsecured credit facilities are subject to certain covenants by OPC, including maintaining minimumratios of asset values to net senior secured debt. OPC was in compliance with all loan covenants asat December 31, 2017 and December 31, 2016.



14. Decommissioning Liabilities

For the years ended December 31, 2017 2016Balance – beginning of year 31,861 31,343Liabilities incurred 1,916 —Liabilities settled (371) (119)Changes to discount rates 262 (1,106)Changes in estimates 1,865 1,208Accretion 643 535Balance – end of year 36,176 31,861

As at December 31, 2017, the Company estimated that the expenditures required to settle thedecommissioning liabilities will be made over the next 38 years with the majority of payments beingmade around 2045. As at December 31, 2017, the Company used discount rates ranging from 1.7%

to 2.3% (December 31, 2016 – 0.7% to 2.3%) based on the Bank of Canada’s risk-free bond ratesand an inflation rate of 1.7% (December 31, 2016 – 1.8%) to calculate the present value of thedecommissioning liabilities.



15. Share Capital

(a) Authorized

Unlimited number of voting common shares without nominal or par value.

(b) Callable common share purchase warrants

In connection with previous equity financings, the Company issued callable common share purchasewarrants to investors who concurrently subscribed for an equivalent number of common shares.

On December 1, 2016, the Company called all of the 8,000,000 then outstanding common sharepurchase warrants with an exercise price of $12.50 per warrant and the related proceeds of $100,000were received in February of 2017.

(c) Stock options

During the second quarter of 2017, the Company's Board of Directors approved the issuance of555,500 stock options to employees and directors with an effective grant date of March 30, 2017.During the second half of 2017, the Company granted an additional 14,100 stock options to newemployees. The stock options expire six years from the grant date and vest in four equal tranches:25% on the grant date and 25% on each of the three subsequent anniversary dates. Fair values of$0.99 to $1.01 per stock option were estimated on the grant dates based on the followingassumptions:

AssumptionShare price on grant date $ 2.25Exercise price $ 2.25Expected volatility 50%Expected life 5 yearsRisk-free interest rate 1.10% to 1.65%Expected forfeiture rate 12%

During the second quarter of 2016, the Company's Board of Directors approved the issuance of4,280,455 stock options to employees, contractors, and directors of the Company at an exercise priceof $2.25 per share with an effective grant date of March 15, 2016. The stock options expire six yearsfrom the grant date and vest in four equal tranches: 25% on the grant date and 25% on each of thethree subsequent anniversary dates. A fair value of $0.98 per stock option was estimated on the dateof the grant based on the following assumptions:

AssumptionShare price on grant date $ 2.25Exercise price $ 2.25Expected volatility 50%Expected life 5 yearsRisk-free interest rate 0.78%Expected forfeiture rate over the life 12%

Concurrent with the grant, employees, contractors and directors surrendered and the Companycanceled 5,486,908 stock options with an exercise price of $8.11 or $9.00, resulting in the immediaterecognition of $986 of stock-based compensation expense for the portion of canceled stock optionsthat had not yet vested.

A summary of the changes in options outstanding under the stock option plan is as follows:

For the years endedDecember 31, 2017 December 31, 2016

Number ofoptions

(thousands)

Weightedaverage

exercise priceNumber of

options (000s)

Weightedaverage

exercise priceBalance – beginning of year 5,578 3.02 7,757 8.01Granted 570 2.25 4,280 2.25Exercised — — (152) 0.23Forfeited (593) 5.45 (820) 7.50Canceled — — (5,487) 8.89Balance – end of year 5,555 2.68 5,578 3.02

The following is a summary of the number of stock options outstanding and exercisable as atDecember 31, 2017:

Exercise priceNumber outstanding

(thousands)Exercisable(thousands)

Weighted averageremaining life

$0.15 75 75 3.0 years$1.00 25 25 3.0 years$2.25 4,554 2,213 4.3 years$3.00 564 564 3.0 years$8.11 120 120 0.7 years$9.00 217 205 2.7 years

5,555 3,202 4.0 years



On March 13, 2018 the Company's Board of Directors approved a grant of up to 0.6 million stockoptions to employees, officers and directors with an exercise price of $2.50.

