Journey Energy Inc.

  • Date: 2016-03-14

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MANAGEMENT’S DISCUSSION AND ANALYSIS – 2015 The following Management’s Discussion and Analysis (“MD&A”) was prepared on March 14, 2016 and is management’s assessment of Journey Energy Inc.’s (“Journey” or the “Company”) financial and operating results for the three and twelve months ended December 31, 2015 and 2014. This MD&A should be read in conjunction with the audited consolidated financial statements of the Company for the three and twelve months ended December 31, 2015 and 2014 along with the notes related thereto. Additional information on the audited consolidated financial statements, this MD&A and other factors that could affect the Company’s operations and financial results are included in Management’s Report to shareholders included with the audited consolidated financial statements. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. Journey prepares its audited consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

Forward-Looking Information This MD&A contains forward-looking statements. More particularly, this MD&A contains statements concerning anticipated: (i) timing and completion of the acquisitions, expectations and assumptions concerning timing of receipt of required regulatory approvals and the satisfaction of other conditions to the completion of the acquisitions, (ii) potential development opportunities and drilling locations associated with the acquisitions, expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, the successful application of technology and the geological characteristics of the acquisitions, (iii) oil and natural gas production during 2016 (iv) debt and bank facilities, (v) capital expenditures, (vi) primary and secondary recovery potentials and implementation thereof, (vii) decline rates, (viii) funds from operations, (ix) operating and cash flow netbacks, (x) operating expenses, (xi) general and administrative expenses, and (xii) realization of anticipated benefits of acquisitions. The forward-looking statements are based on certain key expectations and assumptions made by Journey, including expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures, the application of regulatory and royalty regimes, prevailing commodity prices and economic conditions, development and completion activities, the performance of new wells, the successful implementation of waterflood programs, the availability of and performance of facilities and pipelines, the geological characteristics of Journey’s properties, the successful application of drilling, completion and seismic technology, prevailing weather conditions, exchange rates, licensing requirements, the impact of completed facilities on operating costs, costs of capital, labour and services, and the creditworthiness of industry partners. Although Journey believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Journey can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited Page 1

to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and constraint in the availability of services, adverse weather or break-up conditions, and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Certain of these risks are set out in more detail in this MD&A under the heading ‘Risk Factors’. The following table outlines Journey’s updated forward-looking information included in, and as of the date of this MD&A and has been updated from previous forward-looking information. The disclosure below is intended to provide the reader with the key assumptions that the forward looking information is based upon and the relevant risk factors that would be considered key in preventing Journey from achieving these results. This table also represents Journey’s outlook on 2016: Forward-Looking Information Production for 2016 of between 8,700 and 9,000 BOE/d

2016 cash flow from operations of $15 – 16 million

2016 capital spending program of approximately $9 million excluding acquisitions and dispositions Year-end net debt of between $100$101 million Operating and transportation costs per BOE in the mid $16 range

Interest costs General & administrative costs in the low $3/BOE range (net of capitalized G&A and recoveries) Income taxes – no current income tax is projected to be payable for 2016

Key Assumptions Completion of the forecasted drilling program without rd significant 3 party facility or pipeline outages. Dependent on: Journey achieving average production of oil, NGL and natural gas as per guidance; realizing forecasted commodity prices and an estimated US/CAN average exchange rate of $0.72 Focus will be mainly on drilling 2 - 3 net wells.

Mainly dependent on commodity prices achieving forecast amounts Achieving projected production volumes; no significant changes to cost structures

No significant inflation above current levels No significant changes to currently projected activity levels Journey has a large tax pool position in excess of $679 million

Relevant Risk Factors rd Well performance; 3 party outages.

WTI oil prices; Edmonton par differentials; adequate transportation of oil; AECO gas prices; Journey well performance, downtime and drilling success Achieving the projected cash flow from operations; maintaining a banking credit facility in excess of our net debt Commodity prices

Projected production volumes not achieved; third party oil processing capacities; operating cost increases due to inflation and/or improvement in industry conditions Bank prime rate increases beyond small increments G&A is fairly predictable as they are mainly fixed costs such as rent and salaries Potential tax law changes; significant and sustained increase in commodity prices

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Non-GAAP Measures This MD&A uses the term “netbacks”, which is a term not recognized under General Accepted Accounting Principles (“GAAP”). The Company uses these measures to help evaluate its performance, leverage, and liquidity as well as to assess potential acquisitions. The Company considers corporate netbacks as a key measure as it demonstrates its profitability relative to current commodity prices. Corporate netbacks are comprised of operating, cash flow and net earnings (loss) netbacks. Operating netback is calculated as the average sales price of its commodities less royalties, transportation costs and operating expenses. Cash flow netback starts with the operating netback and deducts general and administrative costs, interest expense and then adds or deducts any realized gains or losses on derivative contracts. To calculate the net earnings(loss) netback, Journey takes the cash flow netback and deducts all noncash expenses including: unrealized gains/losses on derivative contracts, share-based compensation expense, depletion, depreciation, accretion, loss (gain) on dispositions, impairments, exploration and evaluation expenses and deferred income taxes. There is no GAAP measure that is reasonably comparable to netbacks.

Additional GAAP Measures In this MD&A, we refer to additional GAAP financial measures that do not have any standardized meaning as prescribed by GAAP. Additional GAAP financial measures are line items, headings or subtotals in addition to those required under GAAP, and financial measures disclosed in the notes to the audited consolidated financial statements which are relevant to an understanding of the financial statements and are not presented elsewhere in the financial statements. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to generate funds to finance our operations and information regarding our liquidity. Users are cautioned that additional GAAP financial measures presented by the Corporation may not be comparable with measures provided by other entities. Additional GAAP financial measures include cash flow from operations and net debt. The Company considers cash flow from operations (also referred to as “cash flow”) a key performance measure as it demonstrates the Company’s ability to generate funds necessary to repay debt and to fund future growth through capital investment. Journey’s determination of cash flow from operations may not be comparable to that reported by other companies. The reconciliation between cash from operating activities and cash flow from operations can be found in the table below. Journey also presents cash flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of net earnings (loss) per share, which per share amount is calculated under IFRS and is more fully described in the notes to the audited consolidated financial statements. Cash flow from operations is calculated as cash from operating activities before changes in non-cash working capital, transaction costs and decommissioning costs incurred. Cash flow from operations per share is calculated as cash flow from operations divided by the weighted-average number of shares outstanding in the period. Because cash flow from operations and cash flow from operations per share are not impacted by fluctuations in non-cash working capital balances, we believe these measures are more indicative of operational performance than cash from operating activities.

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A reconciliation of cash flow from operations to the GAAP measured cash flow from operating activities is as follows:

Cash provided by operating activities Add (deduct): Transaction costs Changes in non-cash working capital Decommissioning costs incurred Cash flow from operations

Three months ended December 31, 2015 2014 10,394 27,141 (1,267) 400 9,527

(9) (3,200) 625 24,557

Twelve months ended December 31, 2015 2014 55,407 91,651 (7,125) 1,260 49,542

1,768 (1,467) 1,649 93,601

Net debt is used to assess efficiency, liquidity and general financial strength. Net debt is comprised of and calculated as follows: December 31, 2015 Net Debt Bank debt, plus bank indebtedness Accounts receivable Prepaid expenses Accounts payable and accrued liabilities Deferred lease obligations Dividends payable Net debt

90,632 (14,666) (1,928) 31,983 513 106,534

December 31, 2014 83,432 (24,343) (2,081) 40,352 592 2,623 100,575

% Change 10 (40) (7) (21) (13) (100) 6

Barrel of Oil Equivalents Where amounts are expressed in a barrel of oil equivalent (“BOE”), or barrel of oil equivalent per day (“BOE/d”), natural gas volumes have been converted to barrels of oil equivalent at six (6) thousand cubic feet (“Mcf”) to one (1) barrel. Use of the term BOE may be misleading particularly if used in isolation. The BOE conversion ratio of 6 Mcf to 1 barrel (“Bbl”) of oil or natural gas liquids is based on an energy equivalency conversion methodology primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead. This conversion conforms to the Canadian Securities Regulators’ National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.

Amounts All dollar amounts quoted are in thousands of Canadian dollars unless otherwise noted. All share data is quoted in thousands of shares, except per share data or as specifically otherwise noted.

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HIGHLIGHTS FROM THE THREE AND TWELVE MONTHS ENDED DECEMBER 31, 2015 Financial Journey realized cash flow of $9,527 in the fourth quarter of 2015 bringing the year to date amount to $49,543. This translates into $0.22 per basic share ($0.21 diluted) for the quarter and $1.13 per basic share and $1.10 per diluted share for the twelve months ended December 31. Net income was $38,586 for the quarter ($0.89 per basic share and $0.86 per diluted share) and net loss was $111,337 for the twelve months ended December 31 ($2.55 per basic and diluted share). Net cash capital expenditures were $8,555 during the quarter totaling $48,100 for the year to date. During the quarter, Journey paid $784 in dividends relating to dividends declared in the previous quarter. Journey exited the year with net debt of $106,534. At the end of 2015, Journey was drawn $90.6 million on its $140 million syndicated credit facility.

Drilling During the fourth quarter, Journey drilled five (3.1 net) wells with a 100% success rate. This is compared to the successful drilling of four (2.8 net) wells in the fourth quarter of 2014. For the twelve months ending December 31, 2015, the Company drilled 16 (13.2 net) wells as compared to 31 (22.8 net) wells for the comparable period in 2014. The overall reduced activity in 2015 reflected the lower cash flows resulting from declining commodity prices. Drilling activity in 2016 is expected to be significantly reduced again as lower commodity prices continue to affect available cash flows.

Production For the fourth quarter, production volumes decreased by 19% to 9,593 BOE/day in 2015 from 11,773 BOE/day in 2014. This decrease reflects the effects of a reduced capital expenditure program and production declines. For the comparable twelve months, production marginally decreased to 10,309 BOE/day in 2015 from 10,346 BOE/day in 2014.

Outlook For 2016, the annual average production is projected to be between 8,700 and 9,000 BOE/d. Operating and transportation costs are expected to average in the mid $16.00 per BOE range with cash flow from operations for the year anticipated to be approximately $15,000. By the end of the year, capital expenditures are planned to be in the range of $9,000. These projections are based on management’s current view of commodity pricing for 2016. However the volatility of prices, particularly oil, will have an effect on these projections and could cause changes to planned capital spending. In January, 2016, Journey closed a small property acquisition of an additional interest in the Herronton property for $625 before adjustments.

DETAILED FINANCIAL REVIEW PRODUCTION REVENUE AND VOLUMES Aggregate production volumes decreased by 19% during the fourth quarter of 2015 to 882,576 BOE as compared to 1,083,161 BOE for the fourth quarter in 2014. The decrease was reflective of declines and shut-ins due to lower commodity prices. For the twelve month comparative period, aggregate production volumes were essentially flat at 3,762,901 in 2015 and 3,776,141 in 2014. With lower drilling activity planned in 2016, aggregate production volumes are anticipated to be between 8,700 and 9,000 BOE/d. For the quarter, natural gas production decreased to 45% (2014 – 48%) of total volumes, with light oil increasing to 44% (2014 – 41%), heavy oil at 4% (2014 – 4%) and natural gas liquids at 7% (2014 – 7%). For the twelve month Page 5

period, oil and natural gas liquids production increased marginally to 54% (53% - 2014) of total volumes with natural gas production decreasing by 1% from 47% to 46% of total production in 2014.

Aggregate Sales Volumes

Natural gas (Mcf) Light/medium oil (Bbl) Heavy oil (Bbl) Natural gas liquids (Bbl) Barrels of oil equivalent (BOE)

Three months ended December 31, Twelve months ended December 31, % % 2015 2014 Change 2015 2014 Change 2,389,386 3,113,794 (23) 10,467,199 10,557,489 (1) 383,374 448,933 (15) 1,622,245 1,569,422 3 39,618 41,796 (5) 161,801 177,750 (9) 61,353 73,466 (16) 234,322 269,387 (13) 882,576 1,083,161 (19) 3,762,901 3,776,141 -

Volumetric Product Mix % of Aggregate Production Natural gas Light/medium oil Heavy oil Natural gas liquids Total

Three months ended December 31, % 2015 2014 Change 45 48 (6) 44 41 7 4 4 7 7 100 100 -

Twelve months ended December 31, % 2015 2014 Change 46 47 (2) 44 42 5 4 4 6 7 (14) 100 100 -

Daily Sales Volumes Daily sales volumes decreased 19% to 9,593 BOE/d for the fourth quarter of 2015 from 11,773 BOE/d in 2014. The decrease was reflective of shut-ins due to lower commodity prices, fewer wells drilled, and lower than expected production primarily in Herronton. For the twelve months, daily sales volumes remained relatively flat at 10,309 BOE/d for 2015 as compared to 10,346 BOE/d in 2014. Three months ended December 31, % 2015 2014 Change Natural gas (Mcf/d) Light/medium oil (Bbl/d) Heavy oil (Bbl/d) Natural gas liquids (Bbl/d) Barrels of oil equivalent (BOE/d)

25,972 4,167 431 667 9,593

33,846 4,880 454 799 11,773

(23) (15) (5) (17) (19)

Twelve months ended December 31, % 2015 2014 Change 28,677 4,445 443 642 10,309

28,925 4,300 487 738 10,346

(1) 3 (9) (13) -

Daily BOE production for the twelve months ended December 31, 2015 and 2014 are shown by Journey’s main operating properties as follows:

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Area Matziwin Herronton Crystal Creek Countess Cherhill Pembina Greater Alberta other Total

Three months ended December 31, % 2015 2014 Change 1,367 1,858 (26) 1,307 1,944 (33) 1,423 1,423 1,295 1,615 (20) 1,147 1,031 11 987 1,342 (26) 2,067 2,560 (19) 9,593 11,773 (19)

Twelve months ended December 31, % 2015 2014 Change 1,573 1,534 3 1,493 1,917 (22) 1,434 1,082 33 1,393 898 55 1,264 1,065 19 1,061 1,310 (19) 2,091 2,540 (18) 10,309 10,346 -

Benchmark Indices Three months ended December 31, % 2015 2014 Change Crude Oil WTI (US$/Bbl) Edmonton light (CDN$/Bbl) Natural Gas NYMEX (US $/Mmbtu) AECO - Daily (CDN$/Mcf) Foreign Exchange Canadian to US dollar US to Canadian dollar

Twelve months ended December 31, % 2015 2014 Change

41.94 52.01

73.07 74.37

(43) (30)

48.65 56.93

93.17 93.88

(48) (39)

2.12 2.46

3.79 3.59

(44) (31)

2.63 2.69

4.38 4.49

(40) (40)

1.335 0.749

1.136 0.880

18 (15)

1.277 0.783

1.104 0.906

16 (14)

United States natural gas prices are usually referenced to the New York Mercantile Exchange Henry Hub in Louisiana (NYMEX), while in Canada the generally recognized benchmark is the AECO hub in Alberta. Gas prices are influenced by a variety of factors such as: weather patterns; LNG imports; supplies in western Alberta; demand in eastern Canada and the United States, relative storage levels in North America and alternative fuel sources. AECO benchmark pricing was 31% lower in the twelve months of 2015 as compared to the same period in 2014. This was combined with a decrease in WTI prices of 43% over the same comparable periods. The decrease in WTI oil prices were somewhat softened by an 18% depreciation in the Canadian dollar against the US dollar. This is reflected in the Edmonton par oil prices being only 30% lower in 2015 as compared to 2014. The differentials between WTI and Edmonton par have varied between in $2 - $4 CDN per barrel range during the quarter, and continue to vary. Looking forward into 2016, the CAD$ is expected to remain weak against the US$ along with continued soft and volatile oil prices. Gas prices are expected to adjust seasonally but remain range bound. The realized prices during the respective periods were as follows:

Realized Commodity Prices Natural gas ($/Mcf) Light / medium oil ($/Bbl) Heavy oil Natural gas liquids ($/Bbl)

Three months ended December 31, % 2015 2014 Change 2.37 3.58 (34) 42.84 67.74 (37) 36.58 64.88 (44) 24.06 54.41 (56) 28.33 44.56 (36)

Twelve months ended December 31, % 2015 2014 Change 2.64 4.40 (40) 48.60 83.86 (42) 45.52 79.80 (43) 25.73 64.18 (60) 31.87 55.48 (43)

Average realized commodity prices decreased by 36% as compared to the fourth quarter in 2014 from $44.56 per BOE to $28.33 per BOE. Realized natural gas prices decreased by 34% in the quarter as compared to the same quarter in 2014. Journey’s realized light/medium prices decreased by 37% and heavy oil price decreased by 44% in Page 7

the fourth quarter of 2015 compared to 2014 with natural gas liquids prices decreasing significantly by 56% for the same comparable period. For the twelve months ended December 31, Journey’s average realized commodity prices decreased by 43% in 2015 to $31.87 per BOE from $55.48 per BOE in 2014. Realized natural gas prices decreased by 40%, realized light/medium oil price decreased by 42%, realized heavy oil decreased by 43% and natural gas liquids prices also decreased by 60%. Oil prices continued to drop significantly in 2015 in response to world demand as Middle East producers continue to maintain production levels. Low prices are expected to continue into 2016. Journey expects 55% of its production from oil and natural gas liquids while contributing 79% to Journey’s revenues.

RISK MANAGEMENT ACTIVITIES At December 31, 2015, the Company had the following derivative contracts in place: Oil contracts Volume Bbls/d Swap 1,000

Pricing point WTI NYMEX

Strike price/Bbl CAD $77.00

Term July 1, 2015 to June 30, 2016

The net change in these contracts resulted in a realized net gain of $1,911 and an unrealized net gain of $257 for the quarter. A realized net gain of $15,163 and an unrealized net loss of $6,813 were recorded for the twelve months ended December 31, 2015. At December 31, 2015 the estimated fair value of these contracts is $4,024. The loss (gain) on derivative contracts for the periods ended December 31, are as follows: Three months ended December 31, % 2015 2014 Change Realized loss (gain) Unrealized loss (gain) Total

(1,911) (257) (2,168)

(6,132) (9,565) (15,697)

(131) (97) (86)

Twelve months ended December 31, % 2015 2014 Change (15,163) 6,813 (8,350)

1,370 (11,868) (10,498)

(1,207) (157) (79)

The fair value of Journey’s unrealized commodity contracts are based upon Level 2 inputs, having been provided by the financial intermediary with whom the transactions were completed and tested by management for reasonableness based on current prices and market data. The fair value of financial derivatives are recurring measurements and are determined using third-party models and valuation methodologies that utilize observable market data, including forward commodity prices and interest rates to estimate the current fair value of financial derivatives. Journey characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. The three levels are as follows: a)

Level 1 – inputs represent quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

b)

Level 2 – inputs other than quoted prices included in Level 1 that are observable, either directly or indirectly as of the reporting date. Level 2 valuations are based on inputs which can be observed or corroborated in the marketplace from sources such as New York Mercantile exchange or the Natural Gas Exchange.

c)

Level 3 – inputs are less observable, unavailable or where the observable data does not support the majority of the instruments fair value.

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A 10% change in commodity prices would have resulted in unrealized gains or losses on commodity contracts impacting net income by $1,094, all relating to oil. Journey enters into commodity based derivative contracts to actively manage the risks associated with price volatility and thereby partially protect cash flows, which are used to fund both our capital program. These risks can be mitigated by entering into derivative management contracts for oil, natural gas and foreign exchange. The risk associated with using these derivative contracts include: commodity prices moving materially in favour of the counter-party and the credit risk associated with the collection of settlements from price movements in Journey’s favour.

PETROLEUM AND NATURAL GAS (“P&NG”) SALES In the fourth quarter of 2015, aggregate P&NG sales decreased by 48% to $25,008 as compared to $48,264 for the same period in 2014. The decrease was due to a 36% reduction of realized commodity prices combined with a 19% reduction in production volumes. For the twelve months ended December 31, aggregate P&NG sales decreased by 43% to $119,907 in 2015 from $209,509 in 2014. As volumes and product contribution were comparative year over year, the decrease was directly attributable to realized commodity prices.