(d) Performance warrants

At December 31, 2017 and December 31, 2016, the Company had 11,895 vested and exercisableperformance warrants outstanding at an exercise price of $0.15 per performance warrant. Allunexercised performance warrants expire in October 2018.

(e) Restricted Share Units ("RSUs") and Performance Share Units ("PSUs")

During the year ended December 31, 2017, the Company's Board of Directors approved the issuanceof 811,900 RSUs and 1,168,950 PSUs to employees and directors of the Company. The RSUs andPSUs granted vest all at once on the third anniversary date. The number of PSUs that ultimately vestis subject to the Company satisfying certain performance criteria within a target range set by theCompany's Board of Directors. A multiplier (ranging from 0.5 to 2.0) will be applied to any vestedPSUs to the extent such performance criteria are satisfied. The performance factor for the PSUsgranted in the period was assumed to be 1.0 on the grant date.

Notwithstanding the Board's discretion to settle vested units in cash or with shares, according to theterms of the share unit plan, a unitholder may elect to receive up to 50 percent of their vested units inthe form of a cash payment. The Company therefore treats the share units 50% equity-settled and50% cash-settled.

During the year ended December 31, 2017, 133,625 RSUs and 76,526 PSUs (2016 – 239,664 RSUsand 225,521 PSUs) vested resulting in 49,042 (2016 – 102,019) shares being issued and $214 (2016– $577) of cash payments. The RSUs and PSUs were settled 50% in cash and 50% in shares with aweighted average PSU performance factor of 0.9 (2016 – 0.5).

A summary of the changes in RSUs and PSUs outstanding is as follows:

For the years ended December 31, 2017 2016(thousands) RSUs PSUs RSUs PSUsBalance – beginning of year 1,237 1,956 388 307Granted 812 1,169 1,133 1,899Forfeited (110) (102) (44) (24)Vested and settled (134) (82) (240) (226)Balance – end of year 1,805 2,941 1,237 1,956

As at December 31, 2017, the Company's share unit liabilities for those RSUs and PSUs expected tobe settled in cash were recorded using an estimated fair value of $2.50 per share unit (December 31,2016 – $2.25) and performance factors for the PSUs ranging from 0.9 to 1.1 (2016 – 1.0).

As at December 31, 2017, $164 of the Company's share unit liabilities were classified as current(December 31, 2016 – $113), relating to those RSUs and PSUs scheduled to vest in the next twelvemonths, while $3,306 (December 31, 2016 – $1,180) were classified as non-current.

On March 13, 2018 the Company's Board of Directors approved a grant of up to 0.7 million RSUs and1.2 million PSUs to employees, officers and directors.



(f) Contributed surplus

The table below summarizes activity in the contributed surplus account (excludes share-basedcompensation associated with share units expected to be settled in cash, which is reported as aliability on the consolidated statements of financial position):

For the years ended December 31, 2017 2016Balance – beginning of year 61,654 58,975Share-based compensation 2,306 4,774Share units vested (183) (1,678)Stock options and performance warrants exercised — (417)Balance – end of year 63,777 61,654

(g) Per share amounts

The table below summarizes the weighted average number of common shares outstanding used inthe calculation of basic and diluted loss per common share:

(thousands)For the years ended December 31, 2017 2016Weighted average common shares outstanding 130,119 122,485Effect of dilutive securities 1,396 873Weighted average common shares outstanding, diluted 131,515 123,358

Basic net loss per share was calculated using the weighted average number of shares outstanding forthe period. The Company uses the treasury stock method to calculate net loss per share. Thecalculation of diluted weighted average common shares excludes shares related to stock options andwarrants that are anti-dilutive. For the years ended December 31, 2017 and 2016, the Company's netloss per share did not differ from diluted loss per share as a net loss cannot be diluted.



16. Capital Management

The Company's capital includes its working capital, senior secured credit facilities and share capital.At December 31, 2017, the Company had $213.2 million of working capital, before the currentportions of net unrealized hedging liabilities and deferred consideration. The total reflects the receiptof $100 million of proceeds from the common share purchase warrants in February 2017, the sale ofa 4.0% GORR on Orion for cash proceeds of $92.5 million, before transaction costs and adjustments,in September 2017 as well as the cash contribution from the Company's Orion operation during theyear.