Natural gas Light/Medium oil Heavy oil Natural gas liquids P&NG sales

Three months ended December 31, % 2015 2014 Change 5,657 11,144 (49) 16,426 30,412 (46) 1,449 2,711 (47) 1,476 3,997 (63) 25,008 48,264 (48)

Twelve months ended December 31, % 2015 2014 Change 27,677 46,463 (40) 78,837 131,574 (40) 7,365 14,183 (48) 6,028 17,289 (65) 119,907 209,509 (43)

Sales % Contribution Natural gas Light/Medium oil Heavy oil Natural gas liquids Total

Three months ended December 31, % 2015 2014 Change 23 23 65 63 3 6 6 6 8 (25) 100 100 -

Twelve months ended December 31, % 2015 2014 Change 23 22 5 66 63 5 6 7 (14) 5 8 (37) 100 100 -

ROYALTIES For the fourth quarter, royalties were $1,424 in 2015 as compared to $8,014 for the same period in 2014, an 82% reduction. On a per BOE basis, the royalty rate decreased to $1.61 in 2015 as compared to $7.40 from last year. As a percentage of revenue, the rate for the fourth quarter of 2015 was 5.7% or 66% lower than the 16.6% realized in 2014. The large comparative decrease of royalties was primarily due to lower prices and adjustments to gas cost allowance and freehold mineral taxes, recorded in the current quarter but relating to earlier quarters and the previous year. For the twelve months ended December 31, royalties were $14,009 in 2015 as compared to $36,525 for the same period in 2014 representing a 62% reduction. On a per BOE basis, the royalty rate decreased 62% to $3.72 in 2015 as compared to $9.67 from last year. As a percentage of revenue, the rate for 2015 was 11.7% or 33% lower than the 17.4% realized in 2014.

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On Crown royalty lands in Alberta, horizontal oil wells are subject to a maximum 5% royalty rate based on a production month cap of 18 to 48 months or a volume cap of 50,000 to 100,000 BOE of production depending on the measured depth of the well. This rate expires at whichever comes first. For the twelve months of 2015 Crown royalty decreased primarily as a result of lower commodity prices. Journey is anticipating a corporate royalty rate in the range of 11 to 13% for 2016 based on Journey’s internal forecast of commodity prices and anticipated productivity of its wells. However, this could change significantly as Crown royalty rates are dependent on a combination of realized commodity prices and specific well production volumes.

$ Crown Freehold/gross over-riding Total royalties Royalties (as a % of P&NG sales)

$ / BOE Crown Freehold/gross over-riding Total royalties

Three months ended December 31, % 2015 2014 Change 681 4,715 (86) 743 3,299 (77) 1,424 8,014 (82) 5.7 16.6 (66)

Twelve months ended December 31, % 2015 2014 Change 5,851 26,948 (78) 8,158 9,577 (15) 14,009 36,525 (62) 11.7 17.4 (33)

Three months ended December 31, % 2015 2014 Change 0.77 4.35 (82) 0.84 3.05 (72) 1.61 7.40 (78)

Twelve months ended December 31, % 2015 2014 Change 1.55 7.14 (78) 2.17 2.53 (14) 3.72 9.67 (62)

OPERATING Operating costs were $10,997 or $12.46 per BOE for the fourth quarter in 2015 as compared to $15,588, or $14.39 per BOE in 2014. Aggregate operating costs decreased by 29% reflecting improved efficiencies, an active cost reduction program, reduced volumes and a reduction in estimates related to prior quarters. For the twelve months ended December 31, operating costs were $52,690 or $14.00 per BOE in 2015 as compared to $54,871, or $14.53 per BOE in 2014. The Company continually reviews field activities to derive efficiencies and scalability in its operations. For 2016, Journey expects the per BOE rate to average in the mid $16.00 range, reflecting continued cost reductions but subject to lower volumes.

Gross operating expense Less: Processing income Operating expense per financial statements Expense ($ per BOE) Expense (as a % of P&NG sales)

Three months ended December 31, % 2015 2014 Change 11,988 16,587 (28)

Twelve months ended December 31, % 2015 2014 Change 56,058 57,981 (3)

(991) 10,997

(999) 15,588

(1) (29)

(3,368) 52,690

(3,110) 54,871

8 (4)

12.46 44.0

14.39 32.3

(13) 36

14.00 43.9

14.53 26.2

(4) 68

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TRANSPORTATION Transportation expenses were $496 for the fourth quarter of 2015, amounting to 2.0% of P&NG sales for the period as compared to $929 and 1.9% for 2014. The comparative lower expense for the fourth quarter of 2015 was due to less volumes being trucked at lower rates. Cost per BOE averaged $0.56 in 2015, which is 35% lower than the same period in 2014. For the twelve months ended December 31, transportation expenses were $3,115 for 2015 or 23% higher than $2,526 for the comparable period in 2014. On a per BOE basis costs were $0.83 or 24% higher than the $0.67 incurred in 2014. Aggregate transportation costs for 2015 were higher in 2015 primarily due to increased trucked volumes, particularly early in the year. Transportation costs include: clean oil trucking, trucking of natural gas liquids, and transportation associated with the usage of third party natural gas sales lines used before custody transfer and sale of the gas. Transportation costs are dependent on a variety of factors such as: the type of production facilities; the method of transportation; the distances covered; quantities shipped; the type of service offered (interruptible versus firm service) as well as ownership of the transportation facilities. Three months ended December 31, % 2015 2014 Change Transportation expense Expense ($ per BOE) Expense (% of P&NG sales)

496 0.56 2.0

929 0.86 1.9

(47) (35) 5

Twelve months ended December 31, % 2015 2014 Change 3,115 0.83 2.6

2,526 0.67 1.2

23 24 117

GENERAL AND ADMINISTRATIVE (G&A) EXPENSE For the quarter, net G&A expense after recoveries, decreased 16% to $3,535 in 2015 from $4,187 in 2014. Lower recoveries and capitalized G&A in the quarter reflected the effect of staffing and compensation reductions. On a per BOE basis, Journey realized net G&A of $4.00 for the fourth quarter of 2015, 4% higher than the $3.86 for 2014. For the comparable twelve month period ending December 31, 2015, net G&A expense was $12,243, including severance costs of $1,038, or 7% lower than $13,228 in 2014. For the twelve months ended December 31, net G&A was $3.25 in 2015 or 7% lower than $3.50 in 2014. For 2016, net G&A is expected to be approximately $11,000 or 10% lower than 2015.

Gross expense Less: Overhead recoveries Capitalized G&A Net expense per financial statements Expense ($ per BOE) Gross expense Net expense

Three months ended December 31, % 2015 2014 Change 4,188 6,226 (33)

Twelve months ended December 31, % 2015 2014 Change 16,870 19,208 (12)

(536) (117) 3,535

(1,438) (601) 4,187

(63) (81) (16)

(3,334) (1,293) 12,243

(4,090) (1,890) 13,228

(18) (32) (7)

4.74 4.00

5.75 3.86

(18) 4

4.48 3.25

5.09 3.50

(12) (7)

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FINANCE EXPENSE Net finance expense is comprised of interest on bank debt, interest on promissory notes (2014), amortization of financing fees, and other bank charges. Interest expense and bank fees for the fourth quarter of 2015 decreased 16% to $948 from $1,121 in 2014. For the fourth quarter of 2015, the average bank debt outstanding was $93,315 which was a 14% increase from $82,172 for the comparable period in 2014. For the quarter, the average effective interest rate on outstanding bank debt decreased by 26% to 4.0% in 2015 from 5.4% in 2014. On a per BOE basis, net finance expense was $1.07 for 2015 as compared to $1.04 for 2014, representing a 3% increase, period over period, due to lower volumes in the quarter. For the comparable twelve month period, net finance expenses for 2015 decreased 53% to $3,485 from $7,387 in 2014. This was largely attributable to the promissory note outstanding for three months in 2014. The average interest rate on outstanding bank debt decreased to 3.9% for the twelve months of 2015 from 5.8% in 2014. On a per BOE basis, net finance expense was $0.93 for 2015 as compared to $1.96 for 2014, representing a 53% reduction. For 2016, Journey expects the average bank debt outstanding to remain at similar or slightly lower levels than 2015.

Expense per financial statements Add/(Deduct): Finance income Accretion - decommissioning Interest expense and bank fees Average debt outstanding Average interest rate (%) Cash finance expense ($ per BOE)

Three months ended December 31, % 2015 2014 Change 1,796 2,033 (12) 8 (856) 948 93,315 4.0 1.07

(912) 1,121 82,172 5.4 1.04

(6) (16) 14 (26) 3

Twelve months ended December 31, % 2015 2014 Change 6,987 10,490 (33) 14 (3,516) 3,485 88,562 3.9 0.93

(3,103) 7,387 127,054 5.8 1.96

13 (53) (30) (33) (53)

SHARE BASED COMPENSATION Share based compensation expense was $1,023 for the fourth quarter of 2015 as compared to $776 in 2014. For the twelve months ending December 31, the expense was $3,768 for 2015, a decrease of 7% over the $4,042 expensed in 2014 which included the full vesting of series A and B performance warrants. Share based compensation during the fourth quarter reduced the total amount of capitalized share based compensation calculated in earlier quarters by $139. This was due to the effect of staff reductions over the course of 2015. The capitalization is attributable to technical staff, who are directly related to development activities. The fair value of all share based compensation is amortized over the respective vesting periods. In the fourth quarter of 2015, 754 Restricted Share Units (“RSUs”) were granted at a price of $3.00 per unit, 225 Performance Share Units (“PSUs”) were granted at $1.94 per unit and 20 stock options were granted at an average strike price of $1.73 per option. During the same period 18 RSUs and 3 PSUs at a fair value of $9.39 per unit and 179 stock options at an average strike price of $7.18 per option were forfeited. In addition 13 series A Performance Warrants with a fair value of $3.78 per warrant, 26 series B Performance Warrants with a fair value of $3.46 per warrant and 12 series C Performance with a fair value of $5.01 per warrant were forfeited during the quarter. The Company issued series C performance warrants in 2014. The series C performance warrants vest to the holder based on the “Value” (as defined below) of Journey shares as well as time vesting. One third of the series C performance warrants vest when the Value of the common shares reaches $12.00 per share; the next Page 12

third at $13.00 and the last third at $14.00. The time vesting component is one third annually on each anniversary date of their issuance. “Value” is defined as the price per share at which any of the following occurs: a takeover bid for Journey; the Journey shares trade on a stock exchange for five consecutive days; or upon the issuance of equity pursuant to a public or private placement. All performance warrants expire on July 1, 2017. The fair value of all share based compensation was estimated based on the date of issue using a modified Black Scholes pricing model.

Expense per financial statements Expense ($ per BOE)

Three months ended December 31, % 2015 2014 Change 1,023 776 32 1.16

0.72

61

Twelve months ended December 31, % 2015 2014 Change 3,768 4,042 (7) 1.00

1.07

(7)

DEPLETION AND DEPRECIATION (“D&D”) Aggregate D&D decreased from $16,238 in the fourth quarter of 2014 to $8,046 in 2015. The 50% decrease reflects the impairment of carrying value recorded at September 30 and December 31, 2015 with higher reserve additions at December 31. For the quarter, on a per BOE basis, D&D was $9.12 for 2015 as compared to of $14.99 in 2014, representing a 39% decrease. For the twelve months ending December 31, aggregate D&D decreased 18% from $55,082 in 2014 to $44,965 in 2015. On a per BOE basis D&D was $11.95 in 2015, an 18% decrease from $14.59 in 2014.

Depletion and depreciation Expense ($ per BOE)

Three months ended December 31, % 2015 2014 Change 8,046 16,238 (50) 9.12 14.99 (39)

Twelve months ended December 31, % 2015 2014 Change 44,965 55,082 (18) 11.95 14.59 (18)

IMPAIRMENTS The Company had previously tested CGUs for impairment and potential reversal of prior impairments at September 30, 2015, because indicators were present based on an internal assessment of recoverable value. It was determined that the carrying amounts of the Manola, Matziwin, Skiff, Pembina, Peace River Arch, Pine Creek, Sylvan Lake, Herronton, Countess, Crystal, Cherhill, and Enchant CGUs all exceeded their recoverable amount. Recoverable amount was calculated as the fair value of the assets less cost of disposal. The fair value less cost to dispose was determined with a discounted cash flow approach based on an internal assessment of September 30, 2015 proved plus probable reserves and GLJ’s forecast commodity prices. Journey used a risk adjusted discount rate that varied by CGU based on the nature of the assets held in each CGU to determine the fair value at the measurement date (level 3 inputs). The impairment was attributed to property, plant and equipment and, as a result, an impairment loss of $208,213 was recorded. Due to continued softening of commodity prices, at December 31, 2015, the Company tested its CGUs for impairment as well as the potential reversal of prior period impairments where indicators were present. It was determined that, on an annual basis, the carrying amounts of the Manola, Matziwin, Herronton, Skiff, Crystal, Cherhill, Countess, Pembina, Peace River Arch, Pine Creek, Sylvan Lake, and Pincher Creek CGUs all exceeded their recoverable amount. Recoverable amount was calculated as the fair value of the assets less cost of disposal. The fair value less cost to dispose was determined with a discounted cash flow approach based on year end 2015 proved plus probable reserves and an average of three reserve engineer’s forecast commodity prices. Journey used a risk adjusted discount rate that varied by CGU based on the nature of the assets held in each CGU to Page 13

determine the fair value at the measurement date (level 3 inputs). The impairment was attributed to property, plant and equipment and, as a result, a total net impairment loss of $141,524 was recorded for the year (December 31, 2014 - $152,407). This annualized impairment test determined the carrying amounts of Pembina, Peace River Arch, Pine Creek, Pincher Creek and Sylvan Lake CGUs all exceeded their recoverable amount at December 31, 2015 and resulted in a further impairment expense of $24,313. At that time it was determined that a portion of the impairment expensed at September 30, 2015 should be reversed for Manola, Matziwin, Herronton, Skiff, Crystal, Cherhill and Countess CGU’s due to changes in value in the annual reserve report, therefore a $91,002 impairment reversal / change of estimate was recorded. Total impairments for 2015 decreased 9% to $144,476 as compared to $158,369 in 2014. The impairment was primarily attributable to the decline in future oil and natural gas prices used by the Company’s independent reserve evaluator and was allocated to property, plant and equipment and as a result. On a per BOE basis, 2015 impairment was $38.40 for 2015.

Exploration and evaluation asset impairment Oil and gas asset impairment Oil and gas asset impairment reversal/change of estimate Total impairments Exploration and evaluation asset impairment ($/BOE) Oil and gas asset impairment ($ / BOE) Oil and gas asset impairment reversal/change of estimate ($ / BOE) Total impairments ($/BOE)

Three months ended December 31, % 2015 2014 Change 2,952 5,962 (50)

Twelve months ended December 31, % 2015 2014 Change 2,952 5,962 (50)

24,313

152,407

(84)

232,526

152,407

53

(91,002)

-

100

(91,002)

-

100

(63,737) 3.35

158,369 5.50

(140) (39)

144,476 0.78

158,369 1.58

(9) (51)

27.55

140.71

(80)

61.79

40.36

53

(103.11)

-

100

(24.18)

-

100

(72.22)

146.21

(149)

38.40

41.94

(8)

DEFERRED TAXES For the fourth quarter, deferred income tax expense for 2015 was $24,342, as compared to a recovery of $34,680 for the same period in 2014. On a per BOE basis, the expense increased 186% to $27.58 from a recovery of $32.02 in 2014. For the twelve months ended December 31, deferred income tax recovery for 2015 was $41,972 as compared $25,086 for the same period in 2014. On a per BOE basis, the recovery increased 68% to $11.15 from $6.64 in 2014. The change, period over period, was largely a result of a significant increase in Journey’s oil and gas asset impairments during 2015 and also changes in enacted tax rates.

Deferred tax expense (recovery) Deferred tax expense (recovery) ($ per BOE)

Three months ended December 31, % 2015 2014 Change 24,342 (34,680) 170 27.58

(32.02)

186

Twelve months ended December 31, % 2015 2014 Change (41,972) (25,086) 67 (11.15)

(6.64)

68

Page 14

Tax Pool Canadian oil & gas property expense Canadian development expenses Canadian exploration expenses Undepreciated capital costs Financing costs Non-capital losses Total

Rate 10% declining balance 30% declining balance 100% 7-100% declining balance 5 year straight line 100%

Amount 145,678 220,982 47,445 146,655 7,072 111,529 679,361

NETBACKS Operating netback of $13.70 per BOE for the fourth quarter of 2015 decreased by 37% as compared to $21.91 realized for the same period in 2014. For the twelve months ended December 31, operating netback was $13.32 per BOE for 2015 which was a 56% decrease from $30.61 for 2014. The changes, period over period, resulted from significant decreases in realized commodity prices somewhat offset by lower royalties and operating expenses. Cash flow netback per BOE for the fourth quarter was 52% lower in 2015 than 2014. G&A expenses were slightly higher by 4%, on a BOE basis. Finance expenses increased marginally by 3% from $1.04 to $1.07 per BOE and realized hedging gains decreased by 62% to $2.17 per BOE from $5.66 in 2014. For the twelve months, cash flow netback decreased by 47% from $24.79 per BOE in 2014 to $13.17 in 2015. Looking forward into early 2016, cash flow netbacks are expected to be lower than the 2015 fourth quarter which benefited from prior period adjustments to both royalties and operating costs. After including the non-cash items, net income netback for the fourth quarter of 2015 was $43.72 per BOE as compared to a loss netback of $97.23 per BOE in 2014. The difference was due to a 52% reduction in cash flow, change in impairments on oil and gas assets recorded in the fourth quarter of 2015 and the resultant deferred tax expense. Net loss netback for the twelve months ended December 31 was $29.59 per BOE compared to $23.89 for 2014, largely attributable to a 47% reduction in cash flow and an increased deferred tax recovery for 2015.

($ per BOE) Realized price Royalties Operating expenses Transportation expenses Operating General and administrative Finance expenses - cash interest and fees Realized gain (loss) on derivative contracts Cash flow Transaction costs Unrealized gain (loss) on derivative contracts Share based compensation Depletion and depreciation Accretion Impairments Loss (gain) on dispositions Exploration & evaluation

Three months ended December 31, % 2015 2014 Change 28.33 44.56 (36) (1.61) (7.40) (78) (12.46) (14.39) (13) (0.56) (0.86) (35) 13.70 21.91 (37) (4.00) (3.86) 4 (1.07) (1.04) 3 2.17

Twelve months ended December 31, % 2015 2014 Change 31.87 55.48 (43) (3.72) (9.67) (62) (14.00) (14.53) (4) (0.83) (0.67) 24 13.32 30.61 (56) (3.25) (3.50) (7) (0.93) (1.96) (53)

5.66

(62)

4.03

(0.36)

(1,119)

0.29

22.67 0.01 8.83

(52) (100) (97)

13.17 (1.81)

24.79 (0.47) 3.14

(47) (100) (58)

(1.16) (9.12) (0.97) 72.22 (0.76)

(0.72) (14.99) (0.84) (146.21) 2.00 -

61 (39) 15 (149) (100) 100

(1.00) (11.95) (0.93) (38.40) 0.87 (0.69)

(1.07) (14.59) (0.82) (41.94) 0.57 (0.15)

(7) (18) 13 (8) 53 360

10.80

Page 15

($ per BOE) expense Deferred tax recovery (expense) Net income (loss)

Three months ended December 31, % 2015 2014 Change (27.58)

32.02

43.72

(97.23)

186 (145)

Twelve months ended December 31, % 2015 2014 Change 11.15

6.64

68

(29.59)

(23.89)