The Company's term loan matures on July 31, 2020 and at December 31, 2017 it was in fullcompliance with its asset-based financial covenants. Further, the Company has access to a US$15,000 revolving line of credit which matures on July 31, 2019 and is currently undrawn. Details ofthe Company’s debt and equity capital are discussed in notes 13 and 15, respectively.

A portion of the Company's available capital resources are committed to funding the costs of theexpansion of the Orion facility and the drilling of new wells in 2018 which are expected to lead to asignificant increase in production and cash flows from operations in 2019.

As a means to manage its capital exposure, the Company has an active commodity hedgingprogram, targeting 60% of forecast production volumes, net of maximum royalties, for the forward 12months and 30% of volumes for the next 6 months, executed on a rolling basis. In late 2017, inanticipation of of the sanction of the next phase of expansion at Orion, the Company adjusted itshedging policy for the 2018 calendar year to 70% of forecast production volumes to better manageprice volatility during the period of Orion facility construction and production ramp up.



17. Risk Management

Credit Risk

Credit risk is the risk that the counterparty to a financial asset will default, resulting in the Companyincurring a financial loss. The Company evaluates credit risks on an ongoing basis, including a reviewof counterparty credit ratings. Osum’s objective is to have no credit losses. The primary sources ofcredit risk for the Company arise from cash and cash equivalents, accounts receivable, riskmanagement contracts and the sublease on a portion of the Company’s leased head office space.Credit risk for the Company is considered to be low. Cash and cash equivalents consist of cashcurrently held in Government of Alberta guaranteed business or special interest savings accounts.The Company's risk management assets and the vast majority of the Company's accountsreceivable, which relate to blend sales revenue, are owed by a small number of large, well-established oil and gas entities and financial institutions. At December 31, 2017, the Company'sestimated maximum exposure to credit risk related to customers was inconsequential as receivablesrelated to revenue and risk management contracts in the year ended December 31, 2017 have beenrecovered subsequent to the balance sheet date. There were no significant amounts that were agedgreater than 90 days as at December 31, 2017.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet obligations associated with financialliabilities as they become due, including interest and principal related to its long-term debt. TheCompany's financial liabilities also include accounts payable and accrued liabilities which arecomposed primarily of amounts due in respect of the development and operation of the Company’sprojects along with risk management contracts and certain other corporate expenses. Payment termson these amounts are typical trade terms for the industry and generally do not bear interest. TheCompany frequently assesses its liquidity position and obligations by preparing regular short-termand long-term cash flow forecasts. Liquidity risk is mitigated by ensuring all investments are shortterm and a sufficient cash balance is maintained to meet expected future payments. The Companyalso has access to its US$15,000 revolving loan, which was undrawn at December 31, 2017. Seefurther discussion on capital management in note 16.

Market Risk

Market risk is the risk that the fair value of future cash flows of financial assets or liabilities willfluctuate due to movements in market prices. Market risks include interest rate risk, foreign currencyrisk, and commodity price risk. The Company evaluates market risks on an ongoing basis, includingconsideration of possible hedging strategies, and assesses the impact of variability in identifiedmarket risks on medium-term cash requirements.

(i) Commodity price risk

Commodity price risk arises from the effect that fluctuations of future commodity prices may have onthe fair value of future cash flows or financial assets or liabilities. Commodity prices have fluctuatedwidely during recent years due to global and regional factors including supply and demandfundamentals, inventory levels, transportation restrictions and weather, economic, and geopoliticalfactors. Commodity prices have an effect on the amount of revenue earned by the Company on thesale of its bitumen production and impact the amount the Company pays for natural gas, electricity,and diluent, which are all costs incurred in the process of producing and transporting bitumen for sale.