24

CASH FLOW AND NET INCOME (LOSS) Cash flow from operations in the fourth quarter of 2015 was $9,527, a decrease of 61% from $24,557 realized in 2014. For the twelve months ended December 31, cash flow from operations decreased 47% from $93,601 in 2014 to $49,542 in 2015. The decrease was largely attributable, period over period, to a 48% decrease of P&NG sales in the fourth quarter and a 43% decrease in the twelve months ended December 31. Net income for the quarter was $38,586 compared to a loss of $105,316 for 2014. The change in net income for the quarter was primarily due to a 61% reduction in cash flow and changes to oil and gas asset impairment and deferred tax. For the twelve month period, the net loss was $111,337 in 2015 as compared to $90,221 in 2014. For twelve month period the increased net loss was due to a 40% decrease in cash flow being somewhat offset by changes to oil and gas asset impairment and deferred tax. Cash flow from operations is calculated as follows:

Net income (loss) Adjustments for: Transaction costs Unrealized (gain) loss on derivative contracts Share based compensation Depletion and depreciation Loss (gain) on disposition Exploration and evaluation asset impairment Oil and gas asset impairment Accretion Deferred tax expense (recovery) Exploration and evaluation Cash flow from operations

Three months ended December 31, % 2015 2014 Change 38,586 (105,316) (137) (257)

Twelve months ended December 31, % 2015 2014 Change (111,337) (90,221) 23

(9) (9,565)

(100) (97)

6,813

1,768 (11,868)

(100) (157)

1,023 8,046 2,952

776 16,238 (2,168) 5,962

32 (50) (100) (50)

3,768 44,965 (3,269) 2,952

4,042 55,082 (2,168) 5,962

(7) (18) 51 (50)

(66,689) 856 24,342

152,407 912 (34,680)

(144) (6) (170)

141,524 3,516 (41,972)

152,407 3,103 (25,086)

(7) 13 67

668 9,527

24,557

320 (61)

2,582 49,542

581 93,601

344 (47)

During the fourth quarter of 2015, Journey realized a net income of $0.89 per basic share and $0.86 per diluted share. Net loss per share for the twelve months was $2.55 per basic and diluted share. For the twelve month period ended December 31, 2015 the dilutive impact of 6,066 stock options, performance warrants, share purchase warrants and RSUs was omitted as it would have been ant-dilutive. These values are comparable to fourth quarter net loss per share of $2.44 for basic and diluted share for 2014 and net loss per share of $2.56 per basic and diluted share for the twelve months ended December 31, 2014. Fourth quarter cash flow per share in 2015 was $0.22 per basic and $0.21 per diluted share. Comparatively cash flow per share in 2014 was $0.57 for basic and $0.56 for diluted. For the twelve months ended December 31, cash flow per share in 2015 decreased to $1.13 from $2.65 (basic) and to $1.10 from $2.56 (diluted) in 2014.

Page 16

Per share data Net income (loss) Basic ($/share) Diluted ($/share) Cash flow from operations Basic ($/share) Diluted ($/share)

Three months ended December 31, % 2015 2014 Change 0.89 0.86 0.22 0.21

Twelve months ended December 31, % 2015 2014 Change

(2.44) (2.44)

(136) (134)

(2.55) (2.55)

(2.56) (2.56)

0.57 0.56

(61) (62)

1.13 1.10

2.65 2.56

(57) (57)

CAPITAL EXPENDITURES Journey spent $7,546 on capital expenditures (before acquisitions/dispositions) during the fourth quarter of 2015 representing a decrease of 63% from $20,367 in 2014. Five gross (3.1 net) wells drilled during the quarter as compared to four gross (2.1 net) wells drilled in 2014. For the twelve months ended December 31, 2015, $41,545 was spent on capital expenditures (before acquisitions/dispositions), a decrease of 55% over $93,260 spent in 2014. 16 (13.2 net) wells were drilled during the twelve months ended December 31, 2015 as compared to 31 (22.8 net) wells drilled in 2014. In 2015, these capital expenditures were incurred primarily in the Herronton, Countess, Matziwin and Crystal properties. The majority of acquisitions were incurred in the Pembina Greater and Skiff properties with small dispositions in the Sylvan Lake and Countess properties. Three months ended December 31, % 2015 2014 Change Cash expenditures: Land acquisitions and lease rentals Geological and geophysical Drilling and completions Well equipment and facilities Capitalized general and administrative Exploration and development expenditures Other expenditures Total capital expenditures Producing property acquisitions Producing property dispositions Net cash capital expenditures Non-cash expenditures: Capitalized share based compensation Capitalized decommissioning liability Total capital expenditures

Twelve months ended December 31, % 2015 2014 Change

206

2,052

(90)

2,008

7,380

(73)

4,846 2,376 116

1,910 9,650 6,154 601

(100) (50) (61) (81)

344 26,593 11,259 1,292

2,612 62,699 18,212 1,890

(87) (58) (37) (32)

7,544

20,367

(63)

41,496

92,793

(55)

2 7,546 5,281

22 20,389 1,836

(95) (63) 188

49 41,545 11,439

467 93,260 172,120

(90) (55) (93)

(4,273)

(4,523)

(6)

(4,885)

8,554

17,702

(52)

48,099

260,857

(82)

(140)

492

(128)

702

932

(25)

400

626

(36)

1,260

1,649

(34)

8,814

18,820

(51)

50,061

263,438

(81)

(4,523)

8

Page 17

Wells drilled Development wells Success rate (%)

Three months ended December 31, 2015 2014 Gross Net Gross Net 5 3.1 4 2.8 100 100 75 82

Twelve months ended December 31, 2015 2014 Gross Net Gross Net 16 13.2 31 22.8 100 100 97 98

UNDEVELOPED LAND HOLDINGS The undeveloped land holdings at December 31, 2015 are as follows: Area Pincher Creek Herronton Matziwin Pine Creek Crystal Manola Countess Cherhill Sylvan Lake Skiff Other Total

Gross Acres

Net Acres

68,888 27,719 18,721 18,880 17,529 14,400 12,960 12,518 9,901 3,840 34,606 239,962

56,480 21,096 18,475 17,912 13,139 11,167 10,240 7,014 5,767 2,688 2,629 166,608

Average WI % 82 76 99 95 75 78 79 56 58 70 8 69

LIQUIDITY AND CAPITAL RESOURCES Corporate working capital liquidity is maintained by drawing from the unutilized credit facility as needed and then repaying it periodically through production revenues. When new reserves are added and as the financing needs of the Company are expanded, Journey may apply for interim reviews of the credit facility with a view to upgrading it. The capital expenditures in the respective periods were funded as follows:

Capital Program Funding Cash flow from operations Transaction costs Decommissioning costs incurred Change in non-cash working capital Increase (decrease) in outstanding bank debt and indebtedness Deferred financing charge Normal course issuer bid Option/warrant exercises Issuance of flow though shares Issuance of share capital Dividends Recovery of share issue costs Net cash capital expenditures

Three months ended December 31, % 2015 2014 Change 9,527 24,557 (61) 9 (100) (400) (625) (36) 1,068 (9,204) 112

Twelve months ended December 31, % 2015 2014 Change 49,542 93,601 (47) (1,768) (100) (1,260) (1,649) (24) 1,451 2,376 (39)

(674)

6,019

(111)

7,200

10,796

(33)

(56) (127) (784) 8,554

662 (3,716) 17,702

(100) (79) (52)

(69) (2,260) (6,465) (40) 48,099

2,013 10,000 156,956 (11,468) 260,857

(100) (100) (100) (44) (82)

Page 18

For the three and twelve months ended December 31, 2015, the Company funded its net cash capital expenditures primarily from cash flow from operations, increase in debt and changes in non-cash working capital. As at December 31, 2015, Journey had a $140,000 (2014 - $205,000) credit facility with a syndicate of banks. This facility is comprised of a production facility of $125,000 and a working capital facility of $15,000. The production and working capital facilities are available on a revolving basis for a period of at least 365 days until April 30, 2016 which is the next annual review and renewal date. Following this date and without any renewal, the facilities will be available on a non-revolving basis for a one-year term, with a bullet payment of all outstanding amounts by the term maturity date of April 30, 2017. Available borrowings on the bank credit facility are limited by the borrowing base, which is established by the bank. The amount of available credit is based primarily upon the value of petroleum and natural gas assets. The most recent formal evaluation by our external engineers determined these reserve values as at December 31, 2015. The credit facility is subject to a semi-annual borrowing base review each April and October. As at December 31, 2015, the drawn amount on its credit facility was $90.6 million. The bank line is currently under review by the banking syndicate. Given that commodity prices continued to fall from the last review in November, there is a possibility that the facility could be reduced from the current level. Corporate working capital liquidity is maintained by drawing from the unutilized facility as needed and then repaying it periodically through production revenues. As new reserves are added and as the financing needs of the Company are expanded, Journey may apply for interim reviews of the credit facility with a view to upgrading it. The reduction in commodity prices and the expectation of reduced cash flows have caused the Company to reassess its capital expenditure program. The Company will continue to fund its future capital programs through cash flows from operations. Journey’s working capital deficiency, included in its net debt, is managed by keeping the net debt position well below the amount available from its credit facility. Net debt at December 31, 2015 was $106,746 or $33,254 below the credit facility available of $140,000.

RELATED PARTY TRANSACTIONS Journey had entered into the following related party transactions during the twelve months ended December 31, 2015: Pursuant to an administration agreement between Gas Lite Energy Inc. (“Gas Lite”) and Journey, the Company charges a fee for managing the assets of Gas Lite. Journey and Gas Lite are each controlled by the same shareholder. For the year ended December 31, 2015, the fee charged by Journey was $350 (2014 - $196). In addition, and as operator for the majority of Gas Lite’s wells and facilities, Journey charges overhead recoveries pursuant to standard joint operating agreements. For the year ended December 31, 2015 the overhead recoveries were $653 (2014 - $1,428). As at December 31, 2015 Journey had an outstanding receivable from Gas Lite of $877 (2014 - Nil), all of which is considered by management to be collectible. The related party transactions above were recorded at the above disclosed exchange amounts and gave Journey the ability to reduce its G&A costs.

CONTRACTUAL OBLIGATIONS In addition to the commitments listed below, the Company has various indemnifications in place in the ordinary course of business, none of which, as assessed by management, are expected to have a significant impact on the Company’s audited consolidated financial statements.

Page 19

(a) Transportation and office lease costs The Company has committed to firm-service contracts for the transportation of a proportion of its natural gas. In addition, the Company has committed to future minimum payments under an operating lease that covers the rental of office space and a proportionate share of operating costs. The amounts in the table below are the minimum cash obligations that the Company must pay under the terms of the contracts: Total Natural gas transportation Operating leases Total

$ $

1,862 15,183 17,045

2016 $ $

800 2,045 2,845

2017-2018 $ $

824 3,755 4,579

2019-2020 $ $

210 3,748 3,958

Thereafter $ $

28 5,635 5,663

(b) Indemnifications Under the terms of certain agreements and the Company’s by-laws, Journey indemnifies individuals who have acted at the Company’s request to be a director and/or officer, to the extent permitted by law, against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individual as a result of their service. The Company currently has no outstanding claims having a potentially material adverse effect on the Company as a whole.

OFF BALANCE SHEET FINANCINGS There were no off balance sheet financings during the period.

NORMAL COURSE ISSUER BID Pursuant to the Normal Course Issuer Bid (“NCIB”), the Company repurchased 68 shares (2014 – Nil) in the fourth quarter and for the twelve months ended December 31, 2015 the Company repurchased 1,335 shares (2014 – nil).

(000’s) Third quarter, 2015 Fourth quarter, 2015 Total

Number of shares 1,267 68 1,335

Cash Expenditure (2,133) (127) (2,260)

Average Cost per Share 1.68 1.86 1.69

SHARE CAPITAL The following table provides a summary of the outstanding common shares and other equity instruments as at:

(000’s) Common shares outstanding Restricted voting shares outstanding Total shares outstanding Options, warrants, restricted share units and performance share units Fully diluted shares Weighted average common shares Basic

March 14, 2016 29,088 14,527 43,615 6,085 49,700

December 31, 2015 29,088 14,527 43,615 6,066

December 31, 2014 32,790 10,514 43,304 4,827

49,681

48,131

43,715

35,261 Page 20

(000’s) Diluted

March 14, 2016

December 31, 2015 45,121

December 31, 2014 36,508

SELECTED QUARTERLY INFORMATION Below is summarized quarterly information for the previous eight quarters.

Production (BOE/d) Average prices realized ($/BOE) Petroleum and natural gas sales Net income (loss) Basic – per share ($/share) Diluted – per share ($/share) Cash flow from operations Basic – per share ($/share) Diluted – per share ($/share) Total assets Net cash capital expenditures Long term financial liabilities Net debt Dividends paid

Dec 31, 2015 9,593 28.33 25,008 38,586 0.89 0.86 9,527 0.22 0.21 452,116 8,555 106,534 784

Sept 30, 2015 9,786 31.78 28,616 (153,397) (3.49) (3.49) 8,612 0.20 0.19 422,357 14,460 107,921 1,047

Jun 30, 2015 10,609 36.59 35,329 6,846 0.16 0.15 14,040 0.32 0.32 562,616 4,803 97,849 1,650

Mar 31, 2015 11,273 30.51 30,954 (3,372) (0.08) (0.08) 17,363 0.40 0.39 589,938 20,282 104,714 2,984

Production (BOE/d) Average prices realized ($/BOE) Petroleum and natural gas sales Net income (loss) Basic – per share ($/share) Diluted – per share ($/share) Cash flow from operations Basic – per share ($/share Diluted – per share ($/share) Total assets Net cash capital expenditures Long term financial liabilities Net debt Dividends paid

Dec 31, 2014 11,773 44.56 48,264 (105,316) (2.44) (2.44) 24,557 0.57 0.56 563,588 17,702 100,575 7,824

Sep 30, 2014 11,002 59.06 57,806 12,734 0.30 0.29 26,367 0.61 0.59 658,107 32,668 100,635 7,752

Jun 30, 2014 11,151 62.52 61,803 3,480 0.12 0.12 20,096 0.79 0.75 641,796 14,088 86,888

Mar 31, 2014 7,400 64.10 41,636 (1,119) (0.03) (0.03) 20,582 0.37 0.29 653,805 196,399 43,059 261,666 -

-

Petroleum and natural gas sales are impacted by production levels and commodity pricing. Production levels are impacted by decline rates and the Company’s capital program. Commodity prices are affected by both domestic and international factors that are beyond the Company’s control. In addition, royalties are affected by the underlying commodity pricing and changes in production levels. Significant factors and trends that have affected the Company’s results during the above periods are outlined below:

Page 21



In the fourth quarter of 2015, production volumes decreased by 2% or 193 BOE per day to 9,593 BOE per day from 9,786 BOE per day the third quarter. During the quarter, average realized commodity prices decreased by $3.45 per BOE or 11%. Combined, this resulted in a decrease to P&NG sales of 13% or $3,609 from the previous quarter. Operating netback per BOE was 18% higher than Q3, due to a combined 26% decrease in operating costs and royalties more than offsetting reduced P&NG sales. As a result, cash flow netback per BOE was 8% higher over the previous quarter. There were five (3.1 net) wells drilled during the fourth quarter as compared to five (4.4 net) wells in the third quarter.



In the third quarter of 2015, production volumes decreased by 9% or 823 BOE per day from the second quarter of 2015. Average realized commodity prices decreased by $4.81 per BOE resulting in a 20% decrease to P&NG sales of $6,712 from the previous quarter. Operating netback per BOE was 32% lower than Q2, primarily due to decreased realized commodity prices. This resulted in a 34% lower cash flow netback per BOE from the previous quarter. There were five (4.4 net) wells drilled during the third quarter as compared to no new wells in the second quarter. During the quarter, pursuant to the Normal Course Issuer Bid, 1,267 common shares of the Company were purchased and retired for a total cash consideration of $2,133.



In the second quarter of 2015, production volumes decreased by 6% or 664 BOE per day from the first quarter of 2015. Average realized commodity prices increased by $6.08 per BOE resulting in a 14% increase to P&NG sales of $4,374 over the previous quarter. Operating netback per BOE was 59% higher than Q1, primarily due to increased realized commodity prices. However, the cash flow netback per BOE in the quarter was 15% lower than the first quarter, due to a significant reduction of realized hedging gains. There were no new wells drilled in the quarter as compared to 6 (5.7 net) in the previous quarter.



In the first quarter of 2015, production volumes decreased by 500 BOE per day over the fourth quarter of 2014, with average commodity prices decreasing significantly by $14.05 per BOE. P&NG sales decreased 36% from the previous quarter. Operating netback per BOE was 54% lower than Q4, 2014 primarily due to reduced commodity prices. However, the cash flow netback per BOE in the quarter was 24% lower than the fourth quarter, 214 as a result of realized hedging gains. Six (5.7 net) wells were drilled in the quarter with a 100% success rate as compared to 4 (2.8 net) in the previous quarter.



In the fourth quarter of 2014, production volumes increased by 771 BOE per day over the fourth quarter, however average commodity prices decreased significantly by $14.56 per BOE. For the quarter, overall P&NG sales decreased 19%. Operating netback per BOE was 36% lower than Q3 primarily due to reduced P&NG sales. However, cash flow netback per BOE in the quarter was only 20% lower than Q3 as a result of realized hedging gains. Four (2.8 net) wells were drilled in the quarter with an 82% (net) success rate as compared to 8 (4.1 net) in Q3.



In the fourth quarter of 2014, production volumes decreased marginally from the second quarter and average commodity prices decreased as well. For the quarter, overall P&NG sales decreased 6%. Operating netback per BOE was only 2% lower than Q2 due to reduced operating costs and royalties. However, cash flow netback per BOE in the quarter was 20% higher than Q2 as a result of reductions in G&A expenses, finance expenses and realized hedging losses. Twelve (9.6 net) wells were drilled in the quarter with a 100% success rate as compared to 7 (6.0 net) in Q2.



Production volumes and commodity prices for all products increased during the second quarter of 2014 reflecting a full quarter effect of the Q1 acquisition. While average realized prices decreased slightly, overall P&NG sales were up 49% for the quarter. Operating netback per BOE was 22% lower than Q1 due to increased operating costs and royalties associated with the new assets. Cash flow netback per BOE in the quarter was 55% lower than Q1 as a result of increased finance expenses and realized hedging losses. Eight (7 net) well were drilled in the quarter with a 100% success rate.

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Production volumes and commodity prices for all products increased during the first quarter of 2014. The production volume increase was due to drilling and partial period results of the first quarter acquisition. Eight gross (4.4 net) wells were drilled during the quarter with a 100% success rate.

SELECTED ANNUAL INFORMATION

Petroleum and natural gas sales Net income (loss) Basic – per share ($/share) Diluted – per share ($/share) Total assets Total non-current liabilities Dividends paid

December 31, 2015 119,907 (111,337) (2.55) (2.55) 452,116 255,905 6,465

December 31, 2014 209,509 (90,221) (2.56) (2.56) 563,588 238,789 11,468

December 31, 2013 98,814 4,326 0.17 0.15 370,935 127,164 -

Journey’s aggregate P&NG sales were 43% lower in 2015 compared to 2014 resulting from a 43% decrease in aggregated prices per BOE with a constant level of aggregated BOE production. Net income decreased by $94,547 from 2013 to 2014 primarily as a result of the increase in aggregate revenues being far outweighed by a large noncash impairment of $152,507. Net loss in 2015 increased primarily due to a $142 million net impairment to oil and gas assets. During 2014, the basic shares increased primarily as a result of 14,000 shares issued through public offering, 759 issued as flow-through shares and 2,051 through the exercise of options, warrants and RSUs. Total shares outstanding increased by less than 1% in 2015 with loss per share increasing due to the increased net loss. The decrease in the total assets in 2015 was primarily due to the impairment recorded for the year. The change in total non-current liabilities during 2015 was due to increased decommissioning liabilities and bank debt. Total non-current liabilities in 2013 reflected lower bank debt and much smaller decommissioning liabilities.

SUBSEQUENT EVENTS On March 8, 2016, Journey entered into a commodity swap for 1,000 bbl/d of oil for the calendar year 2017 at a price of $60.00 CAD per barrel.