To mitigate fluctuations in commodity prices the Company maintains an active commodity hedgingprogram. The Company's hedging objective is to increase the certainty of Canadian-dollar operatingcash flows as a source of funding by reducing commodity price volatility through the use of financiallyand physically settled derivatives to hedge on a rolling basis up to 60% of its forecast bitumenproduction, net of maximum royalties for the forward 12-month period and 30% of volumes for thenext 6-month period. In late 2017, in anticipation of of the sanction of the next phase of expansion atOrion, the Company adjusted its hedging policy for the 2018 calendar year to 70% of forecastproduction volumes to better manage price volatility during the period of Orion facility constructionand production ramp up.

(ii) Foreign currency risk

Foreign currency risk is the risk that a variation in exchange rates between the Canadian dollar andforeign currencies will affect the fair value or future cash flows of the Company's financial assets orliabilities. The Company has US dollar denominated long-term debt as described in note 13 andtherefore makes interest and principal payments in US dollars. As at December 31, 2017, a C$0.10change in the exchange rate of US$1 = C$1.2573 (increase – US$1 = C$1.3573, decrease – US$1 =C$1.1573) would have resulted in a corresponding change in the carrying value of long-term debt of$20,318 (December 31, 2016 – $20,528).

The Company’s revenues are based on the US dollar, since revenue received from the sale ofbitumen and bitumen blend is generally referenced to a price denominated in US dollars. TheCompany incurs most of its operating and other costs in Canadian dollars. As a result, the Companyis impacted by exchange rate fluctuations between the US dollar and the Canadian dollar, and anystrengthening of the Canadian dollar relative to the US dollar could negatively impact the Company’soperating margins and cash flows. To mitigate this risk, the Company's commodity hedges notedabove are denominated in Canadian dollars.

(iii) Interest rate risk

The Company is exposed to interest rate cash flow risk on its floating rate long-term debt. During theyear ended December 31, 2017, a 100 basis point increase in LIBOR on floating rate debt wouldhave increase the Company's net loss before taxes by $2,665 (2016 – $736) while a 100 basis pointdecrease in LIBOR would have decrease the Company's net loss before taxes by $416 (2016 – $0).



18. Net Finance Costs

For the years ended December 31, 2017 2016Interest expense, long-term debt (note 13) 17,979 18,247Amortization of deferred transaction costs (note 13) 1,838 1,720Interest income (2,449) (1,021)Other income — (1,000)Realized foreign exchange loss (gain) 188 (68)Net finance costs 17,556 17,878



19. Contractual Obligations and Commitments

The information presented in the table below reflects management’s estimate of the contractualmaturities of the Company’s obligations for its oil sands properties and its general corporate activitiesas at December 31, 2017.

Total 2018 2019 2020 2021+Contracts and purchase orders (1) 47,529 47,311 198 10 10Transportation agreements (2) 37,390 7,630 7,468 7,468 14,824Operating leases (3) 2,812 2,035 640 137 —Outstanding share units (4) 4,466 11 1,958 2,497 —Interest and fees on term loan (5) 43,278 16,889 16,715 9,674 —Repayment of term loan (5) 255,452 2,640 2,640 250,172 —Total 390,927 76,516 29,619 269,958 14,834

(1) Contracts and purchase orders including commitments relating to the Orion expansion projects and costs for the storage of the evaporatorsprocured for use at Taiga.

(2) Firm service gas and bitumen blend transportation commitments.(3) Future commitments for the head office leases and field vehicles. The amounts reported are net of expected settlements of the onerous

lease provision on the consolidated statement of financial position. (4) Unaccrued fair value of outstanding share units expected to be settled for cash. (5) Minimum obligations under the term loan using the foreign exchange and interest rates in effect at December 31, 2017.

Subsequent to December 31, 2017, the Company entered into additional commitments related toOrion capital projects totaling $2.6 million which are expected to be incurred in 2018.