CRITICAL ACCOUNTING ESTIMATES The consolidated financial statements for the three and twelve months ended December 31, 2015 have been prepared using the same accounting policies and methods as those used in the Company’s audited consolidated financial statements for the year ended December 31, 2014. A summary of the significant accounting policies used by Journey can be found in Note 3 of the December 31, 2015 audited consolidated financial statements. Note 4 of the Company’s audited consolidated financial statements for the year ended December 31, 2015 discloses the areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the Company’s financial statements. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material. Estimates and judgments are continuously evaluated and are based on

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management’s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can materially differ from these estimates. In the process of applying the Company’s accounting policies, management has made the following judgments, estimates, and assumptions which have the most significant effect on the amounts recognized in the financial statements: Accounts receivable Accounts receivable are recorded at the estimated recoverable amount which involves an estimate of uncollectible amounts. The Company regularly assesses the counter party’s financial strength and provides an estimate of uncollectable amounts based on several factors which include aging, the party’s credit worthiness and the nature of the receivable. The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner. Substantially all of the accounts receivable are with its marketers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these parties and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by entering into transactions with long-standing, reputable, counterparties and partners. In many cases, the Company has offsetting receivables and payables with its joint venture partners and makes use of these offsets to mitigate any payment risk. Wherever possible and practical, the Company requires cash calls from its partners on capital projects before they commence. Receivables related to the sale of the Company’s petroleum and natural gas production are mainly from major marketing companies who have excellent credit ratings. These revenues are normally collected on the 25th day of the month following delivery. Derivatives The fair value of derivative contracts are based on published market prices as at the balance sheet date and may differ from what will eventually be realized. During the period of the contracts, changes in the fair value of the derivative contracts are recognized in statement of comprehensive income (loss). The actual gains and losses realized on eventual cash settlement can vary due to subsequent fluctuations in commodity prices which are determined by supply and demand factors including: weather and general economic conditions in places that Journey does not operate and therefore are largely outside of Journey’s control. The counter-parties with which the Company maintains its risk management contracts are major Canadian chartered banks having investment grade rating. Commodity price volatility from period to period can have a dramatic effect on the recorded realized and unrealized gains and comprehensive income or loss for any reporting period. Oil and gas reserves Oil and gas development and production properties are depreciated on a unit of production basis at a rate calculated by reference to proved and probable reserves determined in accordance with the National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and incorporating the estimated future cost of developing and extracting those reserves. Commercial reserves are determined using estimates of oil and natural gas in place, recovery factors and future prices. Future development costs are estimated using assumptions as to the number Page 24

of wells required to produce the commercial reserves, the cost of such wells and associated production facilities, and other capital costs. There are numerous uncertainties inherent in estimating oil and gas reserves. The key estimates used in the determination of cash flows from oil and natural gas reserves include the following: i) Reserves – Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated. ii) Oil and natural gas prices – Forward price estimates are used in the cash flow models. Commodity prices can fluctuate for a variety of reasons including supply and demand fundamentals, inventory levels, exchange rates, weather, and economic and geopolitical factors. iii) Discount rate – The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital. Changes in the general economic environment could result in significant changes to this estimate. Estimating reserves is very complex, requiring many judgments based on geological, geophysical, engineering and economic data. These estimates may change, having either a positive or negative impact on net earnings as further information becomes available and as the economic environment changes. Purchase price allocations and calculations of depletion and depreciation, impairment and deferred income tax assets are based on estimates of oil and gas reserves. Reserves estimates are based on engineering data, estimated future prices, expected future rates of production and timing of future capital expenditures. By their nature, these estimates are subject to measurement uncertainties and interpretations and the impact on the financial statements could be material. The Company expects that over time, its reserves estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels and may be affected by changes in commodity prices. Depletion and depreciation Depletion of oil and gas properties is provided using the unit-of-production method and is based on production volumes (before royalties) in relation to total estimated proved and probable reserves as determined by internal reserve evaluations for the first three quarters of the year and then at year-end by the Company’s independent engineers. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil. Calculations for depletion of oil and gas properties including production equipment and facilities are based on total capitalized costs plus estimated future development costs of proved and probable reserves less the estimated salvage value of production equipment and facilities after the reserves are fully produced. Exploration and evaluation costs are excluded from depletion calculations. The calculation of the unit-of-production rate of amortization could be impacted to the extent that actual production in the future is different from current forecast production. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves. These factors could include:  Changes in proved and probable reserves.  Changes in estimates of future development costs.  The effect on proved and probable reserves of differences between actual production as compared to forecasts as well as commodity price assumptions.  Unforeseen operational issues.

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Exploration and evaluation (“E&E”) assets The decision to transfer assets from E&E to property, plant and equipment is based on the estimated proved and probable reserves which are in part used to determine a project’s technical feasibility and commercial viability. Upon determination of economic recoverable reserves, the assets transferred include certain and determinable recorded costs drilling costs and apportionment of certain costs accumulated by property such as exploration licenses, leasehold acquisitions, seismic and evaluation costs that would be associated with the reserves. Such determination is not typically subject to trending. Impairment The recoverable amounts of Cash Generating Units (“CGU”), as defined below, and individual assets have been determined based on the higher of value-in-use calculations and fair values less costs of disposal. These calculations require the use of estimates and assumptions including information on future commodity prices, expected production volumes, quantity of reserves, discount rates, as well as future development and operating costs. Key assumptions in the determination of cash flows from reserves include reserves as estimated by the Company’s independent qualified reserve evaluators. It is possible that oil and gas price assumptions may change which may then impact the estimated life of fields and may then require a material adjustment to the carrying value of E&E assets and property, plant and equipment. The Company monitors internal and external indicators of impairment relating to its tangible and intangible assets. The Company’s significant accounting policies are disclosed in note 3 to the audited consolidated financial statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results than reported. The Company’s management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results that differ materially from current estimates. CGU definition The determination of CGU’s requires judgment in defining the smallest identifiable group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGU’s are determined by similar geological structure, shared infrastructure, geographical proximity, commodity type, similar exposure to market risk and materiality. The asset composition of a CGU can directly impact the recoverability of the assets included therein. Recoverable amounts of CGUs The recoverable amount of a CGU used in the assessment of impairment is the greater of its value-in-use (“VIU”) and its fair value less costs of disposal (“FVLCOD”). VIU is determined by estimating the present value of the future net cash flows from the continued use of the CGU, and is subject to the risks associated with estimating the value of reserves. FVLCOD refers to the amount obtainable from the sale of a CGU in an arm’s length transaction between knowledgeable, willing parties, less costs of disposal. Both VIU and FVLCOD estimates include the estimated reserves values in their determination. The key assumptions and estimates of the value of oil and gas reserves and the existing and potential markets for the Company’s oil and gas assets are made at the time of reserves estimation and market assessment and are subject to change as new information becomes available. Changes in international and regional factors, including supply and demand of commodities, inventory levels, drilling activity, currency exchange rates, weather, geopolitical and general economic environment factors, may result in significant changes to the estimated recoverable amounts of CGUs.

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Decommissioning costs Decommissioning costs will be incurred by the Company at the end of the operating life of certain facilities and properties. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors including changes to relevant regulatory requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing and amount of expenditure can also change, for example in response to changes in reserves or changes in laws and regulations or their interpretation. In addition, the Company determines the appropriate discount rate at the end of each reporting period. The Company uses the risk-free discount rate to determine the present value of the estimated future cash outflows to settle the obligation and may change in response to numerous market factors. As a result, there could be significant adjustments to the provisions established which would affect future financial results. Share based compensation The fair value of both the stock options and performance warrants granted are measured using the Black-Scholes option pricing model. Measurement inputs include the Company’s share price on the measurement date, the exercise price of the option, the expected volatility of the Company’s shares, the expected life of the options, expected dividends and the risk-free rate of return. The Company estimates volatility based on the historical share price in the publicly traded markets. The expected life of the options is based on historical experience and estimates of the holder’s behavior. Dividends are not factored in. Management also makes an estimate of the number of options that will be forfeited and the rate is adjusted to reflect the actual number of options that actually vest. As described in Note 15 of the Company’s December 31, 2015 audited consolidated financial statements, in 2014 a tranche of RSUs was granted to employees that vest over three years from issuance date, half on the second anniversary of issuance and half on the third anniversary of issuance. In 2014 the Company also granted Performance Share Units (“PSUs”) to certain employees that cliff vest on the third anniversary date of issuance. The settlement method is at the discretion of the Company and may be either in cash or shares. Income taxes The Company recognizes the net future tax benefit related to deferred income tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Various assumptions are made in assessing when temporary differences will reverse and this may impact the rate used. Assessing the recoverability of deferred income tax assets requires significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction in which the Company operates. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the net deferred tax assets recorded at the balance sheet date could be materially impacted. The determination of the Company’s income and other tax assets and liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax asset or liability may differ from that estimated and recorded by management. The Company estimates its future income tax rate in calculating its future income tax asset or liability.

CHANGES IN ACCOUNTING POLICIES Future Changes in Accounting Standards On January 13, 2016, the International Accounting Standards Board (IASB) published a new standard, IFRS 16 'Leases'. The new standard brings most leases on-balance sheet for lessees under a single model, eliminating the distinction between operating and finance leases. Lessor accounting however remains largely unchanged and the

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distinction between operating and finance leases is retained. IFRS 16 supersedes IAS 17 'Leases' and related interpretations and is effective for periods beginning on or after 1 January 2019, with earlier adoption permitted if IFRS 15 'Revenue from Contracts with Customers' has also been applied. Journey is currently assessing the impact of IFRS 15 on the Company’s financial statements and the merit of early adoption Effective January 1, 2015 the International Accounting Standards Board (“IASB”) issued amendments to IFRS 7 "Financial Instruments Disclosure" which will require additional disclosures on transition from IAS 39 to IFRS 9 which is required for annual periods beginning on or after January 1, 2018. Journey is currently assessing the impact of IFRS 9 on the Company’s financial statements and the merit of early adoption. Effective January 1, 2016 the International Accounting Standards Board (“IASB”) issued amendments to IFRS 11 "Accounting for Acquisitions of Interests in Joint Operations" which will provide specific guidance on the accounting for the acquisition of an interest in a joint operation that is a business. Journey is currently assessing the potential impact on the Company’s financial statements. Effective for fiscal years beginning on or after January 1, 2018 the International Accounting Standards Board (“IASB”) issued IFRS 15 "Revenue from Contracts with Customers" which will provide specific guidance on how and when an IFRS reporter will recognize revenues. The standard is required to be either adopted retrospectively in full or using a modified approach where prior number remain and the retrospective effect is an adjustment to retained earnings. Journey is currently assessing the potential impact on the Company’s financial statements.

RISK FACTORS AND RISK MANAGEMENT The risks in the oil and gas industry are varied and wide-ranging. The primary risks and how the Company mitigates them are as follows: Commodity Price Risk The Company’s operating results and financial condition are dependent on prices received for the production of natural gas, NGL and oil. Commodity prices have historically been subject to wide fluctuations and have the most material impact on funds flow. These prices are determined by supply and demand factors including: weather and general economic conditions in places that Journey does not operate and therefore are largely outside of Journey’s control. Prices received in Canada also reflect changes in the Canadian/US currency exchange rate. Journey’s strategy to mitigate these risks focuses on the use of puts, swaps, costless collars and fixed price contracts to limit exposure to downturns in commodity prices while allowing, to the maximum extent possible, maximum exposure to commodity price increases. The Company’s hedging activities are conducted pursuant to the Company’s Risk Management policy approved by the Board of Directors. Revenues and the resulting funds flows fluctuate with commodity prices, which are tied directly to the US/Canadian dollar exchange rate. Commodity prices are determined on a global basis and circumstances that occur in various parts of the world are outside of the control of the Company. The Company protects itself from fluctuations in prices by maintaining an appropriate hedging strategy, diversifying its asset mix and strengthening its balance sheet in order to take advantage of low price environments by making strategic acquisitions. Journey enters into commodity price contracts to actively manage the risks associated with price volatility and thereby partially protect funds flows, which are used to fund our capital program. The risk associated with using these derivative contracts include: commodity prices moving materially in favour of the counter-party and the credit risk associated with the collection of settlements from price movements in Journey’s favour. Journey mitigates these risks by entering mainly into collar transactions that give acceptable ranges of prices and furthermore by dealing with its chartered banks as the primary counterparty.

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Foreign Exchange Risk Journey is also exposed to fluctuations in the exchange rate between the Canadian and US dollar. Most commodity prices are based on US dollar benchmarks, which result in our realized prices being influenced by the Canadian/U.S. currency exchange rates. Credit Risk Credit risk arises from the potential loss resulting from a counterparty failing to meet its obligations in accordance with the agreed terms. The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner. Substantially all of the accounts receivable are with its marketers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these parties and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by entering into transactions with long-standing, reputable, counterparties and partners. In many cases, the Company has offsetting receivables and payables with its joint venture partners and makes use of these offsets to mitigate any payment risk. Wherever possible, the Company requires cash calls from its partners on capital projects before they commence. On a regular basis, the Company assesses the potential for bad debts associated with these parties and provides for accordingly. Receivables related to the sale of the Company’s petroleum and natural gas production are mainly from major th marketing companies who have excellent credit ratings. These revenues are normally collected on the 25 day of the month following delivery. The counter-parties with which the Company maintains its risk management contracts are major Canadian chartered banks having investment grade rating. Credit Facility Risk The Company currently has a revolving bank credit facility of $140,000. The facility is a 365 day revolving facility from a syndicate of lenders with a maturity of April 30, 2016. The maturity date may, at the request of the Company and with the consent of the lenders, be extended for a one year term after this date. There is a risk that the facility may not be renewed for the same amount or under the same or similar terms to what currently exists. The credit facilities are secured by a $500,000 fixed and floating charge debenture over the petroleum and natural gas properties and all other assets of Journey. The facilities are subject to a semi-annual review, at which time the lenders may re-determine the borrowing base. Journey is subject only certain customary non-financial covenants in its credit facility agreement. Journey is in compliances with all such covenants as at December 31, 2015 and December 31, 2014. The credit facility contains customary restrictions on the disposition of assets and the granting of security, as well as on the making of distributions if there is a default under the facility. As at December 31, 2015, Journey had a $140,000 (2014 - $205,000) credit facility with a syndicate of banks. This facility was comprised of a production facility of $125,000 and a $15,000 working capital facility. The effective annualized interest rate for the period ended December 31, 2015 was 3.9% (2014 – 5.8%). The Company has risk associated with the credit facility to the extent it is not fully supported by the underlying reserve values. Access to Capital Markets The Company’s business plan includes the making of significant capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As funds flow from operations may not be sufficient to fund its ongoing activities at all times, the Company may require additional Page 29

financing in order to carry out its oil and gas acquisition, exploration and development activities over and above its lending facility. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss out on acquisition opportunities, and reduce or terminate operations. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business financial condition, results of operations and prospects. Should circumstances affect the funds flow from operations in a detrimental way, the Company would respond by increasing debt within the Company’s self-imposed debt guideline and/or reducing capital expenditures. The Company relies on various sources of funding to support its capital expenditure program including:   

Internally generated funds flows; Debt may be utilized to expand capital programs when deemed appropriate; and Additional equity, if available and on terms acceptable to the Company, may be used to expand or support exploration and development programs and fund acquisitions.

Interest Rate Risk Journey is exposed to interest rate fluctuations. Interest rate risk arises from changes in market interest rates that may affect the future funds flows from the Company’s financial assets or liabilities. The Company’s revolving demand loan facility is subject to floating rates and is therefore exposed to fluctuations in the market rates of interest. The maturing Western Canadian Sedimentary Basin Land and producing assets are becoming increasingly scarce and more expensive. The Company mitigates these risks by developing its core areas to gain efficiencies. In addition, the Company participates in several farm-in opportunities wherein its exposure to increasing land prices is minimized. For riskier, exploration projects, the Company will solicit partner participation to limit the downside exposure. Increasing United States Oil and Natural Gas Supply Over the last several years, the advent of multi-stage fracking has unlocked previously uneconomic oil and natural gas supplies that are readily available in the United States. The Marcellus, Haynesville, and Eagle Ford shale gas plays in the Eastern United States and the Bakken in North Dakota have created a supply within the major consuming regions of the United States. This has caused a reduction in demand from Western Canada and this could possibly continue for many years to come. As a result, the Company has shifted capital to oil targets on its existing lands and will continue to do so into the foreseeable future. Operating and finding and development costs are decreasing each year The industry has experienced decreased costs for services in the past year. Demand for all services decreased as companies had to become more efficient in the drilling activities due to low commodity prices and demanded price reductions from all service suppliers. The Company mitigates risks by entering into strategic joint ventures to reduce exposure to high costs and diversify drilling risks. The Company employs experienced and motivated staff to evaluate and generate high quality drilling prospects. In addition the Company seeks to utilize appropriate technology and responsible operating practices in operating its wells. The Company utilizes appropriate safety programs and insurance coverage to guard against potential losses. Concentrating on core areas wherein Journey has high degrees of ownership and operatorship further mitigates increasing operating costs as economies of scale are gained. Journey attempts to minimize finding risk by:    

Focusing its efforts on its core areas wherein its expertise and experiences can be properly leveraged; Generating as many internal projects as possible; Being the operator on the majority of projects; Identifying drilling opportunities with multi-zone prospects; and

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Making prudent use of seismic data to identify prospects – either by purchasing trade data or by shooting new seismic.

Administrative Risks The increased transparency required by the securities regulators and constantly evolving accounting guidelines dictate significant resources be devoted to these areas. Journey maintains processes designed to comply with the required disclosures; has a strong Board of Directors and engages technical advisors to assist in meeting securities guidelines. In addition, the industry will continue to experience competitiveness with respect to finding and retaining qualified employees. Retention issues are at least partially mitigated by having all employees participate in its LTI program and paying competitive salaries. Competition The petroleum industry is competitive in all its phases. The Company competes with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. The Company's competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Company. The Company's ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage. Competition may also be presented by alternate fuel sources. Environmental Regulations All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it will be in material compliance with current applicable environmental regulations, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Regulatory Risk There can be no assurance that government regulations including: royalties, income taxes, environmental laws and other regulatory requirements will not be changed in a manner which would adversely affect the Company or its shareholders. While Journey has no control over these regulatory risks, it monitors these changes by participating in industry organizations and wherever possible offering assistance in lobbying for any proposed changes which will benefit all stakeholders. The Alberta government has recently announced changes to its royalty structure framework effective January 1, 2017. In general, the changes appear not to be financially onerous but the Company will continue to monitor and assess as the details become known. The AER has made changes to its LLR program whereby operators are rated with respect the value of their assets versus the estimated abandonment and reclamation obligation. Operators with a rating of less than one-to-one, are required to post deposits with the AER. Journey’s rating is well above this limit and does not expect to post any such deposits in the foreseeable future.

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DISCLOSURE CONTROLS AND PROCEDURES The Company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company’s CEO and CFO by others, particularly during the period in which the annual and interim filings or other reports are being prepared , and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company’s disclosure controls and procedures at the financial year end of the Company and have concluded that the Company’s disclosure controls and procedures are effective at the financial year end of the Company for the foregoing purposes. INTERNAL CONTROLS OVER FINANCIAL REPORTING Journey is required to comply with National Instrument 52-109 Certification of Disclosure on Issuers' Annual and Interim Filings (“NI 52-109”). NI 52-109 requires that Journey disclose in its interim MD&A any material weaknesses in Journey’s internal control over financial and/or any changes in Journey’s internal control over financial reporting that occurred during the period that have materially affected, or are reasonably likely to materially affect Journey’s internal controls over financial reporting. Journey confirms that no material weaknesses or such changes were identified in Journey’s internal controls over financial reporting during the fourth quarter of 2015 and for the year ended December 31, 2015, Journey confirms the effectiveness of Internal Controls over Financial Reporting (ICFR) and Disclosure Controls and Procedures (DCP). It should be noted that a control system. Including the Company’s disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

The December 31, 2015 audited consolidated financial statements are available on SEDAR at www.sedar.com as well as the Company’s website at www.journeyenergy.ca.

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