20. Supplemental Cash Flow Information

For the years ended December 31, 2017 2016Changes in non-cash operating working capitalAccounts receivable (7,046) (3,649)Prepaid expenses and other assets (872) 418Accounts payable and accrued liabilities 5,965 2,899

(1,953) (332)Changes in non-cash investing working capitalAccounts payable and accrued liabilities 12,497 (3,671)

12,497 (3,671)

Supplemental cash flow informationCash interest earned 2,381 1,034

The following table provides a breakdown of the cash and non-cash changes in financing liabilitiesarising from financing activities:

2017 2016Balance – term loan – beginning of year 268,768 278,103Cash changes:

Principal repayments (2,695) (2,759)Non-cash changes:

Unrealized foreign exchange gain (17,784) (8,296)Amortization of debt issue costs 1,838 1,720

Balance – term loan – end of year 250,127 268,768



21. Wages and Employee Benefits Costs

For the years ended December 31, 2017 2016Capitalized:

Salaries, short-term benefits and other 3,360 2,980Share-based compensation 430 575

Expensed:Salaries, short-term benefits and other 20,700 21,397Share based compensation expense 4,075 5,428

22. Compensation of Key Management Personnel

Key management personnel are composed of the Company’s directors and executive officers. Theircompensation is as follows:

For the years ended December 31, 2017 2016Salaries, short-term benefits and other 2,650 1,827Share based compensation expense 2,392 2,099


Corporate Information

Directors

William A. Friley – ChairmanIndependent Businessman

Angelo AcconciaSenior Managing Director, Blackstone Capital

Partners and Blackstone Energy Partners

Vincent ChahleyIndependent Businessman

George CrookshankIndependent Businessman

David KriegerManaging Director, Warburg Pincus LLC

John LeePrincipal, Blackstone Capital Partners and

Blackstone Energy Partners

Francesco MelePartner, Azimuth Capital Management

Brian ReinsboroughPresident and Chief Executive Officer,

Venari Resources LLC

Steve SpencePresident and Chief Executive Officer,

Osum Oil Sands Corp.

Officers

Steve Spence, P.Eng.President and CEO

Victor RoskeyChief Financial Officer

Rick K. Walsh, P.Eng.Chief Operating Officer

Dr. Peter Putnam, P.Geol.Sr. Vice President, Geoscience

Dr. Jen Russel-Houston, P.GeolVice President, Geoscience

AuditorPricewaterhouseCoopers LLPCalgary, Alberta

Independent EngineersGLJ Petroleum Consultants Ltd.Calgary, Alberta

Legal CounselMcCarthy Tetrault LLPCalgary, Alberta

Registrar and Transfer AgentAlliance Trust CompanyCalgary, Alberta

Financial InstitutionATB FinancialCalgary, Alberta

Directors

William A. Friley – ChairmanIndependent Businessman

Angelo AcconciaSenior Managing Director, Blackstone Capital

Partners and Blackstone Energy Partners

Vincent ChahleyIndependent Businessman

George CrookshankIndependent Businessman

David KriegerManaging Director, Warburg Pincus LLC

John LeePrincipal, Blackstone Capital Partners and

Blackstone Energy Partners

Francesco MelePartner, Azimuth Capital Management

Brian ReinsboroughPresident and Chief Executive Officer,

Venari Resources LLC

Steve SpencePresident and Chief Executive Officer,

Osum Oil Sands Corp.

Officers

Steve Spence, P.Eng.President and CEO

Victor RoskeyChief Financial Officer

Rick K. Walsh, P.Eng.Chief Operating Officer

Dr. Peter Putnam, P.Geol.Sr. Vice President, Geoscience

Dr. Jen Russel-Houston, P.GeolVice President, Geoscience

AuditorPricewaterhouseCoopers LLPCalgary, Alberta

Independent EngineersGLJ Petroleum Consultants Ltd.Calgary, Alberta

Legal CounselMcCarthy Tetrault LLPCalgary, Alberta

Registrar and Transfer AgentAlliance Trust CompanyCalgary, Alberta

Financial InstitutionATB FinancialCalgary, Alberta

1900, 255 - 5th Ave S.W. Calgary, AB. T2P 3G6T(403)283.3224 F(403)283.3970osumcorp.com

2017 Annual Report

1900, 255 - 5th Ave S.W. Calgary, AB. T2P 3G6T(403)283.3224 F(403)283.3970osumcorp.com

Documents

Osum Oil Sands Corp. · 2020. 6. 25. · 2017 Annual Report Page Review and Outlook 5 Management's Discussion and Analysis 8 Report of Management 40 ... generation capacity of up